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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

 Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2012

or

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number 001-31539

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction

of incorporation or organization)

41-0518430

(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 1200, Denver, Colorado

(Address of principal executive offices)

80203

(Zip Code)

(303) 861-8140

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class Name of each exchange on which registered

Common stock, $.01 par value New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12

months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and

posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to

submit and post such files). Yes Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to

the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large

accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No 

The aggregate market value of the 64,586,179 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant's common stock on

June 29, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, of $49.11 per share, as reported on the New York Stock Exchange; was

$3,171,827,251. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or

who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for

other purposes.

As of February 14, 2013, the registrant had 66,205,901 shares of common stock outstanding, which is net of 50,581 treasury shares held by the registrant.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its

2013 annual meeting of stockholders to be filed within 120 days after December 31, 2012.

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TABLE OF CONTENTS

ITEM PAGE

PART I

ITEMS 1. and 2. BUSINESS and PROPERTIES 4

General 4

Strategy 4

Significant Developments in 2012 4

Outlook for 2013 5

Core Operational Areas 6

Reserves 8

Production 12

Productive Wells 13

Drilling Activity 13

Acreage 14

Delivery Commitments 15

Major Customers 15

Employees and Office Space 15

Title to Properties 15

Seasonality 15

Competition 16

Government Regulations 16

Cautionary Information about Forward-Looking Statements 20

Available Information 22

Glossary of Oil and Gas Terms 23

ITEM 1A. RISK FACTORS 28

ITEM 1B. UNRESOLVED STAFF COMMENTS 49

ITEM 3. LEGAL PROCEEDINGS 49

ITEM 4. MINE SAFETY DISCLOSURES 50

PART II 51

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY,

RELATED STOCKHOLDER MATTERS AND ISSUER

PURCHASES OF EQUITY SECURITIES 51

ITEM 6. SELECTED FINANCIAL DATA 53

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS 55

Overview of the Company 55

Financial Results of Operations and Additional Comparative Data 63

Comparison of Financial Results and Trends between 2012 and 2011 67

Comparison of Financial Results between 2011 and 2010 70

Overview of Liquidity and Capital Resources 73

Critical Accounting Policies and Estimates 83

Accounting Matters 86

Environmental 86

Non-GAAP Financial Measures 87

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TABLE OF CONTENTS

(Continued)

ITEM PAGE

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT

MARKET RISK (included within the content of ITEM 7) 88

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 89

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE 141

ITEM 9A. CONTROLS AND PROCEDURES 141

ITEM 9B. OTHER INFORMATION 144

PART III 144

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE

GOVERNANCE 144

ITEM 11. EXECUTIVE COMPENSATION 147

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL

OWNERS AND MANAGEMENT AND RELATED

STOCKHOLDER MATTERS 147

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,

AND DIRECTOR INDEPENDENCE 149

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 149

PART IV 150

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 150

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PART I

When we use the terms “SM Energy,” “the Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries

unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil

and Gas Terms. Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the Cautionary

Information about Forward-Looking Statements section of this document for an explanation of these types of statements.

ITEMS 1. and 2. BUSINESS and PROPERTIES

General

We are an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and

natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout the document) in onshore North America, with a current

focus on oil and liquids-rich resource plays. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common

stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”

Our principal offices are located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-

8140.

Strategy

Our business strategy is to focus on the early capture of resource plays in order to create and then enhance value for our shareholders, while

maintaining a strong balance sheet. We strive to leverage industry-leading acquisition, exploration, and operations teams to quickly acquire and test

new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential

through top-tier operational and project execution, and as appropriate, mitigate our risks by selectively divesting certain assets. We continually

examine our portfolio for opportunities to improve the quality of our asset base in order to optimize our returns and preserve our financial strength.

Significant Developments in 2012

• Resource Play Delineation and Development Results in Record Production and Increase in Year-End Proved Reserve

Estimates. Our estimated proved reserves increased 40 percent to 1,760.6 BCFE (293.4 MMBOE) at December 31, 2012, from

1,259.2 BCFE (209.9 MMBOE) at December 31, 2011. We added 900.2 BCFE through drilling activity during the year, which was

primarily led by our efforts in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We achieved

record levels of production in 2012. Our average daily production was composed of 28.3 MBbl of oil, 328.0 MMcf of gas, and 16.7

MBbl of NGLs for an average equivalent production rate of 598.2 MMCFE per day, which was an increase of 29 percent from 465.0

MMCFE per day in 2011. Costs incurred in 2012 for drilling and exploration activities and acquisitions increased nine percent, to $1.7

billion, compared with $1.6 billion in 2011 due mainly to increased activity in plays with significant oil and NGL-rich gas components,

such as our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Core Operational Areas below for additional

discussion concerning our 2012 estimated proved reserves, production, and capital investment.

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• Impairments. We recorded impairment of proved properties expense of $208.9 million for the year ended December 31, 2012. During

the fourth quarter of 2012, we recorded proved property impairment expense of $170.4 million. This non-cash charge was driven by

downward engineering revisions that resulted in the write-down of Wolfberry assets in our Permian region. We also recorded proved

property impairment expense of $38.5 million in the second quarter of 2012 related to our Haynesville shale assets in our Mid-Continent

region due to low natural gas prices.

• Volatility and Decline in Commodity Prices. Our financial condition and the results of our operations are significantly affected by

the prices we receive for oil, natural gas, and NGLs, which can fluctuate dramatically. Oil prices were volatile throughout 2012,

reaching their peak for the year in February when the spot price for NYMEX crude oil hit a high of $109.49 per Bbl. The spot price for

NYMEX crude oil during 2012 was at its lowest of $77.69 per Bbl in June. The average spot price for oil during 2012 was $94.10 per

Bbl, down slightly from the $95.05 per Bbl average NYMEX price in 2011. In 2012, oil prices were impacted by concerns over

international supply disruptions, rising U.S. oil production, and changes in global economic growth expectations throughout the year.

Natural gas prices were also volatile in 2012. The spot price for natural gas at Henry Hub in Erath, Louisiana, a widely-used industry

measuring point, averaged $2.75 per MMBtu in 2012, down from an average price of $4.00 per MMBtu in 2011. The 2012 average

price was the lowest average annual price at Henry Hub since 1999. The high at Henry Hub for 2012 of $3.77 per MMBtu was

recorded in November, and the low of $1.84 per MMBtu was reached in April. Natural gas prices were under downward pressure in

2012 as a result of sustained high natural gas inventories and rising natural gas production in the Marcellus and Eagle Ford basins.

Natural gas prices rose throughout the remainder of the year after reaching their low in April.

NGL prices decreased throughout 2012 largely due to a growing supply of NGLs as increased numbers of industry participants targeted

projects producing NGLs. The average spot price for NGLs in 2012 at Mont Belvieu was $44.91 per Bbl, which was down from

$59.47 per Bbl in 2011. Please refer to Overview of the Company and Oil, Gas, and NGL Prices included in Part II, Item 7 of this

report for additional information regarding our NGL prices.

Outlook for 2013

We enter 2013 with a projected $1.5 billion capital program, approximately $1.2 billion of which we expect to allocate to drilling and

completion activities. Our 2013 capital program allocates all drilling and completion capital to oil and liquids-rich programs. Please refer to Core

Operational Areas below and Outlook for 2013 under Part II, Item 7 of this report for additional discussion surrounding our capital plans for

2013.

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Core Operational Areas

Our operations are concentrated in four core operating areas in the onshore United States. Effective January 1, 2012, we combined our

former ArkLaTex region with our Mid-Continent region, based in Tulsa, Oklahoma, for operational and reporting purposes. The following table

summarizes estimated proved reserves, PV-10 reserve value, and production for the year ended December 31, 2012, for our core operating areas:

South Texas &

Gulf Coast

Rocky

Mountain

MidContinent Permian Total (1)

Proved Reserves

Oil (MMBbl) 30.9 49.2 0.9 11.2 92.2

Gas (Bcf) 530.7 42.7 233.4 26.6 833.4

NGLs (MMBbl) 60.5 — 1.6 0.2 62.3

BCFE (1) 1,079.2 337.9 248.6 94.8 1,760.6

Relative percentage 61% 19% 14% 6% 100%

Proved Developed % 43% 65% 89% 93% 57%

PV-10 Values (in millions) (2)

Proved Developed $ 1,308.7 $ 974.4 $ 295.9 $ 403.6 $ 2,982.6

Proved Undeveloped 591.5 248.5 4.8 21.7 866.5

Total Proved $ 1,900.2 $ 1,222.9 $ 300.7 $ 425.3 $ 3,849.1

Relative percentage 49% 32% 8% 11% 100%

Production

Oil (MMBbl) 3.2 5.4 0.4 1.3 10.4

Gas (Bcf) 59.1 4.4 53.4 3.2 120.0

NGLs (MMBbl) 5.7 — 0.4 — 6.1

BCFE (1) 112.7 36.9 58.1 11.3 218.9

Avg. Daily Equivalents

(MMCFE/d) 307.9 100.9 158.6 30.8 598.2

Relative percentage 51% 17% 27% 5% 100%

(1) Totals may not sum or recalculate due to rounding.

(2) The standardized measure PV-10 calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A

reconciliation between the PV-10 reserve value and the after tax value is shown in the Reserves section below.

South Texas & Gulf Coast Region. Operations in our South Texas & Gulf Coast region are managed from our office in Houston,

Texas. Our current operations in this region focus primarily on our Eagle Ford shale program. Our acreage position covers a significant portion of the

western Eagle Ford shale play, including acreage in the oil, NGL-rich gas, and dry gas windows of the play. As of December 31, 2012, we had

roughly 191,500 net acres in the play. We operate approximately 145,000 of the 191,500 net acres, with an average working interest of nearly 100

percent.

Nearly all of our capital deployed in the South Texas & Gulf Coast region in 2012 targeted our operated Eagle Ford shale program.

Production in 2012 increased 62 percent from the 69.7 BCFE produced in 2011. Estimated proved reserves at year-end 2012 increased 123 percent

from 483.6 BCFE at year-end 2011. Of the 2012 reserve additions in this region, approximately 767.3 BCFE of estimated proved reserves were

added through drilling activities. The increase in production and proved reserves reflects the success we are having in our Eagle Ford shale program

and the resulting consistent pace of investment. Our capital expenditures in our South Texas & Gulf Coast region decreased from $932.3 million in

2011 to $848.4 million in 2012, as a result of being carried for substantially all of our drilling and completion costs in our outside operated Eagle

Ford program pursuant to our Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui &

Co., Ltd. (the “Acquisition and Development Agreement”).

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Rocky Mountain Region. Operations in our Rocky Mountain region are managed from our office in Billings, Montana. Our capital

expenditures in 2012 primarily targeted the Bakken/Three Forks formations in the North Dakota portion of the Williston Basin, where we have

approximately 80,500 net acres. In 2012, we continued to focus our drilling and completion activities in three main areas. In our Raven and Bear Den

prospects, in Williams and McKenzie Counties, North Dakota, we have largely completed our drilling program intended to establish held by

production status and have transitioned our program primarily to infill drilling. Our efforts are focused on optimizing our completions and spacing for

development of the Bakken formation. In our Gooseneck prospect in Divide County, North Dakota, our efforts focused on the Three Forks

formation, where we are also transitioning to infill drilling. As our program moves to infill development, we will continue our transition to multi-well

pad drilling to improve the efficiency of our drilling and completion operations. Elsewhere in our Rocky Mountain region, we are in the exploratory

phase of drilling test wells of various formations in the Powder River Basin. At year-end 2012, we had approximately 65,000 net acres in the Powder

River Basin that we believe to be prospective in various target horizons.

Capital expenditures in our Rocky Mountain region increased from $288.0 million in 2011 to $406.8 million in 2012, as we increased

activity in our Bakken/Three Forks program. Estimated proved reserves for the region at the end of 2012 increased 11 percent from 303.4 BCFE at

year-end 2011. During the year, we added approximately 90.0 BCFE of proved reserves in this region through drilling activities. Total regional

production for 2012 was up 38 percent from the 26.7 BCFE produced in 2011. The increase in capital, production, and proved reserves reflects the

increased activity in our Bakken/Three Forks program.

Mid-Continent Region. Operations in our Mid-Continent region are managed from our office in Tulsa, Oklahoma. Our current operations

in the Mid-Continent region are primarily focused on the horizontal development of the Granite Wash formation in western Oklahoma. Our MidContinent region also manages our Haynesville and Woodford shale assets, on which we minimized activity in 2012 due to the low natural gas price

environment, which resulted in a decrease in our 2012 capital expenditures, production, and year-end reserves, as discussed below. Our 2012 Granite

Wash program targeted the shallower, liquids-rich washes of our approximately 34,000 net acres in the play, substantially all of which are held by

production.

In 2012, we incurred costs of $168.2 million in our Mid-Continent region for exploration, development, and acquisition activities,

compared to $247.0 million incurred in 2011. In 2012, our Mid-Continent region’s production was 58.1 BCFE, a decrease from the 61.8 BCFE

produced in 2011. Estimated proved reserves at the end of 2012 decreased 32 percent from 365.2 BCFE as of the end of 2011.

Permian Region. Operations in our Permian region are managed from our office in Midland, Texas. Our Permian region covers western

Texas and eastern New Mexico. Our primary area of focus in this region is the delineation of our Mississippian limestone play, in which we hold

approximately 65,500 net acres. In addition to this delineation program, we have an exploration program targeting various shale intervals in the

Midland Basin. These programs resulted in an increase in our 2012 capital expenditures, as discussed below.

We incurred costs of $232.5 million in the region for exploration, development, and acquisition activities in 2012 compared to $80.7 million

in 2011. A significant portion of the 2012 costs incurred in this region were for leasing activities and a drilling program that was weighted toward the

last half of the year. The region’s 2012 production was 11.3 BCFE, compared to 2011 production of 11.5 BCFE. The decrease in production was

due to natural decline in our Wolfberry assets as the field matured. Estimated proved reserves at the end of 2012 were 94.8 BCFE, which was a

decrease from 2011 year-end proved reserves of 107.0 BCFE.

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Reserves

The table below presents summary information with respect to the estimates of our proved reserves for each of the years in the three-year

period ended December 31, 2012. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit our internal engineering estimates of at least 80

percent of the PV-10 value of our estimated proved reserves in each year presented. The prices used in the calculation of proved reserve estimates as

of December 31, 2012, were $94.71 per Bbl for oil, $2.76 per MMBtu for natural gas, and $45.65 per Bbl for NGLs.

Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve

estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The PV-10

values shown in the following table are not intended to represent the current market value of our estimated proved reserves. Neither prices nor costs

have been escalated. The actual quantities and present values of our estimated proved reserves may be less than we have estimated. No estimates of our

proved reserves have been filed with or included in reports to any federal authority or agency, other than the Securities and Exchange Commission

(“SEC”), since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – Risks

Related to Our Business contained herein.

Our ability to replace our production is important to our sustainability. Please refer to the reserve replacement terms in the Glossary of Oil

and Gas Terms section of this report for information describing how our reserve replacement metrics are calculated. Our reserve replacement

percentages are calculated using information from the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information

located in Part II, Item 8 of this report.

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We believe the concept of reserve replacement as described in the Glossary of Oil and Gas Terms section of this report, as well as

permutations that may include other captions of the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information

located in Part II, Item 8 of this report, are widely understood by those who make investment decisions related to the oil and gas exploration business.

As of December 31,

2012 2011 2010

Reserve data:

Proved developed

 Oil (MMBbl) 58.8 50.3 46.0

 Gas (Bcf) 483.2 451.2 411.0

 NGLs (MMBbl) 27.2 15.2 —

 BCFE (1) 999.1 844.0 687.3

Proved undeveloped

 Oil (MMBbl) 33.5 21.4 11.4

 Gas (Bcf) 350.2 212.8 229.0

 NGLs (MMBbl) 35.1 12.3 —

 BCFE (1) 761.5 415.2 297.2

Total Proved

 Oil (MMBbl) 92.2 71.7 57.4

 Gas (Bcf) 833.4 664.0 640.0

 NGLs (MMBbl) 62.3 27.5 —

 BCFE (1) 1,760.6 1,259.2 984.5

Proved developed reserves % 57% 67% 70%

Proved undeveloped reserves % 43% 33% 30%

Reserve value data (in millions):

Proved developed PV-10 $ 2,982.6 $ 2,836.3 $ 2,053.5

Proved undeveloped PV-10 866.5 624.9 290.8

Total proved PV-10 $ 3,849.1 $ 3,461.2 $ 2,344.3

Standardized measure of discounted future cash flows $ 3,021.0 $ 2,580.0 $ 1,666.4

Reserve replacement – drilling, excluding revisions 411% 310% 349%

All in – including sales of reserves 329% 262% 293%

All in – excluding sales of reserves 337% 317% 372%

Reserve life (years) 8.0 7.4 8.9

(1) Totals may not sum or recalculate due to rounding.

Note: NGL reserve data for 2010 has not been reclassified to conform to the current presentation given the immateriality of the volumes in 2010. Please refer to

additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this report.

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The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 value (Non-GAAP). The

difference is a result of the PV-10 value measure excluding the impact of income taxes. Please see the definitions of standardized measure of

discounted future net cash flows and PV-10 value in the Glossary of Oil and Gas Terms.

As of December 31,

2012 2011 2010

(in millions)

Standardized measure of discounted future net cash flows $ 3,021.0 $ 2,580.0 $ 1,666.4

Add: 10 percent annual discount, net of income taxes 1,742.1 1,727.6 1,294.6

Add: future undiscounted income taxes 1,609.4 1,740.4 1,335.5

Undiscounted future net cash flows $ 6,372.5 $ 6,048.0 $ 4,296.5

Less: 10 percent annual discount without tax effect (2,523.4) (2,586.8) (1,952.2)

PV-10 value $ 3,849.1 $ 3,461.2 $ 2,344.3

Proved Undeveloped Reserves

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing

wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled

acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable

certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted

indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period. As of December 31,

2012, we had no undrilled proved undeveloped reserves that had been on our books in excess of five years.

During 2012, the Company utilized reliable geologic and engineering technology to add approximately 177.7 BCFE of proved undeveloped

reserves for locations that are more than one location removed from developed locations in the more developed portions of our Eagle Ford shale

position. We incorporated public and proprietary data from multiple sources to establish geologic continuity of the formation and its producing

properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally

collected), and petrophysical analysis of the log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test

production, fluid properties, and core data as well as significant statistical performance data yielding predictable and repeatable reserve estimates

within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical

performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to

immediate offsets to producing wells.

As of December 31, 2012, we had 761.5 BCFE of proved undeveloped reserves, which is an increase of 346.3 BCFE, or 83 percent,

over proved undeveloped reserves of 415.2 BCFE at December 31, 2011. We added 549.7 BCFE of proved undeveloped reserves through our

drilling program, 278.1 BCFE of which were extensions and discoveries, primarily in our Eagle Ford shale play, as well as an additional 271.6

BCFE of infill proved undeveloped reserves that were mostly concentrated in our assets in the Bakken/Three Forks and the Eagle Ford shale plays. A

negative price revision of 29.1 BCFE was primarily due to gas weighted projects in our South Texas & Gulf Coast and Mid-Continent regions that

no longer generated positive cash flow utilizing 12-month average benchmark pricing required by the SEC. Extensive delineation drilling in our Eagle

Ford shale program during 2012 resulted in an increase in statistical data available in the play. This information, combined with extensive data

demonstrating the geologic continuity of the reservoir, allowed us to add 491.2 BCFE of new proved undeveloped reserves in the Eagle Ford shale

play and led to a downward engineering revision of 39.2 BCFE primarily r

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elated to previously booked Eagle Ford shale proved undeveloped locations. We removed 42.7 BCFE of proved undeveloped reserves from our

books, primarily in the Woodford shale, due to low natural gas prices and as a result of the five-year limitation on the number of years that proved

undeveloped reserves may be booked without being developed. During the year, we sold proved undeveloped assets in our Rocky Mountain region,

comprising 3.2 BCFE. During 2012, we converted 89.2 BCFE of proved undeveloped reserves to proved developed reserves, primarily in our Eagle

Ford shale and Bakken/Three Forks plays at a total capital cost of $203.6 million, of which $159.4 million was incurred in 2012. Please refer to

Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for discussion of the carry of 90 percent of certain

of our drilling and completion costs. As of December 31, 2012, estimated future development costs relating to our proved undeveloped reserves are

approximately $660 million, $451 million, and $359 million in 2013, 2014, and 2015, respectively.

Internal Controls Over Reserves Estimates

Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and

values in compliance with the SEC’s regulations. Our process for managing and monitoring the Company’s proved reserves is delegated to our

reservoir engineering group, which is managed by Dennis A. Zubieta, our Vice President - Engineering, Evaluation and A&D, subject to the oversight

of our management and the Audit Committee of our Board of Directors, as discussed below. Mr. Zubieta joined us in June 2000 as a Corporate

Acquisition & Divestiture Engineer, assumed the role of Reservoir Engineer in February 2003, was appointed Reservoir Engineering Manager in

August 2005, was appointed Vice President - Engineering and Evaluation in August 2008, and was appointed Vice President - Engineering,

Evaluation and A&D in October 2012. Mr. Zubieta was employed by Burlington Resources Oil and Gas Company from June 1988 to May 2000 in

various operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of Science degree in Petroleum Engineering from Montana

Tech of The University of Montana in May 1988. Technical reviews are performed throughout the year by regional staff who evaluate geological and

engineering data. This data, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved

reserve quantities. Our regional engineering technical staff do not report directly to Mr. Zubieta; they report to either their respective regional technical

managers or directly to the regional manager. This is intended to promote objective and independent analysis within our regions in the reserves

estimation process.

Third-party Reserves Audit

Ryder Scott performed an independent audit using its own engineering assumptions but with economic and ownership data we provided.

Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10 value. In the aggregate, the proved reserve values of our

audited properties determined by Ryder Scott are required to be within 10 percent of our proved reserve valuations for the total company, as well as

for each respective region. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering

consulting services throughout the world for over seventy years. The technical person at Ryder Scott primarily responsible for overseeing our

reserves audit is a Managing Senior Vice President who received a Bachelor of Science degree in Petroleum Engineering from the University of

Missouri at Rolla in 1970, and who is a registered Professional Engineer in Colorado and Utah. He is also a member of the Society of Petroleum

Engineers. The Ryder Scott 2012 report concerning our reserves is included as Exhibit 99.1.

In addition to a third party audit, our reserves are reviewed by management with the Audit Committee of our Board of Directors.

Management, which includes our Chief Executive Officer, President and Chief Operating Officer, Executive Vice President and Chief Financial

Officer, and Senior Vice President - Portfolio Development and Technical Services, is responsible for reviewing and verifying that the estimate of

proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with

Ryder Scott’s results and also meets with Ryder Scott representatives from time to time to discuss its processes and findings.

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Production

The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties in which we held

an interest during the periods indicated. Realized prices presented below exclude the effects of hedges and derivative contracts. Also presented is a

summary of related production costs per MCFE.

For the Years Ended December 31,

2012 2011 2010

Net production

Oil (MMBbl) 10.4 8.1 6.4

Gas (Bcf) 120.0 100.3 71.9

NGLs (MMBbl) 6.1 3.5 —

BCFE 218.9 169.7 110.0

Eagle Ford net production(1)

Oil (MMBbl) 3.1 2.5 0.8

Gas (Bcf) 58.1 32.9 13.0

NGLs (MMBbl) 5.7 3.1 —

BCFE 110.9 66.6 17.6

Average net daily production

Oil (MBbl per day) 28.3 22.1 17.4

Gas (MMcf per day) 328.0 274.8 196.9

NGLs (MBbl per day) 16.7 9.6 —

MMCFE per day 598.2 465.0 301.4

Eagle Ford average net daily production (1)

Oil (MBbl per day) 8.6 6.8 2.1

Gas (MMcf per day) 158.8 90.1 35.6

NGLs (MBbl per day) 15.5 8.6 —

MMCFE per day 303.1 182.5 48.3

Realized price

Oil (per Bbl) $ 85.45 $ 88.23 $ 72.65

Gas (per Mcf) $ 2.98 $ 4.32 $ 5.21

NGLs (per Bbl) $ 37.61 $ 53.32 $ —

Per MCFE $ 6.73 $ 7.85 $ 7.60

Production costs per MCFE

Lease operating expense $ 0.82 $ 0.88 $ 1.10

Transportation costs $ 0.63 $ 0.51 $ 0.19

Production taxes $ 0.33 $ 0.32 $ 0.48

(1) In each of the years 2012, 2011, and 2010, total estimated proved reserves attributed to our Eagle Ford shale properties exceeded 15 percent of our total

proved reserves expressed on an equivalent basis.

Note: NGL production volumes and prices for 2010 have not been reclassified to conform to the current presentation given the immateriality of the volumes in

2010. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this report.

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Productive Wells

As of December 31, 2012, we had working interests in 1,184 gross (730 net) productive oil wells and 3,018 gross (1,078 net) productive

gas wells. Productive wells are either wells producing in commercial quantities or wells that are mechanically capable of commercial production, but

are currently shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an

oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of the

current production mix.

Drilling Activity

All of our drilling activities are conducted using independent drilling contractors. We do not own any drilling equipment. The following table

summarizes the number of operated and non-operated wells drilled or recompleted on our properties in 2012, 2011, and 2010, excluding nonconsented projects, active injector wells, and any wells in which we own only a royalty interest:

For the Years Ended December 31,

2012 2011 2010

Gross Net Gross Net Gross Net

Development wells:

Oil 127 47.2 125 32.1 191 36.5

Gas 337 124.5 273 81.0 72 17.0

Non-productive 10 6.3 11 4.0 4 1.1

474 178.0 409 117.1 267 54.6

Exploratory wells:

Oil 9 6.9 16 6.3 36 11.5

Gas 8 6.8 48 8.6 83 37.9

Non-productive 8 6.8 3 1.0 1 0.8

25 20.5 67 15.9 120 50.2

Total 499 198.5 476 133.0 387 104.8

A productive well is an exploratory, development, or extension well that is producing oil, gas, and/or NGLs or that is capable of commercial

production of those products. A non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development, or

extension well that proves to be incapable of producing either oil, gas, and/or NGLs in commercial quantities.

As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be

productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of

a stratigraphic horizon known to be productive and is part of a development project, which is defined as the means by which petroleum resources are

brought to economically producible status. The number of wells drilled refers to the number of wells completed at any time during the respective year,

regardless of when drilling was initiated. Completion refers to the installation of equipment for production of oil, gas, and/or NGLs, or in the case of

a dry well, the reporting to the appropriate authority that the well has been plugged and abandoned.

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In addition to the wells drilled and completed in 2012 (included in the table above), as of February 14, 2013, we were participating in the

drilling of 44 gross wells. We operate 25 of these wells on a gross basis (17 on a net basis) and other companies operate the remaining 19 gross

wells (two on a net basis). With respect to completion activity, at such date, there were 234 gross wells in which we have an interest that were being

completed. We operate 45 of these completion activities on a gross basis (40 on a net basis), and were participating in 189 gross (34 net) nonoperated completion activities. Substantially all of these operations relate to the drilling of wells during the primary term of the respective oil and gas

lease or leases.

Acreage

The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral

servitudes held by us as of December 31, 2012. Undeveloped acreage includes leasehold interests that contain proved undeveloped reserves.

Developed Acres (1) Undeveloped Acres (2) Total

Gross Net Gross Net Gross Net

Louisiana 71,750 24,794 39,104 30,989 110,854 55,783

Montana 57,586 39,877 312,758 210,226 370,344 250,103

Nevada — — 197,634 197,634 197,634 197,634

North Dakota 158,489 102,579 105,932 62,115 264,421 164,694

Oklahoma 249,706 82,441 64,642 28,433 314,348 110,874

Pennsylvania 282 282 26,270 22,803 26,552 23,085

Texas 245,699 152,195 570,504 320,510 816,203 472,705

Wyoming 45,261 21,897 267,961 189,825 313,222 211,722

Other (3) 4,430 2,011 42,926 29,937 47,356 31,948

833,203 426,076 1,627,731 1,092,472 2,460,934 1,518,548

Louisiana Fee Properties 10,499 10,499 14,415 14,415 24,914 24,914

Louisiana Mineral Servitudes 7,426 4,217 4,769 4,407 12,195 8,624

17,925 14,716 19,184 18,822 37,109 33,538

Total (4) 851,128 440,792 1,646,915 1,111,294 2,498,043 1,552,086

(1) Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that

includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but has been included only

as developed acreage in the presentation above.

(2) Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of

oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.

(3) Includes interests in Arkansas, Colorado, Kansas, Illinois, Mississippi, Nebraska, New Mexico, and Utah.

(4) As of the filing date of this report, we had approximately 63,368, 79,048, and 162,422 net acres scheduled to expire by December 31, 2013, 2014, and

2015, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases.

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Delivery Commitments

As of December 31, 2012, we had gathering, processing, and transportation through-put commitments with various parties that require us to

deliver fixed, determinable quantities of production over specified time frames. We have an aggregate minimum commitment to deliver 1,515 Bcf of

natural gas and 36 MMBbls of oil. These contracts expire at various dates through 2023. We are required to make periodic deficiency payments for

any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for natural gas is projected, we have

rights under certain contracts to arrange for third party gas to be delivered, and such volume will count toward our minimum volume commitment. Our

current production is insufficient to offset these aggregate contractual liabilities, but we expect to fulfill the delivery commitments with production

from the future development of our proved undeveloped reserves and from the future development of resources not yet characterized as proved

reserves in our Eagle Ford shale and Haynesville shale resource plays. Therefore, we currently do not expect any significant shortfalls.

Major Customers

For the year ended December 31, 2012, we had two major customers, Regency Gas Services LLC and Plains Marketing LP, which

accounted for approximately 21 percent and 13 percent, respectively, of our total revenue. During 2011 and 2010, we had one major customer,

Regency Gas Services LLC, which individually accounted for approximately 18 percent and 11 percent, respectively, of our total revenue.

Employees and Office Space

As of February 14, 2013, we had 725 full-time employees. None of our employees are subject to a collective bargaining agreement, and we

consider our relations with our employees to be good.

As of December 31, 2012, we leased approximately 98,000 square feet of office space in Denver, Colorado for our executive and

administrative offices; approximately 45,000 square feet of office space in Tulsa, Oklahoma; approximately 62,000 square feet in Houston, Texas;

approximately 30,000 square feet in Billings, Montana; approximately 22,000 square feet in Midland, Texas; approximately 7,000 total square feet in

Williston and Watford City, North Dakota; and approximately 2,000 square feet in Casper, Wyoming. As of December 31, 2012, we own field office

facilities containing approximately 12,000 square feet of office space in Catarina, Texas; approximately 3,000 square feet of office space in Belfield,

North Dakota; and approximately 4,000 square feet of office space in Sidney, Montana.

Title to Properties

Substantially all of our interests are held pursuant to oil and gas leases from third parties. A title opinion is usually obtained prior to the

commencement of initial drilling operations. We have obtained title opinions or have conducted other title review on substantially all of our producing

properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry.

Substantially all of our producing properties are subject to mortgages securing indebtedness under our credit facility, royalty and overriding royalty

interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of, or affect the value of, such properties.

We typically perform only minimal title investigation before acquiring undeveloped leasehold acreage.

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To

lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and

forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place

increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although

oil prices are impacted more significantly by global supply and demand. Seasonal

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anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on oil has been somewhat magnified by overall

supply and demand economics attributable to the narrow margin of worldwide production capacity in excess of existing worldwide demand for oil.

Certain of our drilling, completion, and other operations are also subject to seasonal limitations. Seasonal weather conditions and lease stipulations

adversely affect our ability to conduct drilling activities in some of the areas where we operate. See Risk Factors - Risks Related to Our Business

for additional discussion.

Competition

The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe

our leasehold position provides a sound foundation for a solid drilling program and our future growth. Our competitive position also depends on our

geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration,

drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our

management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of

major and independent oil and gas companies, which in some cases have larger technical staffs and greater financial and operational resources than we

do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also

have refining operations, market refined products, own drilling rigs and other equipment, and generate electricity.

We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the

drilling, completion, and maintenance of wells. Consequently, we may face shortages or delays in securing these services from time to time. The oil

and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas.

Competitive conditions may be affected by future new energy, climate-related, financial, and/or other policies, legislation, and regulations.

In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil

and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming

more limited due to the evolving demographics of our industry. We are not insulated from the competition for quality people, and we must compete

effectively in order to be successful.

Government Regulations

Our business is extensively regulated by numerous federal, state, and local laws and governmental regulations. These laws and regulations

may be changed from time to time in response to economic or political conditions, or other developments, and our regulatory burden may increase in

the future. Laws and regulations have the potential of increasing our cost of doing business and, consequently, could affect our profitability.

However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.

Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing the exploration

for and production of oil, gas, and NGLs, including laws and regulations that require permits for the drilling of wells, impose bonding requirements

in order to drill or operate wells, and govern the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and

restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to various state

conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that

may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, state conservation laws sometimes

establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and may impose certain requirements

regarding the ratability or fair apportionment of production from fields and individual wells.

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Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management

(“BLM”). These leases contain relatively standardized terms and require compliance with detailed regulations and orders that are subject to change. In

addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and must comply with

regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of

production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain

circumstances, the BLM may suspend or terminate our operations on federal leases.

In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental

review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to

leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased

the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM.

Our sales of natural gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory

Commission (“FERC”) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce. FERC’s current regulatory

framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations

continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for natural gas

production. In addition, the less stringent regulatory approach currently pursued by FERC and the United States Congress may not continue

indefinitely.

Environmental, Health and Safety Matters

General. Our operations are subject to stringent and complex federal, state, tribal and local laws and regulations governing protection of the

environment and worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other

things:

• require the acquisition of various permits before drilling commences;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and

natural gas drilling and production and saltwater disposal activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing

certain wildlife or threatened and endangered plant and animal species; and

• require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug

abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible.

The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

Additionally, environmental laws and regulations are revised frequently, and any changes that result in more stringent and costly permitting, waste

handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

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The following is a summary of some of the existing laws, rules and regulations to which our business is subject.

Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation,

transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental

Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own,

more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and

production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and

natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such

change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of

operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response,

Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality

of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons

include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance

released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances

that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not

uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the

hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many

years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous

substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations,

including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third

parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control.

These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws,

we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to

prevent future contamination.

Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict

controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states.

The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps

of Engineers or analogous state agencies. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA

applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal

costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other

pollutants from our operations could result in governmental penalties and civil liability.

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Air emissions. The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of various air pollutants through air

emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent

regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and

criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present

an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the

earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of

regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate

change could have an adverse effect on our operations and the demand for oil and gas. See “Risk Factors - Risks Related to Our Business -

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our

operations and the demand for crude oil, natural gas and NGLs .” In addition to the effects of regulation, the meteorological effects of global

climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms

and flooding, and could adversely affect the demand for our products.

Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on

threatened or endangered species. Some of our well drilling operations are conducted in areas where protected species are known to exist. In these

areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from

conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an

adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is

determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we

perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production

from those areas.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National

Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having

the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that

assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental

impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as

proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This

process has the potential to delay development of some of our oil and natural gas projects.

OSHA and other laws and regulation. We are subject to the requirements of the federal Occupational Safety and Health Act

(“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III

of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our

operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace

exposure to hazardous substances and employee health and safety. We believe that we are in substantial compliance with the applicable requirements of

OSHA and comparable laws.

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Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons

from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the

injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is

typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing

involving diesel additives under the Safe Drinking Water Act’s (the “SDWA”) Underground Injection Control Program. The federal SDWA protects

the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids into

below-ground formations that may adversely affect drinking water sources.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using

hydraulic fracturing techniques, which could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and

delays, all of which could adversely affect our financial position, results of operations and cash flows. If new laws or regulations that significantly

restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from

tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by

the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential

increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from

our reserves.

We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While

we believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our

continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we

cannot give any assurance that we will not be adversely affected in the future.

Cautionary Information about Forward-Looking Statements

This Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E

of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities,

events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate

will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words

“anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are

intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this Form 10-K, and include statements

about such matters as:

• the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;

• the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions;

• the possible divestiture or farm-down of, or joint venture relating to, certain properties;

• proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those

proved reserve estimates;

• future oil, gas, and NGL production estimates;

• our outlook on future oil, gas, and NGL prices, well costs, and service costs;

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• cash flows, anticipated liquidity, and the future repayment of debt;

• business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to

defer capital investment, and our outlook on our future financial condition or results of operations; and

• other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and

Results of Operations section in Item 7 of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of

historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These

statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be

materially different from any future results or performance expressed or implied by the forward-looking statements. These risks are described in the

Risk Factors section of this report, and include such factors as:

• the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to

capital, and ability to grow production volumes and/or proved reserves;

• the continued weakness in economic conditions and uncertainty in financial markets;

• our ability to replace reserves in order to sustain production;

• our ability to raise the substantial amount of capital that is required to replace our reserves;

• our ability to compete against competitors that have greater financial, technical, and human resources;

• our ability to attract and retain key personnel;

• the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;

• the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;

• the possibility that exploration and development drilling may not result in commercially producible reserves;

• our limited control over activities on non-operated properties;

• our reliance on the skill and expertise of third-party service providers on our operated properties;

• the possibility that title to properties in which we have an interest may be defective;

• the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and

completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;

• the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain

assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;

• the uncertainties associated with enhanced recovery methods;

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• our commodity derivative contracts may result in financial losses or may limit the prices that we receive for oil, gas, and NGL sales;

• the inability of one or more of our vendors, customers, or contractual counterparties to meet their obligations;

• price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;

• the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our credit facility;

• the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse

economic conditions, and make it more difficult for us to make payments on our debt;

• operating and environmental risks and hazards that could result in substantial losses;

• complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;

• the availability and capacity of gathering, transportation, processing, and/or refining facilities;

• our ability to sell and/or receive market prices for our oil, gas, and NGLs;

• new technologies may cause our current exploration and drilling methods to become obsolete;

• the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities

and systems; and

• litigation, environmental matters, the potential impact of government regulations, and the use of management estimates regarding such

matters.

We caution you that forward-looking statements are not guarantees of future performance and that actual results or performance may be

materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the

filing date of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to

do so except as required by securities laws.

Available Information

Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our

website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current

reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made

available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also make available

through our website’s corporate governance section our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Financial Code of

Ethics, and the Charters of the Audit, Compensation, Executive, and Nominating and Corporate Governance Committees of our Board of Directors.

Information on our website is not incorporated by reference into this report and should not be considered part of this document.

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Glossary of Oil and Gas Terms

The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory

well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under SEC Rule 4-10(a) of Regulation

S-X, as amended effective for fiscal years ending on or after December 31, 2009. The entire definitions of those terms under Rule 4-10(a) of

Regulation S-X can be located through the SEC’s website at www.sec.gov.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. Billion cubic feet, used in reference to natural gas.

BCFE. Billion cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil

or NGLs.

BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs.

BTU. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in

which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and

infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be

productive.

Dry hole. A well found to be incapable of producing either oil, natural gas, and/or NGLs in commercial quantities.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in

another reservoir.

Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and natural gas) rights.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature

and/or stratigraphic condition.

Finding and development cost. Expressed in dollars per MCFE. Finding and development cost metrics provide information as to the cost of

adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as by investors. The

information used to calculate these metrics is included in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report. It

should be noted that finding and development cost metrics have limitations. For example, exploration efforts related to a particular set of proved

reserve additions may extend over several years. As a result, the exploration costs incurred in earlier periods are not included in the amount of

exploration costs incurred during the period in which that set of proved reserves is added. In addition, consistent with industry practice, future capital

costs to develop proved undeveloped reserves are not included in costs incurred. Since the additional development costs that will need to be incurred

in

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the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurred during the period in which

those reserves were added, those development costs in future periods will be reflected in the costs associated with adding a different set of reserves.

The calculations of various finding and development cost metrics are explained below.

Finding and development cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for development and

exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, during the same

period.

Finding and development cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred for development and

exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and revisions of previous

estimates, during the same period.

Finding and development cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount of costs incurred for

development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries,

extensions, infill drilling, and acquisitions, during the same period.

Finding and development cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount of costs incurred for

development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries,

extensions, infill drilling, revisions of previous estimates, and acquisitions, during the same period.

Finding and development cost –All in, including sales of reserves. Calculated by dividing the amount of total capital expenditures for oil and

natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions

of previous estimates less sales of reserves, during the same period.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Gross acre. An acre in which a working interest is owned.

Gross well. A well in which a working interest is owned.

Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.

Lease operating expenses. The expenses incurred in the lifting of crude oil, natural gas, and/or associated liquids from a producing formation to

the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs,

maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.

MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.

MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet, used in reference to natural gas.

MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl

of oil or NGLs.

MMcf. One million cubic feet, used in reference to natural gas.

MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl

of oil or NGLs.

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MMBtu. One million British thermal units.

Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.

Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number of outstanding shares of

common stock.

NGLs. The combination of ethane, propane, butanes, and natural gasolines that when removed from natural gas become liquid under various levels of

higher pressures and lower temperatures.

NYMEX WTI. New York Mercantile Exchange West Texas Intermediate.

OPIS. Oil Price Information Service Mont Belvieu.

PV-10 value (Non-GAAP). The present value of estimated future gross revenue to be generated from the production of estimated net proved

reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of

the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses

such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using

an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized

measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a

comparative basis to other companies and from period to period. This is a Non-GAAP measure.

Productive well. A well that is producing crude oil, natural gas, and/or NGLs or that is capable of commercial production of those products.

Proved reserves. Those quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable

certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating

methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal

is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include

prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-

month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-themonth price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future

conditions.

Recompletion. The completion in an existing wellbore in a formation other than that in which the well has previously been completed.

Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-

month period.

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Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual production volumes and grow

its reserves, and provide information related to how successful a company is at growing its proved reserve base. These are believed to be useful nonGAAP measures that are widely utilized within the exploration and production industry, as well as by investors. They are easily calculable metrics,

and the information used to calculate these metrics is included in the Supplemental Oil and Gas Information section of Part II, Item 8 of this

report. It should be noted that reserve replacement metrics have limitations. They are limited because they typically vary widely based on the extent and

timing of new discoveries and property acquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, because

the metrics do not embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation. The calculations

of various reserve replacement metrics are explained below.

Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve extensions and discoveries

and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company

is having in replacing its production through drilling activity.

Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve extensions, discoveries, and

infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator

of the relative success a company is having in replacing its production through drilling activity with an adjustment for revisions.

Reserve replacement – Drilling and acquisitions, excluding revisions. Calculated as a numerator comprised of the sum of reserve

acquisitions and reserve extensions, discoveries, and infill reserves in an existing proved field divided by production for that same period. This metric

is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities.

Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator comprised of the sum of reserve

acquisitions and reserve extensions, discoveries, and infill reserves, and revisions of previous estimates in an existing proved field divided by

production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and

acquisition activities with an adjustment for revisions.

Reserve replacement percentage – All in, excluding sales of reserves. The sum of reserve extensions and discoveries, infill drilling, reserve

acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period.

Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves, infill drilling, reserve extensions and

discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same

period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil, natural gas, and/or associated

liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resource play. A term used to describe an accumulation of crude oil, natural gas, and/or associated liquid resources known to exist over a large

areal expanse, which when compared to a conventional play typically has a lower expected geological and/or commercial development risk.

Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil, natural gas,

and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.

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Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of crude oil, natural gas, and NGL production free of

costs of exploration, development, and production operations.

Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of

subsurface rock formations.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices

used in estimating the reserves, year-end costs, and statutory tax rates, and a 10 percent annual discount rate. The information for this calculation is

included in the supplemental information regarding disclosures about oil and gas producing activities following the Notes to Consolidated

Financial Statements included in this report.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial

quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.

Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively

major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has

been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share

in the production, sales, and costs.

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ITEM 1A. RISK FACTORS

In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an

investment in us.

Risks Related to Our Business

Crude oil, natural gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition,

cash flows, access to capital, and ability to grow.

Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and natural gas properties depend

heavily on the prices we receive for crude oil, natural gas and NGL sales. Crude oil, natural gas, and NGL prices also affect our cash flows available

for capital expenditures and other items, our borrowing capacity, and the amount and value of our crude oil, natural gas, and NGL reserves. For

example, the amount of our borrowing base under our credit facility is subject to periodic redeterminations based on crude oil, natural gas, and NGL

prices specified by our bank group at the time of redetermination. In addition, we may have crude oil and natural gas property impairments or

downward revisions of estimates of proved reserves if prices fall significantly.

Historically, the markets for crude oil, natural gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide

fluctuations in crude oil, natural gas, and NGL prices may result from relatively minor changes in the supply of and demand for crude oil, natural

gas, and NGLs, market uncertainty, and other factors that are beyond our control, including:

• global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole;

• the level of consumer demand for crude oil, natural gas, and NGLs;

• overall global and domestic economic conditions;

• weather conditions;

• the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may

affect the realized price for crude oil, natural gas, or NGLs;

• liquefied natural gas deliveries to and from the United States;

• the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas;

• the price and availability of alternative fuels;

• technological advances and regulations affecting energy consumption and conservation;

• the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to agree to and maintain

crude oil price and production controls;

• political instability or armed conflict in crude oil or natural gas producing regions;

• strengthening and weakening of the United States dollar relative to other currencies; and

• governmental regulations and taxes.

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These factors and the volatility of crude oil, natural gas, and NGL markets make it extremely difficult to predict future crude oil, natural gas,

and NGL price movements with any certainty. Declines in crude oil, natural gas, and NGL prices would reduce our revenues and could also reduce

the amount of crude oil, natural gas, and NGLs that we can produce economically, which could have a materially adverse effect on us.

Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business

that we cannot predict.

United States and global economies and financial systems have recently experienced turmoil and upheaval characterized by extreme volatility

and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or

sale of financial institutions, increased levels of unemployment, and an unprecedented level of intervention by the United States federal government

and other governments. Although some portions of the economy appear to have stabilized and there have been signs of the beginning of a recovery, the

extent and timing of a recovery, and whether it can be sustained, are uncertain. Continued weakness in the United States or other large economies

could materially adversely affect our business and financial condition. For example:

• the demand for crude oil, natural gas, and NGLs in the United States has declined and may remain at low levels or further decline if

economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows,

liquidity, and financial condition;

• natural gas prices have recently been lower than at various times in the last decade because of increased supply resulting from, among

other things, increased drilling in unconventional reservoirs, and reduced demand in connection with the recent recession, which

sustained low prices could affect our financial condition and results of operations;

• the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

• the liquidity available under our credit facility could be reduced if any lender is unable to fund its commitment;

• our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business,

including for exploration and/or development of our reserves;

• our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations

or seek bankruptcy protection; and

• variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higher interest costs

for unhedged variable interest rate based borrowings under our credit facility.

If we are unable to replace reserves, we will not be able to sustain production.

Our future operations depend on our ability to find, develop, or acquire crude oil, natural gas, and NGL reserves that are economically

producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we

must locate and develop or acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. In addition,

competition for crude oil and natural gas properties is intense, and many of our competitors have financial, technical, human, and other resources

needed to evaluate and integrate acquisitions that are substantially greater than those available to us.

In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors, many of which are

beyond our control. These factors include the purchase price, future crude oil, natural

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gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net

revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the

acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in

estimating quantities of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to

prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties

will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired

properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing

properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected

economic benefits of such transactions may be limited.

Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be

distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating

operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or

long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions. Without

successful drilling or acquisition activities, our reserves and production will decline over time.

Substantial capital is required to replace our reserves.

We must make substantial capital expenditures to find, acquire, develop, and produce crude oil, natural gas, and NGL reserves. Future cash

flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for

crude oil, natural gas, and NGL sales, our success in locating and developing and acquiring new reserves, and the orderly functioning of credit and

capital markets. If crude oil, natural gas, and NGL prices decrease or if we encounter operating difficulties that result in our cash flows from

operations being less than expected, we must reduce our capital expenditures unless we can raise additional funds through debt or equity financing or

the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds

offered to us for potential divestitures may not always be of acceptable value to us.

If our revenues decrease due to lower crude oil, natural gas, or NGL prices, decreased production, or other reasons, and if we cannot obtain

funding through our credit facility, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute

development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited.

Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than

we do.

We face intense competition from major oil and gas companies, independent oil and gas exploration and production companies, financial

buyers, and institutional and individual investors who seek oil and gas investments throughout the world, as well as the equipment, expertise, labor,

and materials required to operate crude oil and natural gas properties. Many of our competitors have financial, technical, and other resources vastly

exceeding those available to us, and many crude oil and natural gas properties are sold in a competitive bidding process in which our competitors may

be able and willing to pay more for development prospects and productive properties, or in which our competitors have technological information or

expertise that is not available to us to evaluate and successfully bid for the properties. In addition, shortages of equipment, labor, or materials as a

result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring

and developing profitable properties in the face of this competition.

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We also compete for human resources. Over the last few years, the need for talented people across all disciplines in the industry has grown,

while the number of talented people available has not grown at the same pace, and in many cases, is declining due to the demographics of the industry.

The loss of key personnel could adversely affect our business.

We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss

of the services of these or other key personnel could adversely affect our business. Our drilling success and the success of other activities integral to

our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition

for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and

professionals, our ability to compete could be harmed.

The actual quantities and present value of our proved crude oil, natural gas, and NGL reserves may be less than we have estimated.

This report and other of our SEC filings contain estimates of our proved crude oil, natural gas, and NGL reserves and the estimated future

net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to crude oil,

natural gas, and NGL prices, drilling and completion costs, gathering and transportation costs, operating expenses, capital expenditures, effects of

governmental regulation, taxes, timing of operations, and availability of funds. The process of estimating crude oil, natural gas, and NGL reserves is

complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and

economic data for each reservoir. These estimates are dependent on many variables, and therefore changes often occur as our knowledge of these

variables evolve. Therefore, these estimates are inherently imprecise. In addition, the reserve estimates we make for properties that do not have a

significant production history may be less reliable than estimates for properties with lengthy production histories. A lack of production history may

contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures.

Actual future production, prices for crude oil, natural gas, and NGLs, revenues, production taxes, development expenditures, operating

expenses, and quantities of producible crude oil, natural gas, and NGL reserves will most likely vary from those estimated. Any significant variance

of any nature could materially affect the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities

and present value may be significantly less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect

production history, results of exploration, operations and development activity, prevailing crude oil, natural gas, and NGL prices, costs to develop

and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage

from production on adjacent properties.

As of December 31, 2012, 43 percent, or 761.5 BCFE, of our estimated proved reserves were proved undeveloped, and two percent, or

40.8 BCFE, were proved developed non-producing. In order to develop our proved undeveloped reserves, as of December 31, 2012, we estimate

approximately $1.6 billion of capital expenditures would be required. Production revenues from proved developed non-producing reserves will not be

realized until sometime in the future and after some investment of capital. In order to develop our proved developed non-producing reserves, as of

December 31, 2012, we estimate capital expenditures of approximately $30 million would be required. Although we have estimated our proved

reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development

may not occur as scheduled, and actual results may not occur as estimated.

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You should not assume that the PV-10 value and standardized measure of discounted future net cash flows included in this report represent

the current market value of our estimated proved crude oil, natural gas, and NGL reserves. Management has based the estimated discounted future net

cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher

or lower. For example, values of our reserves as of December 31, 2012, were estimated using a calculated 12-month average sales price of $2.76 per

MMBtu of natural gas (NYMEX Henry Hub spot price), $94.71 per Bbl of oil (NYMEX WTI spot price), and $45.65 per Bbl of NGL (OPIS

spot price). We then adjust these base prices to reflect appropriate basis, quality, and location differentials over that period in estimating our proved

reserves. During 2012, our monthly average realized natural gas prices, excluding the effect of derivative cash settlements, were as high as $3.79 per

Mcf and as low as $2.18 per Mcf. For the same period, our monthly average realized crude oil prices before the effect of derivative cash settlements

were as high as $92.23 per Bbl and as low as $71.33 per Bbl, and were as high as $47.08 per Bbl and as low as $27.84 per Bbl for NGLs. Many

other factors will affect actual future net cash flows, including:

• amount and timing of actual production;

• supply and demand for crude oil, natural gas, and NGLs;

• curtailments or increases in consumption by oil purchasers and natural gas pipelines; and

• changes in government regulations or taxes, including severance and excise taxes.

The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from

proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for

purposes of computing the PV-10 value. In addition, the 10 percent discount factor required by the SEC to be used to calculate the PV-10 value for

reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our

business and the oil and natural gas industry in general are subject.

Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other

expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors sometimes beyond our control. These factors include

exploration potential, future crude oil, natural gas, and NGL prices, operating costs, and potential environmental and other liabilities. These

assessments are not precise and their accuracy is inherently uncertain.

In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarily reveal all

existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect

every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may

not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties

on an “as is” basis with limited remedies for breaches of representations and warranties.

In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially

different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent acquired properties

are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be

limited.

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Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted

from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we

may not be able to realize all of the anticipated benefits of our acquisitions.

We have limited control over the activities on properties we do not operate.

Some of our properties, including a portion of our operations in the Eagle Ford shale in South Texas, are operated by other companies and

involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such

properties, including the nature and timing of drilling and operational activities, the operator’s skill and expertise, compliance with environmental,

safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount

of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest

owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the

operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially and adversely affect our

financial condition and results of operations.

We rely on third-party service providers to conduct the drilling and completion operations on properties we operate.

Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion operations.

The ability of third-party service providers to perform such drilling and completion operations will depend on those service providers’ ability to

compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the

supply and demand for oil, natural gas liquids and natural gas, prevailing economic conditions and financial, business and other factors. The failure

of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and

adversely affect our financial condition and results of operations.

Title to the properties in which we have an interest may be impaired by title defects.

We generally rely on title reports in acquiring oil and gas leasehold interests and obtain title opinions only on significant properties that we

drill. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk

of title defects than developed acreage. Title insurance is not available for oil and gas properties. As is customary in our industry, we rely upon the

judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and title

abstract facilities before attempting to acquire or place under lease a specific mineral interest and/or undertake drilling activities. We, in some cases,

perform curative work to correct deficiencies in the marketability of the title to us. Generally, under the terms of the operating agreements affecting

our properties, any monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such

property. A material title defect can reduce the value or render a property worthless, thus adversely affecting our financial condition, results of

operations and operating cash flow if such property is of sufficient value.

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Exploration and development drilling may not result in commercially producible reserves.

Crude oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially producible

crude oil, natural gas, or associated liquids will be found. The cost of drilling and completing wells is often uncertain, and crude oil, natural gas or

associated liquids drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are

beyond our control. These factors include:

• unexpected drilling conditions;

• title problems;

• disputes with owners or holders of surface interests on or near areas where we operate;

• pressure or geologic irregularities in formations;

• engineering and construction delays;

• equipment failures or accidents;

• hurricanes or other adverse weather conditions;

• compliance with environmental and other governmental requirements; and

• shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment,

pipe, chemicals, water, sand, and other supplies.

The prevailing prices for crude oil, natural gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production

equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices.

The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one

region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling

costs for the rigs that are available in that region. In addition, the recent economic and financial downturn has adversely affected the financial

condition of some drilling contractors, which may constrain the availability of drilling services in some areas.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental

authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits

from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable

conditions or costs could have a materially adverse effect on our ability to explore on or develop our properties.

The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and

other technologies we use do not allow us to know conclusively prior to drilling a well if crude oil, natural gas, or NGLs are present, or whether they

can be produced economically. The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the

economics of a project. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating

and other costs to cover drilling and completion costs. Even if sufficient amounts of crude oil, natural gas, or NGLs exist, we may damage a

potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing a well, resulting in a

reduction in or no production from the well, significant expense to repair the well, or the loss and abandonment of the well.

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Drilling results in our newer shale plays may be more uncertain than results in shale plays that are more developed and have longer established

production histories. For example, our experience with horizontal drilling in the Eagle Ford shale play, as well as the industry’s drilling and production

history, is more limited than in many shale plays, such as the Barnett or Woodford shales, and we and the industry generally have less information

with respect to the ultimate recoverability of reserves and the production decline rates in these shales than other areas with longer histories of drilling

and production. Completion techniques that have proven to be successful in other shale formations to maximize recoveries are being used in the early

development of these new shales; however, we can provide no assurance of the ultimate success of these drilling and completion techniques.

In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can

be more susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we

do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so, or if we will be able

to produce crude oil, natural gas, or NGLs from these or any other potential drilling locations.

Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate within a particular area may

decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Unless production is

established within the spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire

and we would lose our right to develop the related properties. Our total net acreage expiring in the next three years represents approximately 27 percent

of our total net undeveloped acreage at December 31, 2012. Although we have identified numerous potential drilling locations, we may not be able to

economically produce crude oil, natural gas, or NGLs from all of them and our actual drilling activities may materially differ from those presently

identified, which could adversely affect our financial condition, results of operations and operating cash flow.

Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and

completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and

completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, we may incur

material write-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Many of our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to

maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to,

landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our

casing the entire length of the well bore, and being able to run tools and recover equipment consistently through the horizontal well bore. Risks that we

face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools

and other equipment the entire length of the well bore during completion operations, being able to recover such tools and other equipment, and

successfully cleaning out the well bore after completion of the final fracture stimulation.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production

profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling

program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil,

natural gas, and NGL decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur

material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.

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Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in

such projects.

We inject water into formations on some of our properties to increase the production of crude oil, natural gas, and associated liquids. We

may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in our operations. The additional

production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery

methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we may not

realize an acceptable return on our investments in such projects. In addition, if proposed legislation and regulatory initiatives relating to hydraulic

fracturing become law, the cost of some of these enhanced recovery methods could increase substantially.

Our commodity derivative contract activities may result in financial losses or may limit the prices that we receive for crude oil,

natural gas, and NGL sales.

To mitigate a portion of the exposure to potentially adverse market changes in crude oil, natural gas, and NGL prices and the associated

impact on cash flows, the Company has entered into various derivative contracts. The Company’s derivative contracts in place include swap and

collar arrangements for crude oil, natural gas, and NGLs. As of December 31, 2012, we were in a net accrued asset position of $38.7 million with

respect to our crude oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain

circumstances, including instances in which:

• our production is less than expected;

• one or more counterparties to our commodity derivative contracts default on their contractual obligations; or

• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity

derivative contract arrangement.

The risk of one or more counterparties defaulting on their obligations is heightened by the recent global and domestic economic and financial

downturn affecting many banks and other financial institutions, including our counterparties and their affiliates. These circumstances may adversely

affect the ability of our counterparties to meet their obligations to us pursuant to derivative transactions, which could reduce our revenues and cash

flows from realized derivative cash settlements. As a result, our financial condition, results of operations, and cash flows could be materially affected

in an adverse way if our counterparties default on their contractual obligations under our commodity derivative contracts.

In addition, commodity derivative contracts may limit the prices that we receive for our crude oil, natural gas and NGL sales if crude oil,

natural gas, or NGL prices rise substantially over the price established by the commodity derivative contract.

The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from crude oil, natural gas, and NGL sales or joint interest billings to co-owners of oil and

gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be

similarly affected by various economic and other conditions, including the recent global and domestic economic and financial downturn.

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In addition, for the year ended December 31, 2012, we had two major customers, Regency Gas Services LLC and Plains Marketing LP,

which accounted for approximately 21 percent and 13 percent, respectively, of our total production revenue. During 2011 and 2010, we had one

major customer, Regency Gas Services LLC, individually account for approximately 18 percent and 11 percent, respectively, of our total

production revenue. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices at which

we sell such products.

We have entered into firm transportation contracts that require us to pay fixed amounts of money to our counterparties regardless

of quantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of natural gas to our

counterparties, our results of operations and liquidity could be adversely affected.

As of December 31, 2012, we were contractually committed to deliver 1,515 Bcf of natural gas and 36 MMBbls of oil pursuant to

contracts expiring at various dates through 2023. We may enter into additional firm transportation agreements as our development of our shale plays,

including the Eagle Ford and Haynesville shales, expand. At the current time, we do not have enough proved developed reserves to offset these

contractual liabilities, but we intend to develop reserves that will exceed the commitments and therefore do not expect any shortfalls. We expect our

production volumes, as well as that of our competitors, to increase significantly in the Eagle Ford shale. The use of firm transportation commitments

gives us the strategic advantage of priority space in a transportation pipeline. In the event we encounter delays in drilling and completing our wells or

otherwise due to construction, interruptions of operations, or delays in connecting new volumes to gathering systems or pipelines for an extended

period of time, the requirements to pay for quantities not delivered could have a material impact on our results of operations and liquidity.

Future crude oil, natural gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset

carrying values.

We follow the successful efforts method of accounting for our crude oil and natural gas properties. All property acquisition costs and costs

of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If

commercial quantities of hydrocarbons are not discovered with an exploratory well, the costs of drilling the well are expensed.

The capitalized costs of our crude oil, natural gas, and NGL properties, on a depletion pool basis, cannot exceed the estimated undiscounted

future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs

of each depletion pool to the estimated discounted future net cash flows of that depletion pool. Unproved properties are evaluated at the lower of cost

or fair market value. We incurred an impairment of proved property and impairment of unproved properties totaling $208.9 million and $16.3 million,

respectively, during 2012, $219.0 million and $7.4 million, respectively, during 2011, and $6.1 million and $2.0 million, respectively, during 2010.

Significant further declines in crude oil, natural gas, or NGL prices in the future or unsuccessful exploration efforts could cause further impairment

write-downs of capitalized costs.

We review the carrying value of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of

each quarter. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if crude oil, natural gas, or NGL

prices increase.

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Lower crude oil, natural gas, or NGL prices could limit our ability to borrow under our credit facility.

Our credit facility has a current commitment amount of $1.0 billion, subject to a borrowing base that the lenders redetermine semi-annually

based largely on the bank group’s assessment of the value of our crude oil, natural gas, and NGL properties, which in turn is impacted by crude oil,

natural gas, and NGL prices. The current borrowing base under our credit facility is $1.55 billion. Declines in crude oil, natural gas, or NGL prices

in the future could limit our borrowing base and reduce the amount we can borrow under our credit facility. Additionally, divestitures of properties

could result in a reduction of our borrowing base.

Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic

conditions, and make it more difficult for us to make payments on our debt.

As of December 31, 2012, we had $350.0 million of long-term senior unsecured debt outstanding relating to our 6.625% Senior Notes due

2019 (the “2019 Notes”) that we issued on February 7, 2011; $350.0 million of long-term senior unsecured debt outstanding relating to our 6.50%

Senior Notes due 2021 (the “2021 Notes”) that we issued on November 8, 2011; and $400.0 million of long-term senior unsecured debt outstanding

relating to our 6.50% Senior Notes due 2023 (the “2023 Notes”) that we issued on June 29, 2012, (collectively referred to as our “Senior Notes”);

and $340.0 million of outstanding borrowings under our secured credit facility. We had three outstanding letters of credit in the aggregate amount of

$808,000, (which reduce the amount available for borrowings under the facility on a dollar-for-dollar basis), resulting in $659.2 million of available

debt capacity under our credit facility, assuming the borrowing conditions under this facility will be met. Our long-term debt represented 50 percent of

our total book capitalization as of December 31, 2012.

Our indebtedness could have important consequences for our operations, including:

• making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital

requirements, capital expenditures, debt service, or other general corporate requirements;

• requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest

costs associated with our debt, rather than to productive investments;

• limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt,

making acquisitions, and paying dividends;

• placing us at a competitive disadvantage compared to our competitors that have less debt; and

• making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

Our ability to make payments on our debt and to refinance our debt and fund planned capital expenditures will depend on our ability to

generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors

that are beyond our control. If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to

us under our credit facility or from other sources, we might not be able to service our debt or fund our other liquidity needs. If we are unable to

service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity

securities, divest assets, or restructure or refinance our debt. We might not be able to sell our equity securities, sell our assets, or restructure or

refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our

existing and future credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may

negatively affect the cost, terms, conditions, and availability of future financing.

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Our debt agreements, including the agreement governing our credit facility and the indentures governing the 2019 Notes, 2021 Notes, and

2023 Notes, permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition,

entities we may acquire in the future could have significant amounts of debt outstanding that we could be required to assume, and in some cases

accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition.

As discussed above, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our

bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at

that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing base or arrange new financing, we may

be forced to sell significant assets.

The agreements governing our debt contain various covenants that limit our discretion in the operation of our business, could

prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.

Our debt agreements contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our

ability to borrow under our credit facility is subject to compliance with certain financial covenants, including (i) maintenance of a quarterly ratio of

total debt to consolidated earnings before interest, taxes, depreciation, amortization, and exploration expense of no greater than 4.0 to 1.0, and (ii)

maintenance of an adjusted current ratio of no less than 1.0 to 1.0, each as defined in our credit facility. Our credit facility also requires us to comply

with certain financial covenants, including requirements that we maintain certain levels of stockholders’ equity and limit our annual cash dividends to

no more than $50.0 million. These restrictions on our ability to operate our business could seriously harm our business by, among other things,

limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities.

The respective indentures governing the 2019 Notes, 2021 Notes, and 2023 Notes also contain covenants that, among other things, limit our

ability and the ability of our subsidiaries to:

• incur additional debt;

• make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock;

• sell assets, including capital stock of our subsidiaries;

• restrict dividends or other payments of our subsidiaries;

• create liens that secure debt;

• enter into transactions with affiliates; and

• merge or consolidate with another company.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of

all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a

significant portion of our outstanding indebtedness.

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We are subject to operating and environmental risks and hazards that could result in substantial losses.

Crude oil and natural gas operations are subject to many risks, including human error and accidents that could cause personal injury, death

and property damage, well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas and associated liquids or well fluids,

migration of fracture fluids into surrounding groundwater, spills or releases from facilities and equipment used to deliver these materials, spills or

releases of brine or other produced or flowback water, subsurface conditions that prevent us from stimulating the planned number of stages,

accessing the entirety of the wellbore with our tools during completion, or removing fracturing materials from the wellbore to allow production to

begin, fires, adverse weather such as hurricanes in the South Texas & Gulf Coast region, freezing conditions in the Williston Basin of our Rocky

Mountain region, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas such as hydrogen

sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses.

Furthermore, if we experience any of the problems with well stimulation and completion activities referenced above, such as hydraulic

fracturing, our ability to explore for and produce crude oil, natural gas, or NGLs may be adversely affected. We could incur substantial losses or

otherwise fail to realize reserves in particular formations as a result of the need to shutdown, abandon and relocate drilling operations, the need to

sample, test and monitor drinking water in particular areas and to provide filtration or other drinking water supplies to users of water supplies that may

have been impacted or threatened by potential contamination from fracturing fluids, the need to modify drill sites to ensure there are no spills or

releases off-site and to investigate and/or remediate any spills or releases that might have occurred, and suspension of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation,

handling and disposal of materials, including solid and hazardous wastes and petroleum hydrocarbons. We may incur joint and several, strict liability

under applicable United States federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous

substances at, on, under or from our leased or owned properties, some of which have been used for natural gas and oil exploration and production

activities for a number of years, often by third parties not under our control. For our non-operated properties, we are dependent on the operator for

operational and regulatory compliance, and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed

thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict

liability laws without regard to fault or the legality of the original conduct, including the CERCLA or the Superfund law, the RCRA, the Clean Water

Act, the CAA, the OPA, and analogous state laws. Under any implementing regulations, we could be required to remove or remediate previously

disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater

contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future

contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damage

allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment. As a result, we may incur substantial liabilities to third

parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur

losses.

We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden

environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damage

or insurance coverage for environmental damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks

generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we believe that the cost of

available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets

in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer

a material loss.

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Following the severe Atlantic hurricanes in 2004, 2005, and 2008, the insurance markets suffered significant losses. As a result, insurance

coverage for wind storms has become substantially more expensive, and future availability and costs of coverage are uncertain.

Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs

and other risks.

Federal, state, tribal, and local authorities extensively regulate the oil and natural gas industry. Legislation and regulations affecting the

industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result,

may affect, among other things, the pricing or marketing of crude oil, natural gas and NGL production. Noncompliance with statutes and regulations

and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal

penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also

result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill,

complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.

Governmental authorities regulate various aspects of drilling for and the production of crude oil, natural gas, and NGLs, including the permit

and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oil and natural gas properties, rightsof-way and easements, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment,

and restoration standards, oil and gas operations, and restoration. Public interest in environmental protection has increased in recent years, and

environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a

proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case,

negatively affect our ability to explore or develop certain properties. Federal authorities also may require any of our ongoing or planned operations on

federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our

operations.

Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal and

local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to

current requirements, including the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate,

could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with

new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and

regulations, we could incur significant liability, including joint and several, strict liability under federal, state, and tribal environmental laws for noise

emissions and for discharges of crude oil, natural gas, and associated liquids or other pollutants into the air, soil, surface water, or groundwater. We

could be required to spend substantial amounts on investigations, litigation, and remediation for these emissions and discharges and other compliance

issues. Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs, but also natural resources,

real or personal property and other compensatory damages and civil and criminal liability. The listing of additional wildlife or plant species as federally

endangered or threatened could result in limitations on exploration and production activities in certain locations. Existing environmental laws or

regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect

on us.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas

where we operate.

Operations in certain of our regions, such as our Rocky Mountain and Permian regions, are adversely affected by seasonal weather

conditions and lease stipulations designed to protect various wildlife or plant species. In certain areas on federal lands, drilling and other oil and natural

gas activities can only be conducted during

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limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field

equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal

leases or across federal lands. Possible restrictions may include seasonal restrictions in greater sage-grouse habitat during breeding and nesting

seasons, within a certain distance of active raptor nests during fledging, and in big game winter or parturition ranges during winter or calving seasons.

These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs

and additional operating restrictions or delays.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas and

associated liquids from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and natural gas

properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Eagle Ford shale of south Texas, and the

Bakken/Three Forks formations in North Dakota. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbonbearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas

commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel in the

fluid system under SDWA and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition,

legislation has been introduced before Congress during prior sessions and is likely to be introduced during the 113th Congress, to provide for federal

regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. If hydraulic fracturing is

regulated at the federal level, our fracturing activities could become subject to additional permit or disclosure requirements or operational restrictions

and also to associated permitting delays, litigation risk, and potential cost increases.

Certain states that we operate in, including Pennsylvania, Texas, and Wyoming, have adopted, and other states are considering adopting,

regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing

operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad

Commission of Texas (“RCT”) and the public of certain information regarding the components and volume of water used in the hydraulic fracturing

process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general

and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently

conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in

nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the

drilling and/or completion of wells.

There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing

practices. The White House Council on Environmental Quality is coordinating a review of hydraulic fracturing practices, and a committee of the

United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies

are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a

study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a progress report, but no research results

or findings, issued in December 2012 and a draft report of results to be issued in 2014 for independent peer review by the Science Advisory Board. In

addition, the United States Department of Energy is conducting an investigation into practices the agency could recommend to better protect the

environment from drilling using hydraulic fracturing completion methods. Also, the United States Department of the Interior is developing disclosure

requirements or other mandates for hydraulic fracturing on federal lands; the Department of the Interior anticipates issuing during the first quarter of

2013 a revised proposed rule relating to hydraulic fracturing activities on federal lands.

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Additionally, certain members of Congress have called upon the United States Government Accountability Office to investigate how

hydraulic fracturing might adversely affect water resources, the United States Securities and Exchange Commission to investigate the natural gas

industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means

of hydraulic fracturing, and the United States Energy Information Administration to provide a better understanding of that agency’s estimates

regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The United States

Geological Survey Offices of Energy Resources Program, Water Resources and Natural Hazards and Environmental Health Offices have ongoing

research projects on hydraulic fracturing. These ongoing or proposed studies, depending on their course and outcomes, could spur initiatives to

further regulate hydraulic fracturing under the SDWA or other regulatory processes.

Further, on August 16, 2012, the EPA issued final rules subjecting all oil and gas operations (production, processing, transmission, storage,

and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air

Pollutants (“NESHAPS”) programs. The EPA rules also include NSPS standards for completions of hydraulically fractured gas wells. These

standards require the use of reduced emission completion (“REC”) techniques developed in EPA's Natural Gas STAR program along with the pit

flaring of gas not sent to the gathering line beginning in January 2015. The standards are applicable to newly drilled and fractured wells as well as

existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (“MACT”)

standards for those glycol dehydrators and certain storage vessels at major sources of hazardous air pollutants not currently subject to MACT

standards. The EPA stated in January 2013, however, that it intends to reconsider portions of the final rule. We are currently evaluating the effect of

these rules on our business.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas

production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for

third parties opposing such activity to pursue legal proceedings against producers and service providers based on allegations that specific chemicals

used in the fracturing process could adversely affect human health or the environment, including groundwater. Additional legislation or regulation

could also lead to operational delays or increased costs in the exploration for and production of oil, natural gas, and associated liquids, including from

the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state, or local

laws, or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas

wells, increased compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows. The EPA is

in the process of updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act. Flowback and produced water

from the hydraulic fracturing process contains total dissolved solids, including chlorides. The EPA anticipates issuing a draft criteria document in

2013.

On October 20, 2011, the EPA announced a schedule for development of standards for disposal of wastewater produced from shale gas

operations to publicly owned treatment works (“POTWs”). The regulations will be developed under the EPA’s Effluent Guidelines Program under the

authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014.

Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired

if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of

or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.

The hydraulic fracturing process on which we depend to drill for commercial quantities of crude oil, natural gas, and associated liquids

requires the use and disposal of significant quantities of water.

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Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our

operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain

operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes

associated with the exploration, development, or production of natural gas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or

groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our

operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and

production may be eliminated as a result of future legislation.

During his first term, President Obama sent to Congress a legislative package that included proposed legislation that, if enacted into law,

would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production

companies. These changes included, among other proposals:

• the repeal of the percentage depletion allowance for oil and natural gas properties;

• the elimination of current deductions for intangible drilling and development costs;

• the elimination of the deduction for certain domestic production activities; and

• an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear when or if these or similar changes will be enacted. The passage of legislation enacting these or similar changes in federal

income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and

development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our

operations and the demand for crude oil, natural gas, and NGLs.

In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other “greenhouse gases” present an endangerment

to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere

and other climatic changes. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict

emissions of greenhouse gases under existing provisions of the CAA. For example, the EPA has adopted two sets of rules regulating greenhouse gas

emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other regulates the

permitting and emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules

requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum

refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas

production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011. In the courts, several cases are pending that may

increase the risk of claims being filed against companies that have significant greenhouse gas emissions. Such cases seek to challenge air emissions

permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts

to the environment, people, and property. Any laws or regulations that restrict or reduce emissions of greenhouse gases could require us to incur

increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce.

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In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and

almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development

of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by

requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to

acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall

greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating

costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting

requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, gas,

and NGLs we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on

our business, financial condition, results of operations, and cash flows. Finally, it should be noted that some scientists have predicted that increasing

concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased

frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely

affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from

flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance

coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and

operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom

we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from

potential physical effects of climate change.

Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments

to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which was signed into law on July 21, 2010,

establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that

market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and trade execution requirements. On October 18,

2011, the Commodities Futures Trading Commission (the “CFTC”) approved regulations to set position limits for certain futures and option contracts

in the major energy markets, which were successfully challenged in federal district court by the Securities Industry Financial Markets Association

and the International Swaps and Derivatives Association and largely vacated by the court. The CFTC has filed a notice of appeal with respect to this

ruling. Under CFTC final rules promulgated under the Dodd-Frank Act, we believe our derivatives activity will qualify for the non-financial,

commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing

requirement. The Dodd-Frank Act may also require us to comply with margin requirements in our derivative activities, although the application of

those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin

off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to

post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of

derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our

exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of

operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital

expenditures. Finally, the Dodd-Frank Act was intended, in

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part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments

related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower

commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and

cash flows.

Our ability to sell crude oil, natural gas and NGLs, and/or receive market prices for our production, may be adversely affected by

constraints on gathering systems, processing facilities, pipelines and other transportation systems owned or operated by others or

by other interruptions.

The marketability of our crude oil, natural gas, and NGL production depends in part on the availability, proximity, and capacity of gathering

systems, processing facilities, and pipeline and other transportation systems owned or operated by third parties. The lack of available capacity in these

systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower

price realizations. Although we have some contractual control over the processing and transportation of our operated production, material changes in

these business relationships could materially affect our operations. Federal and state regulation of crude oil, natural gas, and NGL production and

transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or

capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, and transport crude oil, natural

gas, and NGLs.

In particular, if drilling in the Eagle Ford shale, Haynesville shale, Bakken/Three Forks resource play, and Granite Wash resource play

continues to be successful, the amount of crude oil, natural gas, and NGLs being produced by us and others could exceed the capacity of, and result

in strains on, the various gathering and transportation systems, pipelines, processing facilities, and other infrastructure available in these areas. It will

be necessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to be expanded, built or developed

to accommodate anticipated production from these areas. Because of the current economic climate, certain processing, pipeline, and other gathering

or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other

constraints. Capital and other constraints could also limit our ability to build or access intrastate gathering and transportation systems necessary to

transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development

activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower

prices, which would adversely affect our results of operations and cash flows. In addition, the operations of the third parties on whom we rely for

gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous

permits, approvals and certifications from various federal, state, and local government authorities. These third parties may incur substantial costs in

order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or

if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a

failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial

condition and results of operations.

A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of

weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we

might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could

temporarily and adversely affect our cash flows and results of operations.

New technologies may cause our current exploration and drilling methods to become obsolete.

The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and

services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive

pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical,

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and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we

can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we

will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements

consistent with industry standards, our operations and financial condition may be adversely affected.

Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other

disruptions.

As a crude oil, natural gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access

to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and

infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize

various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and

controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of

sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our

reputation, financial position, results of operations, or cash flows.

Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to

data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise

protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of

business or potential liability.

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to

increased volatility in prices for crude oil, natural gas, and NGLs, all of which could adversely affect the markets for our operations. Energy assets

might be specific targets of terrorist attacks. These developments have subjected our operations to increased risk and, depending on their occurrence

and ultimate magnitude, could have a material adverse effect on our business.

Risks Related to Our Common Stock

The price of our common stock may fluctuate significantly, which may result in losses for investors.

From January 1, 2012, to February 14, 2013, the closing daily sale price of our common stock as reported by the New York Stock

Exchange ranged from a low of $41.80 per share in August 2012 to a high of $83.35 per share in February 2012. We expect our stock to continue to

be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:

• changes in crude oil, natural gas, or NGL prices;

• variations in drilling, recompletion, and operating activity;

• changes in financial estimates by securities analysts;

• changes in market valuations of comparable companies;

• additions or departures of key personnel;

• future sales of our common stock; and

• changes in the national and global economic outlook.

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We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could

decline as a result.

Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders

from receiving a takeover premium on their investment.

Our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control.

These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural

requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These

provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including

transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.

Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our business is doing

well.

The potential for sales of substantial amounts of our common stock in the public market may have a materially adverse effect on our stock

price. As of February 14, 2013, 66,153,847 shares of our common stock were freely tradable without substantial restriction or the requirement of

future registration under the Securities Act of 1933. Also as of that date, options to purchase 257,180 shares of our common stock were

outstanding, all of which were exercisable. These options are exercisable at prices ranging from $12.53 to $20.87 per share. In addition, restricted

stock units (“RSUs”) providing for the issuance of up to a total of 493,968 shares of our common stock and 898,145 performance share units

were outstanding. Performance share units are structurally the same as the previously granted Performance Share Awards or (“PSAs”) (collectively

known as “Performance Share Units” or “PSUs”). The PSUs represent the right to receive, upon settlement of the PSUs after the completion of a

three-year performance period, a number of shares of our common stock that may be from zero to two times the number of PSUs granted, depending

on the extent to which the underlying performance criteria have been achieved and the extent to which the PSUs have vested. As of February 14,

2013, there were 66,205,901 shares of our common stock outstanding, which is net of 50,581 treasury shares.

We may not always pay dividends on our common stock.

Payment of future dividends remains at the discretion of our Board of Directors, and will continue to depend on our earnings, capital

requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our credit facility limiting our

annual cash dividends to no more than $50.0 million, and to covenants in the indentures for our 2019 Notes, 2021 Notes, and 2023 Notes that limit

our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current semi-annual dividend

rate of $0.05 per share, or discontinue the payment of dividends altogether.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the

filing date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect

upon our financial condition, results of operations or cash flows.

We were a defendant in litigation, captioned W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al., wherein the plaintiffs

claimed an aggregate overriding royalty interest of 7.46875 percent in production from approximately 22,000 of our net acres in the Eagle Ford shale

play in South Texas. The plaintiffs sought to quiet title to their claimed overriding royalty interest and to recover unpaid overriding royalty interest

proceeds allegedly due. We believed that the claimed overriding royalty interest had been terminated under the governing agreements and the applicable

law, and contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court in Webb

County, Texas, issued an order granting plaintiffs’ motion for summary judgment and denying our motion for summary judgment. On September 30,

2011, the District Court entered final judgment for the plaintiffs and awarded then current damages of approximately $5.1 million, which included

prejudgment interest. The District Court also awarded attorneys fees and costs to the plaintiffs. We appealed the District Court’s judgment and

obtained a stay pending appeal that prevented the plaintiffs from executing on the judgment.

On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this matter, which reversed the summary

judgment granted to the plaintiffs by the District Court and rendered judgment that the plaintiffs take nothing. Accordingly, based on the judgment of

the Fourth Court of Appeals, the plaintiffs are not entitled to their claimed 7.46875 percent overriding royalty interest, nor are they entitled to the

claimed damages related to the overriding royalty interest, attorneys fees or costs. The plaintiffs petitioned the Supreme Court of Texas for a review

of the judgment of the Fourth Court of Appeals. The Supreme Court of Texas denied this petition for review on February 15, 2013, and as a result,

the decision of the Fourth Court of Appeals is dispositive and its dismissal of the plaintiffs’ claims is final.

We also filed a declaratory judgment action in Webb County, Texas, captioned SM Energy Company vs. W.H. Sutton, et al., seeking a

judgment declaring that the lease at issue in W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al. had terminated with respect to the

remaining 18,000 acres, based upon a failure of continuous development, and that any overriding royalty interest claimed by the defendants has been

extinguished. On September 19, 2012, the District Court in Webb County, Texas, granted our motion for summary judgment, concluding that the

defendants’ claims for any overriding royalty interest had been extinguished. The plaintiffs filed their notice of appeal to the Fourth Court of Appeals

on November 15, 2012, but due to the numerous requests for an extension, have not yet filed their brief. We will continue to contest this litigation.

We, and our working interest partners, filed an action against Endeavour Operating Corporation (“Endeavour”) in Harris County, Texas,

captioned SM Energy Company, et al. v. Endeavour Operating Corporation, seeking an order requiring Endeavour to honor its obligations to

consummate the purchase of certain assets located in Pennsylvania, or in the alternative, for damages. We are required to take reasonable measures to

attempt to mitigate our potential losses, and during 2012 we initiated efforts to remarket such assets. If we are successful in such efforts and complete

a sale of these assets for less than the $110 million ($80 million of which is attributable to our interest) Endeavour agreed to pay to us and our

working interest partners, we will continue to prosecute this action to recover any such deficiency and any amounts expended in our efforts to

remarket the assets, and to obtain any other relief to which we are entitled. As of the filing date of this report, we have no commitment from another

party to purchase these assets.

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On January 27, 2011, Chieftain Royalty Company (“Chieftain”) filed a Class Action Petition against us in the District Court of Beaver

County, Oklahoma, claiming damages related to royalty valuation on all of our Oklahoma wells. These claims include breach of contract, breach of

fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of

post-production costs. We removed this lawsuit to the United States District Court for the Western District of Oklahoma on February 22, 2011. We

have responded to the petition and denied the allegations. The court has not yet ruled on Chieftain's motion to certify the putative class, and has stayed

any such ruling until the United States Court of Appeals for the Tenth Circuit issues its ruling on class certification in two similar royalty class action

lawsuits, where the defendants have appealed such certification. The opinion from the Tenth Circuit is expected during the summer of 2013. We

believe we properly valued and paid royalty under Oklahoma law and have and will continue to vigorously defend this case.

ITEM 4. MINE SAFETY DISCLOSURES

These disclosures are not applicable to us.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER

PURCHASES OF EQUITY SECURITIES

Market Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM”. The

following table presents the range of high and low intraday sales prices per share for the indicated quarterly periods in 2012 and 2011, as reported by

the New York Stock Exchange:

Quarter Ended High Low

December 31, 2012 $ 62.09 $ 45.25

September 30, 2012 $ 59.39 $ 39.44

June 30, 2012 $ 71.81 $ 43.12

March 31, 2012 $ 84.40 $ 69.40

December 31, 2011 $ 88.50 $ 53.45

September 30, 2011 $ 85.55 $ 60.52

June 30, 2011 $ 78.55 $ 61.37

March 31, 2011 $ 75.00 $ 54.59

PERFORMANCE GRAPH

The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2007, and

ending on December 31, 2012, with the cumulative total returns of the Dow Jones U.S. Exploration and Production Board Index, and the Standard

& Poor’s 500 Stock Index.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS

The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the Securities and

Exchange Commission.

Holders. As of February 14, 2013, the number of record holders of SM Energy’s common stock was 88. Based upon inquiry,

management believes that the number of beneficial owners of our common stock is approximately 35,200.

Dividends. We have paid cash dividends to our stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each

of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in 2005 through 2012. We expect that our practice of paying

dividends on our common stock will continue,

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although the payment of future dividends will continue to depend on our earnings, cash flow, capital requirements, financial condition, and other

factors, including the discretion of our Board of Directors. In addition, the payment of dividends is subject to covenants in our credit facility that limit

our annual dividend payment to no more than $50.0 million per year. We are also subject to certain covenants under our 2019 Senior Notes, our 2021

Senior Notes, and our 2023 Senior Notes that restrict certain payments, including dividends; provided, however, the first $6.5 million of dividends

paid each year are not restricted by this covenant. Based on our current performance, we do not anticipate that these covenants will restrict future

annual dividend payments of $0.10 per share of common stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.5

million in 2012 and $6.4 million in 2011.

Restricted Shares. We have no restricted shares outstanding as of December 31, 2012, aside from Rule 144 restrictions on shares held by

insiders and shares issued to members of the Board of Directors under our Equity Incentive Compensation Plan (“Equity Plan”).

Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table provides information about purchases

by the Company and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended

December 31, 2012, of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to

Section 12 of the Exchange Act.

ISSUER PURCHASES OF EQUITY SECURITIES

Total Number of

Shares Purchased(1)

Average Price Paid

per Share

Total Number of Shares

Purchased as Part of

Publicly Announced

Program

Maximum Number of

Shares that May Yet be

Purchased Under the

Program(2)

January 1, 2012 –

March 31, 2012 176 $ 79.93 — 3,072,184

April 1, 2012 -

June 30, 2012 — $ — — 3,072,184

July 1, 2012 -

September 30, 2012 456,227 $ 47.32 — 3,072,184

October 1, 2012 -

October 31, 2012 — $ — — 3,072,184

November 1, 2012 -

November 30, 2012 162 $ 49.43 — 3,072,184

December 1, 2012 -

December 31, 2012 158 $ 53.92 — 3,072,184

Total October 1, 2012 -

December 31, 2012 320 $ 51.66 — 3,072,184

Total 456,723 $ 47.34 — 3,072,184

 

(1) All shares purchased in 2012 were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying RSUs and PSUs

delivered under the terms of grants under the Equity Plan.

(2) In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization

to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, subject to the approval of our Board of Directors, we may

repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market

transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the

indentures governing our Senior Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash

flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time. Please refer to Dividends

above for a description of our dividend limitations.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected supplemental financial and operating data for us as of the dates and periods indicated. The financial

data for each of the five years presented were derived from our consolidated financial statements. The following data should be read in conjunction

with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which

includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated

financial statements included in this report.

Years Ended December 31,

2012 2011 2010 2009 2008

(in millions, except per share data)

Total operating revenues $ 1,505.1 $ 1,603.3 $ 1,092.8 $ 832.2 $ 1,301.3

Net income (loss) $ (54.2) $ 215.4 $ 196.8 $ (99.4) $ 87.3

Net income (loss) per share:

Basic $ (0.83) $ 3.38 $ 3.13 $ (1.59) $ 1.40

Diluted $ (0.83) $ 3.19 $ 3.04 $ (1.59) $ 1.38

Total assets at year-end $ 4,199.5 $ 3,799.0 $ 2,744.3 $ 2,360.9 $ 2,697.2

Long-term debt:

Line of credit $ 340.0 $ — $ 48.0 $ 188.0 $ 300.0

3.50% Senior Convertible Notes, net

of debt discount $ — $ 285.1 $ 275.7 $ 266.9 $ 258.7

6.625% Senior Notes due 2019 $ 350.0 $ 350.0 $ — $ — $ —

6.50% Senior Notes due 2021 $ 350.0 $ 350.0 $ — $ — $ —

 6.50% Senior Notes due 2023 $ 400.0 $ — $ — $ — $ —

Cash dividends declared and paid per

common share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10

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Supplemental Selected Financial and Operations Data

For the Years Ended December 31,

2012 2011 2010 2009 2008

Balance Sheet Data (in millions)

Total working capital (deficit) $ (201.0) $ (42.6) $ (227.4) $ (87.6) $ 15.2

Total stockholders’ equity $ 1,414.5 $ 1,462.9 $ 1,218.5 $ 973.6 $ 1,162.5

Weighted-average common shares outstanding (in

thousands)

Basic 65,138 63,755 62,969 62,457 62,243

Diluted 65,138 67,564 64,689 62,457 63,133

Reserves

Oil (MMBbl) 92.2 71.7 57.4 53.8 51.4

Gas (Bcf) 833.4 664.0 640.0 449.5 557.4

 NGLs (MMBbl) 62.3 27.5 — — —

BCFE 1,760.6 1,259.2 984.5 772.2 865.5

Production and Operational (in millions)

Oil, gas, and NGL production revenues $ 1,473.9 $ 1,332.4 $ 836.3 $ 616.0 $ 1,259.4

Oil, gas, and NGL production expenses $ 391.9 $ 290.1 $ 195.1 $ 206.8 $ 271.4

DD&A $ 727.9 $ 511.1 $ 336.1 $ 304.2 $ 314.3

General and administrative $ 119.8 $ 118.5 $ 106.7 $ 76.0 $ 79.5

Production Volumes

Oil (MMBbl) 10.4 8.1 6.4 6.3 6.6

Gas (Bcf) 120.0 100.3 71.9 71.1 74.9

NGLs (MMBbl) 6.1 3.5 — — —

BCFE 218.9 169.7 110.0 109.1 114.6

Realized price

Oil (per Bbl) $ 85.45 $ 88.23 $ 72.65 $ 54.40 $ 92.99

Gas (per Mcf) $ 2.98 $ 4.32 $ 5.21 $ 3.82 $ 8.60

NGL (per Bbl) $ 37.61 $ 53.32 $ — $ — $ —

Adjusted price (net of derivative cash settlements)

Oil (per Bbl) $ 83.52 $ 78.89 $ 66.85 $ 56.74 $ 75.59

Gas (per Mcf) $ 3.48 $ 4.80 $ 6.05 $ 5.59 $ 8.79

NGL (per Bbl) $ 38.90 $ 47.90 $ — $ — $ —

Expense per MCFE

LOE $ 0.82 $ 0.88 $ 1.10 $ 1.33 $ 1.46

Transportation $ 0.63 $ 0.51 $ 0.19 $ 0.19 $ 0.19

Production taxes $ 0.33 $ 0.32 $ 0.48 $ 0.37 $ 0.71

DD&A $ 3.32 $ 3.01 $ 3.06 $ 2.79 $ 2.74

General and administrative $ 0.55 $ 0.70 $ 0.97 $ 0.70 $ 0.69

Statement of Cash Flow Data (in millions)

Provided by operations $ 922.0 $ 760.5 $ 497.1 $ 436.1 $ 679.2

(Used in) investing $ (1,457.3) $ (1,264.9) $ (361.6) $ (304.1) $ (673.8)

Provided by (used in) financing $ 422.1 $ 618.5 $ (141.1) $ (127.5) $ (42.8)

 

Note: 2010 and prior NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality

of the amounts. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices in Part II, Item 7 of this report.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS

This discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements in

Part I, Items 1 and 2 of this report for important information about these types of statements.

Overview of the Company

General Overview

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in

onshore North America. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, as well as exposure to

the Granite Wash play and emerging oil-focused plays in the Permian Basin. We have built a portfolio of onshore properties in the contiguous United

States primarily through early entry into existing and emerging resource plays. This portfolio is comprised of properties with established production

and reserves, prospective drilling opportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable

production and reserve growth. Furthermore, by entering these plays early, we believe we can capture larger resource potential at a lower cost.

Our principal business strategy is to focus on the early capture of resource plays in order to create and then enhance value for our

shareholders while maintaining a strong balance sheet. We strive to leverage industry-leading exploration and leasehold acquisition teams to quickly

acquire and test new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop

such potential through top-tier operational and project execution and to mitigate our risks by selectively divesting of certain assets when deemed

appropriate by us. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to optimize our returns and

preserve our financial strength.

In 2012 we had the following financial and operational results:

• At year-end 2012, we had estimated proved reserves of 1,760.6 BCFE (293.4 MMBOE), of which 53 percent were liquids (oil and

NGLs) and 57 percent was characterized as proved developed. We added 900.2 BCFE from our drilling program, the majority of which

related to our activity in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We had negative price

revisions that decreased our estimated proved reserves by 72.7 BCFE primarily due to gas weighted projects in our South Texas & Gulf

Coast and Mid-Continent regions that do not generate positive cash flow utilizing historical 12-month average benchmark pricing

required by the SEC. The prices used in the calculation of proved reserve estimates as of December 31, 2012, were $94.71 per Bbl,

$2.76 per MMBtu, and $45.65 per Bbl, for oil, gas, and NGLs, respectively. These prices were two percent, 33 percent, and 23

percent lower for oil, gas, and NGLs, respectively, than the prices used at year-end 2011. We had downward engineering revisions of

49.2 BCFE related primarily to Eagle Ford shale proved undeveloped locations as well as downward engineering revisions of Wolfberry

assets in our Permian region. Additionally, we removed 42.7 BCFE of proved undeveloped reserves primarily in the Woodford shale due

to low natural gas prices and as a result of the five-year limitation on the number of years proved undeveloped reserves may remain on

the books without being developed. Please refer to the caption Proved Undeveloped Reserves under the section Reserves included in

Part I, Items 1 and 2 of this report for additional discussion. We had immaterial acquisitions of 1.6 BCFE, and we divested of 16.9

BCFE of proved reserves during the year related to non-core assets located primarily in our Rocky Mountain and Mid-Continent

regions.

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• The PV-10 value of our estimated proved reserves was $3.8 billion as of December 31, 2012, compared with $3.5 billion as of

December 31, 2011. The after tax value, represented by the standardized measure calculation, was $3.0 billion as of December 31,

2012 compared with $2.6 billion as of December 31, 2011. The standardized measure calculation is presented in the Supplemental

Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the

after tax value is shown under Reserves in Part I, Items 1 and 2 of this report.

• We had record production in 2012. Our average daily production in 2012 was 28.3 MBbl of oil, 328.0 MMcf of gas, and 16.7 MBbl

of NGLs, for an average equivalent production rate of 598.2 MMCFE, compared with 465.0 MMCFE in 2011, an increase of 29

percent year-over-year. Please refer to the caption Production Results below for additional discussion.

• We recorded a net loss of $54.2 million, or a loss of $0.83 per diluted share, for the year ended December 31, 2012, due to an

impairment of proved properties. This compares with net income of $215.4 million, or $3.19 per diluted share, for the year ended

December 31, 2011. Please refer to the caption Comparison of Financial Results and Trends Between 2012 and 2011 below

for additional discussion regarding the components of net income (loss) and 2012 Highlights for additional discussion on impairment

of proved properties.

• We had record cash flow provided by operating activities of $922.0 million for the year ended December 31, 2012, compared with

$760.5 million for the year ended December 31, 2011, which was an increase of 21 percent year-over-year. Please refer to Analysis

of cash flow changes between 2012 and 2011 below for additional discussion.

• Costs incurred for oil and gas producing activities for the year ended December 31, 2012, were $1.7 billion, compared with $1.6

billion for the same period in 2011. Please refer to the caption Costs Incurred in Oil and Gas Producing Activities below for

additional discussion.

• EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2012, was $1.0 billion, compared with $886.6 million

for the same period in 2011. Please refer to the caption Non-GAAP Financial Measures below for additional discussion, including

our definition of EBITDAX and reconciliations of our GAAP net income (loss) and net cash provided by operating activities to

EBITDAX.

Reserve Replacement, Finding and Development Costs, and Growth

Like all oil and gas exploration and production companies, we face the challenge of growing proved reserves. An exploration and production

company depletes part of its asset base with each unit of oil, gas, or NGL it produces. Our future growth will depend on our ability to organically and

economically add reserves in excess of production.

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The following table provides various reserve replacement and finding and development cost metrics for the year ended December 31, 2012:

Reserve Replacement Percentage Finding and Development Cost per

MCFE (1)

Excluding

Divestitures

Including

Divestitures

Excluding

Divestitures

Including

Divestitures

Drilling, excluding revisions 411% 403% $ 1.74 $ 1.77

Drilling, including revisions 336% 328% $ 2.13 $ 2.18

Drilling and acquisitions, excluding revisions 412% 404% $ 1.74 $ 1.78

Drilling and acquisitions, including revisions 337% 329% $ 2.13 $ 2.18

Reserve Acquisitions 1% N/M $ 3.59 N/M

All-in 337% 329% $ 2.29 $ 2.34

* N/M – Percentage or amount, as applicable, is not meaningful.

(1) Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for discussion on how we are being carried on 90

percent of certain drilling and completion costs.

The following table provides average reserve replacement and finding and development cost metrics for the three-year period ended

December 31, 2012:

Reserve Replacement Percentage

Finding and Development Cost per

MCFE (1)

Excluding

Divestitures

Including

Divestitures

Excluding

Divestitures

Including

Divestitures

Drilling, excluding revisions 363% 324% $ 2.15 $ 2.41

Drilling, including revisions 337% 298% $ 2.31 $ 2.62

Drilling and acquisitions, excluding revisions 363% 324% $ 2.15 $ 2.41

Drilling and acquisitions, including revisions 338% 298% $ 2.31 $ 2.62

Reserve Acquisitions N/M N/M $ 3.52 N/M

All-in 338% 298% $ 2.45 $ 2.77

* N/M – Percentage or amount, as applicable, is not meaningful.

(1) Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for discussion on how we are being carried on 90

percent of certain drilling and completion costs.

Our challenge is to grow net asset value per share, which we believe drives appreciation in our stock price over the long term. To accomplish

this, we believe it is important to organically and economically replace annual production with new reserves. We believe annual reserve replacement

percentage and finding and development costs are important analytical measures that are widely used by investors and industry peers in evaluating and

comparing the performance of oil and gas companies. While single-year measurements have some meaning in terms of a trend, we believe aberrations,

causing both positive and negative results, will occur over short intervals of time. The information used to calculate the above reserve replacement and

finding and development cost metrics is included in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report.

For additional information about these metrics, see the reserve replacement and finding and development cost terms in the Glossary of Oil and Gas

Terms at the end of Part I, Items 1 and 2 of this report.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, gas, and NGL

production, which can fluctuate dramatically. We sell the majority of our natural gas under contracts using first-of-the-month index pricing, which

means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets

where high BTU gas is sold

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at the wellhead, we also receive additional value for the high energy content contained in the gas stream. Our NGL production is generally sold using

contracts paying us a monthly average of the posted OPIS daily settlement prices, adjusted for processing, transportation, and location differentials.

Our oil and condensate are sold using contracts paying us either the average of the NYMEX WTI daily settlement price or the average of alternative

posted prices for the periods in which the product is produced, adjusted for quality, transportation, and location differentials.

Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. As a result, we reported

realized prices for our natural gas production for periods through December 31, 2010, that were higher than industry benchmarks due to the price

uplift associated with incremental value contained in the higher BTU content of our produced gas stream. Beginning in 2011, we changed our

reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product. Projected rapid

production growth from our NGL-rich assets associated with plant product sales contracts necessitated a change in our reporting of production

volumes. Our 2010 production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality

of the NGL volumes produced in that period.

The following table is a summary of commodity price data for the years ended December 31, 2012, 2011, and 2010:

For the Years Ended December 31,

2012 2011 2010

Crude Oil (per Bbl):

Average NYMEX price $ 94.10 $ 95.05 $ 79.51

Realized price $ 85.45 $ 88.23 $ 72.65

Natural Gas:

Average NYMEX price (per MMBtu) $ 2.75 $ 4.00 $ 4.37

Realized price (per Mcf) $ 2.98 $ 4.32 $ 5.21

NGLs (per Bbl):

Average OPIS price $ 44.91 $ 59.47 $ 34.61

Realized price $ 37.61 $ 53.32 N/A

 

Note: 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of NGL

volumes. Please refer to additional discussion above. Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane,

32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard

composite barrel and does not necessarily represent the Company’s product mix for NGL production. The Company's actual product mix is reflected in actual

prices received for NGLs produced.

We expect future prices for oil, gas, and NGLs to be volatile. In addition to supply and demand fundamentals, as a global commodity, the

price of oil will likely continue to be impacted by real or perceived geopolitical risks in oil producing regions of the world, particularly in the Middle

East. The relative strength of the U.S. dollar compared to other currencies could also affect the price of oil. The supply of NGLs in the U.S. is

expected to continue to grow in the near term as a result of the number of industry participants targeting projects that produce these products. The

pace of NGL production is growing faster than the capacity to process or consume NGLs, which will likely negatively impact pricing in the near

term. The prices of several of the specific NGL products correlate to the price of oil and accordingly are likely to directionally follow that market.

Gas prices have been under downward pressure for several years due to market oversupply resulting from continued high levels of natural gas

production and insufficient demand for natural gas as a result of tepid economic growth, although gas prices increased moderately in the last half of

2012. The 12-month strip prices for NYMEX WTI oil, NYMEX

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Henry Hub gas, and OPIS NGLs (same product mix as discussed above) as of December 31, 2012, were $93.19 per Bbl of oil, $3.60 per MMBtu

of gas, and $41.20 per Bbl of NGLs, respectively. Comparable prices as of February 14, 2013, were $98.38 per Bbl, $3.51 per MMBtu, and

$41.03 per Bbl, respectively.

While changes in quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the

prices we receive are affected by quality, energy content, location, and transportation differentials for these products. Consistent with all prior

periods reported, our realized prices shown in the table above do not include the impact of cash settlements from derivative contracts.

Derivative Activity

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy

governing our use of derivatives. The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet and the

level of capital commitments and long-term obligations we have in place. With our current derivative contracts, we believe we have established a base

cash flow stream for our future operations and have partially reduced our exposure to volatility in commodity prices. We utilize swaps as well as

costless collars for a portion of our derivatives since collars allow us to participate in some of the upward movements in oil, gas, and NGL prices

while also setting a price floor for a portion of our production. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of

this report for additional information regarding our oil, gas, and NGL derivatives, and the caption, Summary of Oil, Gas, and NGL Derivative

Contracts in Place, below.

The following table presents a reconciliation from our realized price to our adjusted price for the commodities indicated, including the

effects of derivative cash settlements, for 2012, 2011, and 2010:

For the Years Ended December 31,

2012 2011 2010

Crude Oil (per Bbl):

Realized price $ 85.45 $ 88.23 $ 72.65

Less the effects of derivative cash settlements (1.93) (9.34) (5.80)

Adjusted price, including the effects of derivative cash settlements $ 83.52 $ 78.89 $ 66.85

Natural Gas (per Mcf):

Realized price $ 2.98 $ 4.32 $ 5.21

Add the effects of derivative cash settlements 0.50 0.48 0.84

Adjusted price, including the effects of derivative cash settlements $ 3.48 $ 4.80 $ 6.05

Natural Gas Liquids (per Bbl):

Realized price $ 37.61 $ 53.32 $ —

Add (less) the effects of derivative cash settlements 1.29 (5.42) —

Adjusted price, including the effects of derivative cash settlements $ 38.90 $ 47.90 $ —

 

Note: 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the

volumes. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices above.

The Dodd-Frank Act included provisions requiring over-the-counter derivative transactions to be executed through an exchange or centrally

cleared. On July 10, 2012, the CFTC and the SEC adopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms and

determine what types of transactions will be subject to heightened scrutiny under the Dodd-Frank Act swap rules. The issuance of these final rules

also triggers compliance dates for a number of other final Dodd-Frank Act rules, including new rules proposed by the CFTC governing margin

requirements for uncleared swaps entered into by non-bank swap entities, and new rules proposed

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by U.S. banking regulators regarding margin requirements for uncleared swaps entered into by bank swap entities. The ultimate effect on our business

of these new rules and any additional regulations is currently uncertain. Under CFTC rules we believe our derivative activity will qualify for the nonfinancial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap

clearing requirement. However, we are not certain whether the provisions of the final rules and regulations will exempt us from the requirements to

post margin in connection with commodity price risk management activities. Final rules and regulations on major provisions of the legislation, such as

new margin requirements, are to be established through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings,

new rules and regulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use to

manage our financial risks related to volatility in oil, gas, and NGL commodity prices.

2012 Highlights

Operational Activities. We operated between 15 and 18 drilling rigs company-wide for most of 2012. The primary focus of our operated

drilling activity this year was oil and NGL-rich gas projects. We also participated in non-operated drilling activity primarily in oil and NGL-rich plays.

In our Eagle Ford shale program in South Texas, we operated six rigs throughout most of 2012 until releasing one of our operated rigs at the

end of the third quarter due to increased drilling rig efficiencies. We focused our drilling in areas with higher BTU gas content and condensate yields.

We believe we have secured most of the requisite services, such as gas pipeline takeaway capacity and drilling and completion services, to support our

current development plans. We will continue to explore additional arrangements to facilitate the continued growth of our operated program. Please

refer to Note 6 – Commitments and Contingencies under Part II, Item 8 of this report and Delivery Commitments and Core Operational

Areas under Part I, Items 1 and 2 of this report for additional discussion concerning these agreements.

In our non-operated Eagle Ford program, the operator had nine drilling rigs and one spudder rig running throughout 2012. We expect the

majority of our non-operated Eagle Ford drilling and completion costs to be funded by Mitsui over approximately the next two years under the terms

of our previously announced Acquisition and Development Agreement.

We started 2012 operating three drilling rigs in our Bakken/Three Forks program in the North Dakota portion of the Williston Basin and

increased to four drilling rigs in the third quarter, focusing on our Gooseneck, Raven, and Bear Den prospects. In the southern portion of our Rocky

Mountain region, we operated one rig testing various formations in the Powder River Basin of Wyoming as part of our exploration program.

Effective January 1, 2012, we combined our ArkLaTex region into our Mid-Continent region, based in Tulsa, Oklahoma, for operational

and reporting purposes. Throughout 2012, we operated three drilling rigs in our Granite Wash program in western Oklahoma and the Texas Panhandle,

focusing primarily on the Marmaton washes due to their higher oil and NGL content. Essentially all of our acreage position in this play is held by

production. We completed our operated Haynesville shale program early in the year after achieving held by production status on substantially all of our

acreage.

In our Permian region, we began the year with one operated rig and increased to four during the third quarter of 2012, with two of the rigs

testing the Mississippian limestone formation on our properties in the northeast Midland Basin where we have approximately 65,500 net acres. A third

rig focused on the Bone Spring formation on our properties in New Mexico. Finally, the fourth rig operated in the Midland Basin, focusing on testing

the Leonard shale. We added approximately 38,000 net acres to our Permian Basin Texas acreage position in 2012.

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Production Results. The table below provides a regional breakdown of our 2012 production:

South Texas

& Gulf Coast

Rocky

Mountain Mid-Continent Permian Total (1)

Production:

Oil (MMBbl) 3.2 5.4 0.4 1.3 10.4

Gas (Bcf) 59.1 4.4 53.4 3.2 120.0

NGLs (MMBbl) 5.7 — 0.4 — 6.1

BCFE (1) 112.7 36.9 58.1 11.3 218.9

Avg. Daily Equivalents

(MMCFE/d) 307.9 100.9 158.6 30.8 598.2

Relative percentage 51% 17% 27% 5% 100%

(1) Totals may not sum or recalculate due to rounding.

We had record production in 2012, which was primarily driven by the development of our operated and non-operated Eagle Ford shale

programs in our South Texas & Gulf Coast region. Please refer to Comparison of Financial Results and Trends between 2012 and 2011

below for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development

activities, whether capitalized or expensed, are summarized as follows:

For the Year Ended

December 31, 2012

(in millions)

Development costs $ 1,346.2

Exploration costs 220.9

Acquisitions

Proved properties 5.8

Unproved properties 115.0

Total, including asset retirement obligation $ 1,687.9

The majority of costs incurred for oil and gas producing activities during 2012 related to the development of our Eagle Ford shale and

Bakken/Three Forks programs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect

to fund our capital program in 2013.

Impairment of Proved Properties. We recorded impairment of proved properties expense of $208.9 million for the year ended

December 31, 2012, related to the write-down of our Wolfberry assets in our Permian region due to downward engineering revisions, as well as

write-downs of our Haynesville shale assets due to low natural gas prices.

Divestiture Activity and Unsuccessful Sale of Properties. During 2012, we divested of various non-strategic properties located in our

Rocky Mountain and Mid-Continent regions for $57.4 million in total divestiture proceeds. Additionally in 2012, we reclassified assets located in

both regions that were previously classified as held for sale to assets held and used, as these assets were no longer being actively marketed, which

resulted in a $33.9 million non-cash loss. Please refer to Note 3 - Divestitures and Assets Held for Sale in Part II, Item 8 of this report for

additional discussion. 

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Equity Compensation. During 2012, we granted 379,332 RSUs and 314,853 PSUs pursuant to our long-term equity compensation

program. Additionally, we issued 929,375 shares of our common stock to settle PSU and RSU awards granted in previous years. Please refer to

Note 7 - Compensation Plans in Part II, Item 8 of this report for additional discussion.

3.50% Senior Convertible Notes. In April 2012, we called for the redemption of our outstanding 3.50% Senior Convertible Notes,

which triggered the conversion feature of these notes. We settled the principal amount of all converted 3.50% Senior Convertible Notes in cash with

the excess value settled in shares of common stock, and settled all redeemed notes in cash. Please refer to Note 5 - Long-term Debt in Part II, Item 8

of this report for additional discussion.

2023 Notes. In June 2012, we issued $400.0 million in aggregate principal amount of 6.50% Senior Notes. The notes were issued at par and

mature on January 1, 2023. We received net proceeds of $392.1 million from this issuance, which we used to pay down outstanding borrowings

under our credit facility. Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion.

Marketing of Properties. During the second quarter of 2012, we began to re-market our Marcellus shale assets located in Pennsylvania.

Please refer to Note 3 - Divestitures and Assets Held for Sale in Part II, Item 8 of this report, as well as Legal Proceedings in Part I, Item 3 of

this report for additional discussion.

Credit Facility. In the third quarter of 2012, the borrowing base under our credit facility was increased by our lenders to $1.55 billion

from $1.4 billion. Please refer to Overview of Liquidity and Capital Resources below for additional discussion.

Outlook for 2013

We enter 2013 with a capital program of approximately $1.5 billion, of which approximately $1.2 billion will be focused on drilling and

completion activities. We expect that approximately 90 percent of our drilling budget will be spent on our operated Eagle Ford shale, Bakken/Three

Forks and operated Permian programs.

In 2013, we plan to invest approximately $650 million of drilling and completion capital in our operated Eagle Ford shale play. Throughout

2013, we plan to operate five drilling rigs supported by two frac spreads, all of which will be primarily focused on pad drilling in the northern portion

of our acreage position where there is a higher liquid contribution to our production mix. In 2013, our firm contracted wet gas takeaway capacity will

increase with the addition of incremental capacity on existing pipelines and the addition of a third pipeline with firm transportation capacity contracted

to begin in the third quarter. During 2013, we plan to continue to refine our development program and well designs to optimize well performance and

capital efficiency.

In our non-operated Eagle Ford shale program, the operator is currently operating nine drilling rigs and one spudder rig. Based on the

operator’s stated plans, our expectation is that the number of rigs will decrease to eight drilling rigs and one spudder rig during the year. Mitsui will

carry the majority of our non-operated drilling activity through 2013, so we expect to deploy minimal drilling and completion capital in this program.

Costs associated with items such as infrastructure are not carried by Mitsui, and we will be responsible for our proportionate share of those costs.

We plan to deploy $290 million of our capital budget in our Bakken/Three Forks program in the Williston Basin in 2013. Currently, we are

operating four drilling rigs in this program and plan to operate an average of 3.5 drilling rigs throughout the year. Our plan with these rigs is to

continue infill drilling in our three focus areas and leverage efficiencies through pad drilling.

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In our Permian program, we plan to deploy approximately $170 million of drilling and completion capital. Our program will focus two

drilling rigs in our Mississippian limestone play as we continue to delineate our position of approximately 65,500 net acres. During the year, we will

also continue to run an exploratory program in the Midland Basin testing various shale formations.

The remaining $90 million of our drilling and completion capital planned for this year will be deployed in our operated Granite Wash program

and various other operated and non-operated programs. Our Granite Wash program will have one to two operated rigs, while the remainder of the

activity will be in our exploration plays, including on our Powder River Basin acreage.

Please refer to Overview of Liquidity and Capital Resources for additional discussion regarding how we intend to fund our 2013

capital program.

Financial Results of Operations and Additional Comparative Data

The table below provides information regarding selected production and financial information for the quarter ended December 31, 2012, and

the immediately preceding three quarters. Additional details of per MCFE costs are presented later in this section.

For the Three Months Ended

December 31, September 30, June 30, March 31,

2012 2012 2012 2012

(in millions, except for production data)

Production (BCFE) 60.7 57.0 50.6 50.7

Oil, gas, and NGL production revenue $ 424.7 $ 373.9 $ 312.6 $ 362.6

Realized hedge gain $ 1.5 $ 0.5 $ 0.2 $ 1.7

Gain (loss) on divestiture activity $ 4.2 $ (8.5) $ (24.2) $ 1.5

Lease operating expense $ 48.0 $ 46.5 $ 46.1 $ 39.4

Transportation costs $ 43.0 $ 37.0 $ 30.3 $ 28.6

Production taxes $ 20.2 $ 18.9 $ 14.7 $ 19.1

DD&A $ 204.3 $ 192.4 $ 161.6 $ 169.6

Exploration $ 24.2 $ 25.4 $ 22.0 $ 18.6

Impairment of proved properties $ 170.4 $ — $ 38.5 $ —

Abandonment and impairment of unproved properties $ 5.0 $ 0.4 $ 10.7 $ 0.1

General and administrative $ 28.4 $ 32.2 $ 31.1 $ 28.1

Change in Net Profits Plan liability $ (11.6) $ 0.8 $ (22.1) $ 3.9

Unrealized and realized derivative (gain) loss $ (15.6) $ 55.9 $ (98.1) $ 2.2

Net income (loss) $ (67.1) $ (38.3) $ 24.9 $ 26.3

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Selected Performance Metrics:

For the Three Months Ended

December 31, September 30, June 30, March 31,

2012 2012 2012 2012

Average net daily production equivalent (MMCFE per

day) 659.6 619.6 555.7 557.0

Lease operating expense (per MCFE) $ 0.79 $ 0.82 $ 0.91 $ 0.78

Transportation costs (per MCFE) $ 0.71 $ 0.65 $ 0.60 $ 0.56

Production taxes as a percent of oil, gas, and NGL

production revenue 4.8% 5.1% 4.7% 5.3%

Depletion, depreciation and amortization and asset

retirement obligation liability accretion (per MCFE) $ 3.37 $ 3.38 $ 3.20 $ 3.35

General and administrative (per MCFE) $ 0.47 $ 0.56 $ 0.62 $ 0.56

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A year-to-year overview of selected production and financial information, including trends:

As of and for the Years Ended

December 31,

Amount Change Between Percent Change Between

2012 2011 2010 2012/2011 2011/2010 2012/2011 2011/2010

Net production volumes (1)

Oil (MMBbl) 10.4 8.1 6.4 2.3 1.7 28 % 27 %

Gas (Bcf) 120.0 100.3 71.9 19.7 28.5 20 % 40 %

NGLs (MMBbl) 6.1 3.5 — 2.6 3.5 75 % N/A

BCFE 218.9 169.7 110.0 49.2 59.7 29 % 54 %

Average net daily production (1)

Oil (MBbl per day) 28.3 22.1 17.4 6.2 4.7 28 % 27 %

Gas (MMcf per day) 328.0 274.8 196.9 53.1 78.0 19 % 40 %

NGLs (MBbl per day) 16.7 9.6 — 7.1 9.6 75 % N/A

Equivalent (MMCFE per day) 598.2 465.0 301.4 133.2 163.6 29 % 54 %

Oil, gas, and NGL production revenues

(in millions)

Oil production revenue $ 886.2 $ 712.8 $ 461.9 $ 173.4 $ 250.9 24 % 54 %

Gas production revenue $ 357.7 $ 433.4 $ 374.4 $ (75.7) $ 59.0 (17)% 16 %

NGL production revenue $ 230.0 $ 186.2 $ — $ 43.8 $ 186.2 24 % N/A

Total $ 1,473.9 $ 1,332.4 $ 836.3 $ 141.5 $ 496.1 11 % 5 9 %

Oil, gas, and NGL production expense (in

millions)

Lease operating expenses $ 180.1 $ 149.8 $ 121.5 $ 30.3 $ 28.3 20 % 23 %

Transportation costs $ 138.9 $ 86.4 $ 21.2 $ 52.5 $ 65.2 61 % 308 %

Production taxes $ 72.9 $ 53.9 $ 52.4 $ 19.0 $ 1.5 35 % 3 %

Total $ 391.9 $ 290.1 $ 195.1 $ 101.8 $ 95.0 35 % 49 %

Realized price

Oil (per Bbl) $ 85.45 $ 88.23 $ 72.65 $ (2.78) $ 15.58 (3)% 21 %

Gas (per Mcf) $ 2.98 $ 4.32 $ 5.21 $ (1.34) $ (0.89) (31)% (17)%

NGLs (per Bbl) $ 37.61 $ 53.32 $ — $ (15.71) $ 53.32 (29)% N/A

Per MCFE $ 6.73 $ 7.85 $ 7.60 $ (1.12) $ 0.25 (14)% 3 %

Per MCFE data

Production costs:

 Lease operating expense $ 0.82 $ 0.88 $ 1.10 $ (0.06) $ (0.22) (7)% (20)%

 Transportation costs $ 0.63 $ 0.51 $ 0.19 $ 0.12 $ 0.32 24 % 168 %

 Production taxes $ 0.33 $ 0.32 $ 0.48 $ 0.01 $ (0.16) 3 % (33)%

General and administrative $ 0.55 $ 0.70 $ 0.97 $ (0.15) $ (0.27) (21)% (28)%

Depletion, depreciation and amortization

and asset retirement obligation liability

accretion $ 3.32 $ 3.01 $ 3.06 $ 0.31 $ (0.05) 10 % (2)%

Derivative cash settlement (gain) loss(2) $ (0.22) $ 0.27 $ (0.22) $ (0.49) $ 0.49 (181)% (223)%

Earnings per share information

Basic net income (loss) per common share $ (0.83) $ 3.38 $ 3.13 $ (4.21) $ 0.25 (125)% 8 %

Diluted net income (loss) per common

share $ (0.83) $ 3.19 $ 3.04 $ (4.02) $ 0.15 (126)% 5 %

Basic weighted-average common shares

outstanding (in thousands) 65,138 63,755 62,969 1,383 786 2 % 1 %

Diluted weighted-average common shares

outstanding (in thousands) 65,138 67,564 64,689 (2,426) 2,875 (4)% 4 %

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(1) Amount and percentage changes may not recalculate due to rounding.

(2) Derivative cash settlements are included within the realized hedge gain (loss) and unrealized and realized derivative (gain) loss line items in the

accompanying statements of operations.

Note: 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the

volumes. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices above.

We present per MCFE information because we use this information to evaluate our performance relative to our peers and to identify and

measure trends we believe may require analysis. Average daily production for the year ended December 31, 2012, increased 29 percent compared to

the same period in 2011, driven by the development of our Eagle Ford shale program and a substantial increase in production from our Bakken/Three

Forks program.

Changes in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our realized price on a per MCFE

basis for the year ended December 31, 2012, decreased 14 percent compared with the same period in 2011. The decrease in realized price is due to an

overall decline in commodity prices, most significantly gas and NGL prices, during 2012.

LOE on a per MCFE basis for the year ended December 31, 2012, decreased seven percent compared with the same period in 2011.

Absolute dollars for LOE in all regions increased in 2012, however production increased at a faster rate thereby reducing LOE on a per MCFE basis.

Additionally, the 2011 divestiture of certain of our non-strategic Mid-Continent region properties, which had meaningfully higher per unit operating

costs, reduced our LOE on a per MCFE basis for the year ended December 31, 2012. LOE in our South Texas & Gulf Coast region decreased in

the second half of 2012 due to cost saving initiatives in the region. Based upon the current level of industry activity, we believe that LOE on a per

MCFE basis will remain stable throughout 2013.

Transportation costs on a per MCFE basis for the year ended December 31, 2012, increased 24 percent compared to the same period in

2011. This is a result of increased production in our Eagle Ford shale program, where our transportation arrangements have higher per unit costs

compared with our other regions. We anticipate transportation costs will continue to increase on a per MCFE basis as our Eagle Ford shale program

becomes a larger portion of our total production.

Production taxes on a per MCFE basis for the year ended December 31, 2012, increased three percent compared with the same period in

2011. In the second quarter of 2011, we were notified that we qualified for severance tax incentive rebate programs for wells meeting specific criteria

in certain areas of Texas. A sizable incentive tax rebate was recorded in the second quarter of 2011, significantly decreasing the per MCFE rate for

the year ended December 31, 2011. We expect our future operated wells drilled in these areas to qualify for incentive tax rebate programs. We

generally expect production taxes to trend with oil, gas, and NGL revenues.

General and administrative expense on a per MCFE basis for the year ended December 31, 2012, decreased 21 percent compared with the

same period in 2011, as production increased at a faster rate than our general and administrative expense. A portion of our general and administrative

expense is linked to our profitability and cash flow, which are driven in large part by the realized commodity prices we receive for our production.

The Net Profits Plan and a portion of our short-term incentive compensation program correlate with net cash flows and therefore are subject to

variability.

DD&A expense, for the year ended December 31, 2012, increased 10 percent, on a per MCFE basis, compared with the same period in

2011. Our DD&A rate increased as a result of the transfer of a portion of our non-operated working interest to Mitsui, which reduced our reserve

base but had no impact on the carrying value of our assets. As we utilize our carry with Mitsui, we expect our DD&A rate to improve as we add

reserves without incurring capital costs. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning

Agreement in Part II, Item 8 of this report for additional discussion on the Mitsui transaction. Our DD&A rate can

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fluctuate as a result of impairments, divestitures, and changes in the mix of our production and the underlying proved reserve volumes. Additionally,

the accounting treatment for assets that are classified as held for sale can also impact our DD&A rate since these properties are no longer depleted.

Please refer to Comparison of Financial Results and Trends between 2012 and 2011 for additional discussion on oil, gas, and NGL

production expense, DD&A, and general and administrative expense.

Please refer to the section Earnings per Share in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this

report for additional discussion on the types of shares included in our basic and diluted net income (loss) per common share calculations. During the

second quarter of 2012, all of our outstanding 3.50% Senior Convertible Notes were redeemed or net share settled following conversion. The shares

issued upon conversion are reflected in our basic weighted-average common shares outstanding calculations for the year ended December 31, 2012.

We recorded a net loss for the year ended December 31, 2012. Consequently, our in-the-money stock options, unvested RSUs, and contingent PSUs

were anti-dilutive for the year resulting in a decrease in the diluted weighted-average common shares outstanding when compared with the year ended

December 31, 2011. Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion on our 3.50% Senior

Convertible Notes.

Comparison of Financial Results and Trends between 2012 and 2011

Oil, gas, and NGL production revenue. The following table presents the regional changes in our production and oil, gas, and NGL

revenues and costs between the years ended December 31, 2012, and 2011:

Average Net Daily

Production Added (Lost)

Oil, Gas & NGL

Revenue Added (Lost)

Production Costs

Increase

(MMCFE/d) (in millions) (in millions)

South Texas & Gulf Coast 116.8 $ 137.0 $ 68.9

Rocky Mountain 27.7 113.1 26.1

Mid-Continent (10.6) (92.1) 2.3

Permian (0.7) (16.5) 4.5

Total 133.2 $ 141.5 $ 101.8

The largest regional production increase occurred in the South Texas & Gulf Coast region as a result of drilling activity in our Eagle Ford

shale program. Production in our Eagle Ford shale program continues to increase and we expect it to do so for the next several years. We also saw an

increase in production in our Rocky Mountain region as a result of strong production performance from wells drilled in our Bakken/Three Forks

program in late 2011 and throughout 2012.

The following table summarizes the realized prices we received in 2012 and 2011, before the effects of derivative cash settlements:

For the Years Ended December 31,

2012 2011

Realized oil price ($/Bbl) $ 85.45 $ 88.23

Realized gas price ($/Mcf) $ 2.98 $ 4.32

Realized NGL price ($/Bbl) $ 37.61 $ 53.32

Realized equivalent price ($/MCFE) $ 6.73 $ 7.85

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A 29 percent increase in production on an equivalent basis combined with a 14 percent decrease in realized price per MCFE resulted in an

11 percent increase in revenue between the two periods. Based on current levels of activity, we expect production volumes to increase annually for

the next several years. We also expect our realized prices to trend with commodity prices.

Realized hedge gain (loss). We recorded a net realized hedge gain of $3.9 million for the year ended December 31, 2012, compared with

a net realized hedge loss of $20.7 million for the same period in 2011. These amounts are comprised of realized cash settlements on commodity

derivative contracts that were designated as cash flow hedges and were previously recorded in accumulated other comprehensive income (loss)

(“AOCIL”). Our realized oil, gas, and NGL hedge gains and losses are a function of commodity prices at the time of settlement compared with the

respective derivative contract prices.

Gain (loss) on divestiture activity. We recorded a net loss on divestiture activity of $27.0 million for the year ended December 31, 2012,

compared with a net gain of $220.7 million for the comparable period of 2011. The net loss on divestiture activity for the year ended December 31,

2012, is due to a loss on unsuccessful property sale efforts and the write-down of certain assets held for sale to their fair value. This loss was offset

partially by a net gain on completed divestitures. The net gain for the year ended December 31, 2011, relates to the divestitures of oil and gas

properties located in our South Texas & Gulf Coast, Rocky Mountain, and Mid-Continent regions. We will continue to evaluate our portfolio to

determine whether there are non-strategic properties we could divest. Please refer to Divestiture Activity and Unsuccessful Sale of Properties

above and Note 3 - Assets Held for Sale in Part II, Item 8 of this report for additional discussion.

Marketed gas system revenue and expense. Marketed gas system revenue decreased to $52.8 million for the year ended December 31,

2012, compared with $69.9 million for the comparable period of 2011, as a result of lower production in the Mid-Continent region and declining gas

prices. Concurrent with the decrease in marketed gas system revenue, marketed gas system expense decreased to $47.6 million for the year ended

December 31, 2012, from $64.2 million for the comparable period of 2011. There was no significant change in our net margin. We expect that

marketed gas system revenue and expense will continue to correlate with increases and decreases in production and our realized gas price.

Oil, gas, and NGL production expense. Total production costs increased $101.8 million, or 35 percent, to $391.9 million for the year

ended December 31, 2012, compared with $290.1 million in 2011, primarily due to a 29 percent increase in net production volumes on an equivalent

basis. Please refer to our caption A year-to-year overview of selected production and financial information, including trends above for

discussion of production costs on a per MCFE basis.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense increased 42 percent

to $727.9 million in 2012 compared with $511.1 million in 2011 due to an increase in our depreciable asset base as a result of continued

development of our Eagle Ford and Bakken/Three Forks assets and the associated growth of our production. Please refer to our caption A year-toyear overview of selected production and financial information, including trends above for discussion of DD&A expense on a per

MCFE basis.

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Exploration. The components of exploration expense are summarized as follows:

For the Years Ended December 31,

2012 2011

Summary of Exploration Expense (in millions)

Geological and geophysical expenses $ 13.6 $ 7.3

Exploratory dry hole 20.9 0.3

Overhead and other expenses 55.7 45.9

Total $ 90.2 $ 53.5

Exploration expense for 2012 increased 69 percent compared with the same period in 2011 as a result of wells categorized as exploratory

being classified as dry during the year, as well as an increase in exploration overhead and geological and geophysical expenses (“G&G”) due to an

increase in our exploration efforts. An exploratory project resulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry

hole and impacts the amount of exploration expense we record.

Impairment of proved properties. We recorded impairment of proved properties expense of $208.9 million for the year ended

December 31, 2012. The impairments were a result of write-downs of our Wolfberry assets in our Permian region due to downward engineering

revisions, as well as write-downs of our Haynesville shale assets due to low natural gas prices. We recorded impairment of proved properties expense

of $219.0 million for the comparable period in 2011 related to legacy assets located in our Mid-Continent region as a result of depressed natural gas

prices.

Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved properties expense of

$16.3 million for the year ended December 31, 2012, the majority of which related to acreage we no longer intend to develop in our Rocky Mountain

and Mid-Continent regions. We recorded $7.4 million of abandonment and impairment of unproved properties expense for the comparable period in

2011, primarily associated with lease expirations in our Mid-Continent region. We expect abandonment and impairment of unproved properties to

more likely occur in periods of low commodity prices, which negatively impact operating cash flows available for exploration and development, as

well as anticipated economic performance.

General and administrative. General and administrative expense increased slightly to $119.8 million for the year ended December 31,

2012, compared with $118.5 million for the same period in 2011. The change is due to an increase in employee headcount in 2012, which resulted in

an increase to base compensation, benefits, and general corporate office expenses incurred. These were mostly offset by an increase in COPAS

overhead reimbursement as a result of an increase in operated well count, as well as an overall decrease in accruals for cash bonus that reflect less

success at reaching performance metrics when compared with the prior year. Please refer to our caption A year-to-year overview of selected

production and financial information, including trends above for discussion of general and administrative costs on a per MCFE basis.

Change in Net Profits Plan liability. This non-cash expense generally relates to the change in the estimated value of the associated

liability between the reporting periods. For 2012, we recorded a non-cash benefit of $28.9 million compared to a non-cash benefit of $25.5 million

in 2011. The change in our liability is subject to estimation and may change dramatically from period to period based on assumptions used for

production rates, reserve quantities, commodity pricing, discount rates, and production costs. Payments made to participants as a result of divestitures

and ongoing operations will also impact our liability. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for the

impact a direct payment made to cash-out several pools had on our change in Net Profits Plan liability in 2011.

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Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative gain of $55.6 million in 2012

compared to a gain of $37.1 million for the same period in 2011. Declining commodity prices in both periods resulted in favorable derivative

positions and settlements. These amounts include the change in fair value of commodity derivative contracts and realized cash settlement gains or

losses on derivatives for which unrealized changes in fair value were not previously recorded in AOCIL. Please refer to Note 10 - Derivative

Financial Instruments in Part II, Item 8 of this report for additional discussion.

Other operating expense. Other operating expense was $7.0 million in 2012 compared with $17.6 million in 2011. The decrease is a

result of commissions and legal costs incurred in 2011 associated with our Acquisition and Development Agreement with Mitsui, as well as legal

costs incurred related to the arbitration proceedings involving Anadarko E&P Company, LP during the second half of 2011. Please refer to Note 12 -

Acquisition and Development Agreement and Carry and Earning Agreement, in Part II, Item 8 of this report for additional discussion of

our Acquisition and Development Agreement.

Income tax benefit (expense). We recorded an income tax benefit of $29.3 million for 2012 compared to an expense of $123.6 million

for 2011, resulting in effective tax rates of 35.0 percent and 36.5 percent, respectively. The net decrease in the rate reflects differing effects

between years of the individual components of our tax rate. Comparable valuation allowance amounts recorded on state net operating losses and

charitable contributions in each of the two years had the effect of increasing the 2011 rate of expense while decreasing the 2012 benefit rate. The

impacts from these two items were mostly offset by the effect from recognized research and development credit benefits. Other 2012 net decreases in

the effective rate resulted from changes in the mix of the highest marginal state tax rates, the differing effects from percentage depletion and other

permanent differences. The current income tax expense in 2012 was $370,000 compared with the income tax benefit of $204,000 in 2011 which

included a federal carryback amount. 

In January 2013 federal legislation was passed extending the R&D credit to our 2012 and 2013 tax years. Since the legislation was not

passed as of December 31, 2012, our 2012 income tax benefit does not reflect an impact for 2012 credit amounts. As of the filing date of this report

we have not prepared a study for 2012 while we await the outcome of an on-going audit for R&D credits claimed for our 2007 through 2010 tax

years. We are uncertain of when we may complete a study or the impact calculated 2012 and 2013 R&D tax credits would have on our income tax

expense and tax rates for 2013. Even with a R&D credit, we expect our tax rate to be higher in 2013.

Comparison of Financial Results between 2011 and 2010

Oil, gas and NGL production revenue. Average daily production for the year ended December 31, 2011, increased 54 percent to 465.0

MMCFE, compared with 301.4 MMCFE for the same period in 2010. The following table presents the regional changes in our production and oil,

gas, and NGL revenues and costs between the two years. Effective January 1, 2012, we combined our ArkLaTex region into our Mid-Continent

region, based in Tulsa, Oklahoma, for operational and reporting purposes. Prior period presentation has been conformed to reflect this change.

Average Net Daily Production

Added (Lost)

Oil and Gas Revenue Added

(Lost)

Production Costs Increase

(Decrease)

(MMCFE/d) (in millions) (in millions)

South Texas & Gulf Coast 129.0 $ 348.9 $ 79.0

Rocky Mountain 4.9 96.1 12.2

Mid-Continent 38.4 63.3 4.1

Permian (8.7) (12.2) (0.3)

Total 163.6 $ 496.1 $ 95.0

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The largest regional production increase occurred in the South Texas & Gulf Coast region as a result of production from drilling activity in

our Eagle Ford shale program. We also saw an increase in production in our Mid-Continent region as a result of strong production performance from

wells drilled in our Haynesville shale program in late 2010 and early 2011.

The following table summarizes the average realized prices we received in 2011 and 2010, before the effects of derivative cash settlements:

For the Years Ended December 31,

2011 2010

Realized oil price ($/Bbl) $ 88.23 $ 72.65

Realized gas price ($/Mcf) $ 4.32 $ 5.21

Realized NGL price ($/Bbl) $ 53.32 $ —

Realized equivalent price ($/MCFE) $ 7.85 $ 7.60

Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of 2011, we

changed our reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing consistent with title

transfer for each product. 

The three percent increase in average realized prices per MCFE coupled with a 54 percent increase in production volumes between periods

resulted in a meaningful increase in revenue.

Realized hedge gain (loss). We recorded a net realized hedge loss of $20.7 million for the year ended December 31, 2011, compared

with a net realized hedge gain of $23.5 million for the same period in 2010. The realized net loss in 2011 is comprised of realized cash settlements on

commodity contracts that were previously recorded in AOCL, whereas the realized net gain in 2010 is comprised of realized cash settlements on all

commodity derivative contracts.

Gain (loss) on divestiture activity. We recorded a gain on divestiture activity of $220.7 million, which was net of the $27.5 million

write-down related to our Marcellus shale assets, for the year ended December 31, 2011, compared with a gain of $155.3 million for the comparable

period of 2010. The 2011 gain related to the divestitures of oil and gas properties located in our South Texas & Gulf Coast, Rocky Mountain, and

Mid-Continent regions. The 2010 gain related to the divestitures of oil and gas properties located in our Rocky Mountain and Permian regions.

Marketed gas system revenue and expense. Marketed gas system revenue was $69.9 million for the year ended December 31, 2011,

which was relatively flat compared to $70.1 million for the year ended December 31, 2010. Concurrent with the decrease in marketed gas system

revenue, marketed gas system expense decreased to $64.2 million for the year ended December 31, 2011, from $66.7 million for the comparable

period of 2010.

Oil and gas production expense. Total production costs increased $95.0 million, or 49 percent, to $290.1 million for the year ended

December 31, 2011, compared with $195.1 million in 2010 due primarily to a 54 percent increase in equivalent production volumes in 2011. Total

oil, gas, and NGL production costs per MCFE decreased $0.06 to $1.71 for the year ended December 31, 2011, compared with $1.77 in 2010, due

to a decrease in recurring LOE resulting from the sale of non-strategic properties with higher per unit LOE costs, as well as a decrease in production

taxes per MCFE due to severance tax incentives in our South Texas & Gulf Coast and Mid-Continent regions. These decreases were offset slightly

by an increase in transportation costs per MCFE, which was primarily a result of increased production in our Eagle Ford shale program where our

transportation agreements have higher per unit transportation costs due to the lack of infrastructure in the emerging play.

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Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense increased 52 percent

to $511.1 million for the year ended December 31, 2011, compared with $336.1 million in 2010. The increase in overall DD&A expense was due

to increased production. DD&A expense per MCFE decreased two percent to $3.01 for the year ended December 31, 2011, compared to $3.06 in

2010 due to an increase in our reserve base and production volumes, while our property balances remained relatively constant between the two periods.

Exploration. The components of exploration expense are summarized as follows:

For the Years Ended December 31,

2011 2010

Summary of Exploration Expense (in millions)

Geological and geophysical expenses $ 7.3 $ 21.5

Exploratory dry hole 0.3 0.3

Overhead and other expenses 45.9 42.1

Total $ 53.5 $ 63.9

Exploration expense in 2011 decreased 16 percent compared to the same period in 2010 due to a reduction in geological and geophysical

expense, as a result of a decrease in our exploration efforts in 2011. The increase in exploration overhead costs related to equity incentive

compensation expense as discussed under General and administrative below.

Impairment of proved properties. We recorded $219.0 million of impairment of proved properties expense in 2011, compared to $6.1

million in 2010. The impairment in 2011 related to assets located in our Mid-Continent region that were impacted by significantly lower natural gas

prices in the second half of 2011.

Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved properties expense of

$7.4 million for the year ended December 31, 2011, associated with lease expirations in our Mid-Continent region. We recorded $2.0 million of

abandonment and impairment of unproved properties expense for the comparable period in 2010, associated with lease expirations in our Rocky

Mountain and Mid-Continent regions.

General and administrative. General and administrative expense increased 11 percent to $118.5 million for the year ended

December 31, 2011, compared with $106.7 million for the same period in 2010. The change was due to an increase in base and equity incentive

compensation and accruals for cash bonuses, as well as an increase in corporate office expenses as a result of an increase in employee headcount

between the two periods. General and administrative expense per MCFE decreased $0.27 to $0.70 per MCFE for the year ended December 31, 2011,

compared to $0.97 in 2010, mostly due to our production increasing at a faster rate than our general and administrative expense.

Change in Net Profits Plan liability. For 2011, the change in the Net Profits Plan liability, a non-cash item, was a $25.5 million benefit

compared to a $34.4 million benefit in 2010. This non-cash charge or benefit is directly related to the change in the estimated value of the associated

liability between the reporting periods. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for the impact a direct

payment made to cash-out several pools had on our change in Net Profits Plan liability in 2011.

Unrealized and realized derivative (gain) loss. We recognized an unrealized and realized derivative gain of $37.1 million in 2011

compared to a loss of $8.9 million for the same period in 2010. The 2011 amount includes gains resulting from unrealized changes in fair value on

commodity derivative contracts of $62.8 million and realized cash settlement losses on derivatives for which unrealized changes in fair value were not

previously recorded in other comprehensive loss of $25.7 million. The 2010 activity is comprised solely of the ineffective portion of derivatives

designated as cash flow hedges.

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Other operating expense. Other operating expense was $17.6 million in 2011 compared with $3.0 million in 2010. The increase was a

result of commission and legal costs associated with our Acquisition and Development Agreement with Mitsui, as well as legal costs related to the

arbitration proceedings against Anadarko E&P Company, LP during the second half of 2011.

Income tax benefit (expense). Income tax expense totaled $123.6 million for 2011 compared to tax expense of $118.1 million for

2010, resulting in effective tax rates of 36.5 percent and 37.5 percent, respectively. The effective rate change from 2010 primarily reflected changes

in the mix of the highest marginal state tax rates, a multi-year research and experimentation credit claim, an adjustment for anticipated utilization of

charitable contributions carryovers, and differing effects of other permanent differences including percentage depletion. The current income tax

benefit in 2011 was $204,000 compared with current income tax expense of $3.5 million in 2010. These amounts were three percent of the total

income tax expense for 2010 and were not material for 2011.

Overview of Liquidity and Capital Resources

We believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage

the duration and level of our drilling and completion services commitments in order to provide us with some flexibility to reduce activity and capital

expenditures in periods of prolonged commodity price decline.

Sources of cash

We currently expect our 2013 capital program to be partially funded by cash flows from operations, with an anticipated shortfall to be

funded by borrowings under our credit facility. Although we anticipate that cash flow from operations and borrowing capacity under our credit

facility will be sufficient to fund our expected 2013 capital program, we may also elect to access the capital markets, depending on prevailing market

conditions. The divestiture of certain oil and gas properties is also a potential source of funding and we will continue to evaluate our portfolio to

identify potential divestiture candidates.

Our primary sources of liquidity are the cash flows provided by our operating activities, borrowings under our credit facility, proceeds

received from divestitures of properties, and other financing alternatives, including accessing capital markets. From time to time, we may enter into

carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. All of our sources of

liquidity can be impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes

produced, all of which affect us and our industry. We have no control over the market prices for oil, gas, or NGLs, although we are able to influence

the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk

management program. The borrowing base under our credit facility could be reduced as a result of lower commodity prices, divestitures of producing

properties, or newly issued debt. See “Credit Facility” below for a discussion of our most recent borrowing base redetermination. Historically,

decreases in commodity prices have limited our industry’s access to capital markets.

In the second quarter of 2012, we issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023. Additionally, some

of the proceeds from our 2021 Notes issued in the fourth quarter of 2011 were available for use in 2012. In late 2011, we consummated our

Acquisition and Development Agreement with Mitsui pursuant to which Mitsui funds, or carries, 90 percent of certain drilling and completion costs

attributable to our remaining interest in our non-operated Eagle Ford shale acreage until $680.0 million has been expended on our behalf. Of the

original $680.0 million carry amount, $277.5 million had been spent as of December 31, 2012. The remaining carry is expected to be realized over

approximately the next two years. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement in

Part II, Item 8 of this report for additional discussion.

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Proposals to fund the federal government budget continue to include eliminating or reducing current tax deductions for intangible drilling

costs, the domestic production activities deduction, and percentage depletion. Legislation modifying or eliminating these deductions would have the

immediate effect of reducing operating cash flows thereby reducing funding available for our exploration and development capital programs and those

of our peers in the industry. If enacted, these funding reductions could have a significant adverse effect on drilling in the United States for a number

of years.

Credit facility

In May 2011, we entered into our Fourth Amended and Restated Credit Agreement, providing a $2.5 billion senior secured revolving credit

facility with a scheduled maturity date of May 27, 2016. In the third quarter of 2012, our borrowing base under the credit facility was increased to

$1.55 billion from $1.4 billion. Our borrowing base is subject to regular semi-annual redeterminations by our lenders and the next scheduled redetermination date is April 1, 2013. As of the filing date of this report, our lenders have committed to a current aggregate commitment amount of $1.0

billion under the credit agreement. We believe the current commitment amount is sufficient to meet our anticipated liquidity and operating needs.

Through the filing date of this report, we have experienced no issues utilizing our credit facility. No individual bank participating in our credit facility

represents more than 10 percent of the lending commitments under the credit facility.

The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under our credit

facility as of February 14, 2013, December 31, 2012, and December 31, 2011.

As of February 14, 2013 As of December 31, 2012 As of December 31, 2011

(in millions)

Credit facility balance $ 407.5 $ 340.0 $ —

Letters of credit (1) $ 0.8 $ 0.8 $ 0.6

Available borrowing capacity $ 591.7 $ 659.2 $ 999.4

(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.

Our daily weighted-average credit facility debt balance was approximately $171.8 million and $10.7 million for the years ended

December 31, 2012, and 2011, respectively. Borrowings under our credit facility are secured by mortgages on substantially all of our proved oil and

gas properties.

Weighted-average interest rates

Our weighted-average interest rates in the current and prior year include accrued interest payments, cash fees paid on the unused portion of

the credit facility’s aggregate commitment amount, letter of credit fees, amortization of the debt discount related to our 3.50% Senior Convertible

Notes through April 2, 2012, and amortization of deferred financing costs. Our weighted-average borrowing rate is calculated using only our

accrued interest and fee payments.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended

December 31, 2012, 2011, and 2010.

For the Years Ended December 31,

2012 2011 2010

Weighted-average interest rate 6.4% 8.5% 8.3%

Weighted-average borrowing rate 5.5% 5.2% 2.8%

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The decrease in our weighted-average interest rate from 2011 is a result of our Senior Notes being outstanding for all or a part of the year

ended December 31, 2012, with rates below the 2011 average interest rate, as well as a higher average balance on our revolving credit facility, which

provides a lower interest rate than all our fixed debt instruments and which reduces the fee paid on the unused portion of our aggregate commitment.

Our weighted-average borrowing rate for the year ended December 31, 2012, was impacted by the three tranches of high yield unsecured

debt we have issued since February 2011, as well as the redemption and settlement of our 3.50% Senior Convertible Notes that occurred in the second

quarter of 2012. Each tranche of high yield unsecured debt has a coupon rate that is higher than the coupon rate on the 3.50% Senior Convertible

Notes, and is also higher than the average borrowing rate on the credit facility incurred during 2011. This had the effect of increasing our average

borrowing rate since high yield unsecured debt replaced lower cost secured bank debt and our 3.50% Senior Convertible Notes.

We are subject to customary covenants under our credit facility, including limitations on dividend payments and requirements to maintain

certain financial ratios, which include debt to EBITDAX, as defined under the caption Non-GAAP Financial Measures below, of less than 4.0 to

1.0 and an adjusted current ratio, as defined by our credit agreement, of no less than 1.0. As of December 31, 2012, our debt to EBITDAX ratio and

adjusted current ratio, as defined by our credit agreement, were 1.40 and 1.81, respectively. As of the filing date of this report, we are in compliance

with all financial and non-financial covenants under our credit facility.

Uses of cash

We use cash for the acquisition, exploration, and development of oil and gas properties and for the payment of operating and general and

administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the exploration and development of oil and

gas properties are the primary use of our capital resources. During 2012, we spent $1.5 billion for exploration and development capital expenditures,

and leasehold acquisition. These amounts differ from the cost incurred amounts, which are accrual-based and include asset retirement obligation,

G&G, and exploration overhead amounts.

The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of available

acquisition and drilling opportunities, our cash flow from operating, investing, and financing activities, and our ability to assimilate acquisitions and

execute our drilling program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing

and results of our operated and non-operated development and exploratory activities may lead to changes in funding requirements for future

development. We regularly review our capital expenditure budget to assess changes in current and projected cash flows, potential acquisition and

divestiture activities, debt requirements, and other factors.

We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other

securities. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such

repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities

laws, and other factors. The amounts involved in any such transaction may be material.

As of the filing date of this report, subject to the approval of our Board of Directors, we could repurchase up to 3,072,184 shares of our

common stock under our stock repurchase program. Shares may be repurchased from time to time in open market transactions or privately negotiated

transactions, subject to market conditions and other factors, including certain provisions of our credit facility and the indentures governing our Senior

Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors reviews this program

as part of the allocation of our capital. During 2012, we did not repurchase any shares of our common stock, and we currently do not plan to

repurchase any outstanding shares.

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During 2012, we paid $6.5 million in dividends to our stockholders, which constitutes a dividend of $0.10 per share. Our intention is to

continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, credit facility and other

covenants, and other factors which could arise. Payment of future dividends remains at the discretion of our Board of Directors. Additionally, during

the second quarter of 2012 we paid $287.5 million to settle our 3.50% Senior Convertible Notes.

 

The following table presents changes in cash flows between the years ended December 31, 2012, 2011, and 2010, for our operating,

investing, and financing activities. The analysis following the table should be read in conjunction with our statements of cash flows in Part II, Item 8

of this report.

For the Years Ended

December 31, Amount of Changes Between Percent of Change Between

2012 2011 2010 2012/2011 2011/2010 2012/2011 2011/2010

(in millions)

Net cash provided by

operating activities $ 922.0 $ 760.5 $ 497.1 $ 161.5 $ 263.4 21 % 53 %

Net cash (used in)

investing activities $ (1,457.3) $ (1,264.9) $ (361.6) $ (192.4) $ (903.3) 15 % 250 %

Net cash provided by

(used in) financing

activities $ 422.1 $ 618.5 $ (141.1) $ (196.4) $ 759.6 (32)% (538)%

Analysis of cash flow changes between 2012 and 2011

Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash settlements, increased $256.5

million, or 21 percent, to $1.5 billion for the year ended December 31, 2012, compared with the same period in 2011. This increase was due to an

increase in production volumes and favorable derivative settlements resulting from declining commodity prices throughout the year. Cash paid for

lease operating expenses in 2012 increased $28.4 million compared with 2011 due to increased production and higher service costs caused by

increased demand for those services. Cash paid for interest during 2012 increased $29.2 million compared with the same period in 2011 due to

interest payments on our Senior Notes, as well as an increase in interest payments under our credit facility arising from an increase in our weightedaverage borrowings for the year.

Investing activities. Capital expenditures in 2012 decreased $125.3 million, or eight percent, compared with the same period in 2011.

This decrease was a result of being carried for substantially all of our drilling and completion costs in our outside operated Eagle Ford program. Net

proceeds from the sale of oil and gas properties decreased $309.1 million between the two periods due to a decrease in divestiture activity in 2012.

Financing activities. During 2012, we paid $287.5 million to settle our 3.50% Senior Convertible Notes. We received $392.1 million of

net proceeds from the issuance of our 2023 Notes in 2012, compared with $684.2 million of proceeds from the issuance of our 2019 Notes and

2021 Notes in 2011. We had net borrowings under our credit facility of $340.0 million during 2012, compared with net repayments of $48.0 million

made during 2011.

Analysis of cash flow changes between 2011 and 2010

Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash settlements, increased $409.4

million to $1.2 billion for the year ended December 31, 2011. The increase was due to an increase in production volumes. Cash paid for lease

operating expenses in 2011 increased $26.5 million compared with 2010. We received $4.0 million in income tax refunds in 2011 compared to $25.6

million received during 2010.

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Investing activities. Cash used for investing activities was $1.3 billion for the year ended December 31, 2011, compared with $361.6

million for the same period in 2010. Cash spent on capital expenditures increased $964.8 million, or 144 percent, to $1.6 billion. This increase in

capital and exploration activities was financed mainly by higher cash flows available from operating activities, divestiture proceeds, and proceeds

from the issuance of our 2019 Notes and 2021 Notes. Proceeds received from divestitures increased $53.0 million to $364.5 million for the year

ended December 31, 2011, due to an increase in the size of the divestiture packages.

Financing activities. Net repayments to our credit facility decreased $92.0 million for the year ended December 31, 2011, compared to

2010 as our strong cash position throughout 2011 resulted in decreased borrowings. After deducting aggregate fees of $15.8 million, we received

aggregate net proceeds of $684.2 million due to the issuance of our 2019 Notes and 2021 Notes during 2011. We spent $8.7 million on debt issuance

costs for our amended credit facility during the year ended December 31, 2011.

Interest Rate Risk

We are exposed to market risk due to the floating interest rate on our revolving credit facility. Our credit agreement allows us to fix the

interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate

is fixed, interest rate changes affect the credit facility’s fair market value but do not impact results of operations or cash flows. Conversely, for the

portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of

operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes, but can impact fair

market values. As of December 31, 2012, our fixed-rate debt outstanding totaled $1.1 billion. As of December 31, 2012, we had $340.0 million of

floating-rate debt outstanding. The carrying amount of our floating-rate debt at December 31, 2012, approximates its fair value. Assuming a constant

floating-rate debt level of $340.0 million, the before-tax cash flow impact resulting from a 100 basis point change in our interest rate would be $3.4

million over a 12-month time period.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production heavily impacts our revenue, overall profitability, access to capital and future

rate of growth. Oil, gas, and NGLs are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the

markets for oil, gas, and NGLs have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our

production depend on numerous factors beyond our control. Based on our 2012 production, a 10 percent decrease in our average realized price

received for oil, gas, and NGLs would have reduced our oil, gas, and NGL production revenues by $88.6 million, $35.8 million, and $23.0 million,

respectively.

The fair values of our commodity derivative contracts are largely determined by estimates of the forward curves of the relevant price indices.

At December 31, 2012, a 10 percent increase and 10 percent decrease in the forward curves associated with our commodity derivative instruments

would have changed our net asset positions by the following amounts:

10% Increase 10% Decrease

(in thousands)

Gain/(loss):

Gas derivatives $ (66.9) $ 61.9

Oil derivatives $ (29.0) $ 29.0

NGL derivatives $ (5.4) $ 5.4

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We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity prices. Please refer to Note 10 –

Derivative Financial Instruments of Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contracts, and

additional information below under the caption Summary of Oil, Gas, and NGL Derivative Contracts in Place.

Summary of Oil, Gas, and NGL Derivative Contracts in Place

Our oil, gas, and NGL derivative contracts include costless swaps and costless collar arrangements. All contracts are entered into for otherthan-trading purposes. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional information

regarding accounting for our derivative transactions.

As of December 31, 2012, our commodity derivative contracts through the third quarter of 2015 totaled 10.1 million Bbls of oil, 80.7

million MMBtu of gas, and 1.2 million Bbls of NGLs. As of February 14, 2013, the Company had commodity derivative contracts in place through

the fourth quarter of 2015 for a total of 14.5 million Bbls of oil, 114.8 million MMBtu of gas, and 2.0 million Bbls of NGLs.

In a typical commodity swap agreement, if the agreed-upon published third-party index price is lower than the swap fixed price, we receive

the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, we pay the

difference. For collar agreements, we receive the difference between an agreed upon index and the floor price if the index price is below the floor

price. We pay the difference between the agreed upon contracted ceiling price and the index price if the index price is above the contracted ceiling

price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices.

The following tables summarize the approximate volumes, average contract prices, and fair value of contracts we had in place as of

December 31, 2012:

Oil contracts

Oil Swaps:

Contract Period NYMEX WTI Volumes

WeightedAverage

Contract

Price

Fair Value at

December 31, 2012

(Liability)

(Bbls) (per Bbl) (in millions)

First quarter 2013 514,000 $ 89.87 $ (1.3)

Second quarter 2013 534,000 $ 88.99 (2.4)

Third quarter 2013 300,000 $ 91.47 (0.7)

Fourth quarter 2013 265,000 $ 91.22 (0.5)

2014 1,256,000 $ 90.92 (1.7)

2015 355,000 $ 88.40 (0.7)

All oil swaps 3,224,000 $ (7.3)

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Oil Collars:

Contract Period

NYMEX WTI

Volumes

WeightedAverage

Floor

Price

WeightedAverage

Ceiling

Price

Fair Value at

December 31, 2012

Asset (Liability)

(Bbls) (per Bbl) (per Bbl) (in millions)

First quarter 2013 755,000 $ 79.87 $ 107.36 $ 0.1

Second quarter 2013 620,000 $ 76.65 $ 109.08 0.2

Third quarter 2013 765,000 $ 74.89 $ 107.98 (0.3)

Fourth quarter 2013 727,000 $ 81.02 $ 116.09 1.8

2014 2,174,000 $ 83.71 $ 107.93 5.2

2015 1,814,000 $ 85.00 $ 95.51 (0.1)

All oil collars 6,855,000 $ 6.9

Natural Gas Contracts

Natural Gas Swaps:

Contract Period Volumes

WeightedAverage

Contract

Price

Fair Value at

December 31, 2012

Asset (Liability)

(MMBtu) (per MMBtu) (in millions)

First quarter 2013 8,611,000 $ 4.34 $ 9.2

Second quarter 2013 7,205,000 $ 3.99 4.5

Third quarter 2013 6,114,000 $ 4.19 4.2

Fourth quarter 2013 5,593,000 $ 4.38 3.9

2014 23,309,000 $ 4.14 4.4

2015 17,469,000 $ 4.02 (1.2)

All natural gas swaps* 68,301,000 $ 25.0

*Natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (56%), IF NGPL TXOK (4%), IF PEPL (16%), IF Reliant N/S

(17%), and IF TETCO STX (5%).

Natural Gas Collars:

Contract Period Volumes

WeightedAverage

Floor

Price

WeightedAverage

Ceiling

Price

Fair Value at

December 31, 2012

Asset

(MMBtu) (per MMBtu) (per MMBtu) (in millions)

First quarter 2013 1,330,000 $ 4.39 $ 5.46 $ 1.5

Second quarter 2013 1,910,000 $ 4.39 $ 5.32 2.0

Third quarter 2013 1,770,000 $ 4.39 $ 5.31 1.7

Fourth quarter 2013 1,640,000 $ 4.39 $ 5.31 1.4

2014 5,734,000 $ 4.38 $ 5.36 4.0

All natural gas collars* 12,384,000 $ 10.6

*Natural gas collars are comprised of IF HSC (18%), IF NGPL TXOK (18%), IF Reliant N/S (29%), and IF TETCO STX (35%).

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NGL Contracts

NGL Swaps:

Contract Period Volumes

WeightedAverage

Contract

Price

Fair Value at

December 31, 2012

Asset

(Bbls) (per Bbl) (in millions)

First quarter 2013 436,000 $ 46.21 $ 1.3

Second quarter 2013 371,000 $ 42.74 1.3

Third quarter 2013 222,000 $ 50.45 0.5

Fourth quarter 2013 206,000 $ 50.27 0.4

All NGL swaps* 1,235,000 $ 3.5

*NGL swaps are comprised of OPIS Mont. Belvieu Purity Ethane (37%), OPIS Mont. Belvieu LDH Propane (25%), OPIS Mont. Belvieu NONLDH Isobutane (2%), OPIS Mont. Belvieu NON-LDH Normal Butane (16%), and OPIS Mont. Belvieu NON-LDH Natural Gasoline (20%).

Commodity Derivative Contracts Entered into After December 31, 2012

The following tables summarize all commodity derivative contracts entered between January 1, 2013, and February 14, 2013:

Oil contracts

Oil Swaps:

Contract Period NYMEX WTI Volumes

WeightedAverage

Contract

Price

(Bbls) (per Bbl)

First quarter 2013 220,000 $ 98.25

Second quarter 2013 559,000 $ 98.25

Third quarter 2013 458,000 $ 97.50

Fourth quarter 2013 392,000 $ 95.85

2014 344,000 $ 95.85

All oil swaps 1,973,000

Oil Collars:

Contract Period

NYMEX WTI

Volumes

WeightedAverage

Floor

Price

WeightedAverage

Ceiling

Price

(Bbls) (per Bbl) (per Bbl)

2014 847,000 $ 85.00 $ 99.10

2015 1,552,000 $ 85.00 $ 92.79

All oil collars 2,399,000

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Natural Gas Contracts

Natural Gas Swaps:

Contract Period Volumes

WeightedAverage

Contract

Price

(MMBtu) (per MMBtu)

Third quarter 2013 3,542,000 $ 3.57

Fourth quarter 2013 2,925,000 $ 3.57

2014 13,208,000 $ 3.90

All natural gas swaps* 19,675,000

*Natural gas swaps are comprised of IF El Paso Permian (4%), IF HSC (77%), IF NGPL TXOK (3%), IF NNG Ventura (6%), IF PEPL (10%).

Natural Gas Collars:

Contract Period

NYMEX WTI

Volumes

WeightedAverage

Floor

Price

WeightedAverage

Ceiling

Price

(MMBtu) (per MMBtu) (per MMBtu)

2015 14,480,000 $ 3.96 $ 4.30

All natural gas collars* 14,480,000

*Natural gas collars are comprised of IF El Paso Permian (4%), IF HSC (72%), IF NNG Ventura (7%), IF PEPL (10%), IF Reliant N/S (7%).

NGL Contracts

NGL Swaps:

Contract Period Volumes

WeightedAverage

Contract

Price

(Bbls) (per Bbl)

First quarter 2013 60,000 $ 75.37

Second quarter 2013 181,000 $ 74.36

Third quarter 2013 153,000 $ 74.25

Fourth quarter 2013 136,000 $ 74.20

2014 208,000 $ 75.87

All NGL swaps* 738,000

*NGL swaps are comprised of OPIS Mont. Belvieu NON-LDH Isobutane (38%), OPIS Mont. Belvieu NON-LDH Natural Gasoline (34%), and

OPIS Mont. Belvieu NON-LDH Normal Butane (28%).

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Schedule of Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2012, for the periods specified (in millions):

Contractual Obligations Total

Less than 1

year 1-3 years 3-5 years

More than 5

years

Long-term debt (1) $ 1,440.0 $ — $ — $ 340.0 $ 1,100.0

Interest payments (2) 624.3 77.9 155.8 146.3 244.3

Delivery commitments (3) 858.7 53.2 170.7 193.0 441.8

Operating leases and contracts (3) 153.9 74.6 40.8 11.0 27.5

Derivative liability (4) 15.8 9.0 6.8 — —

Net Profits Plan (5) 77.5 16.6 28.9 22.5 9.5

Asset retirement obligations (6) 120.5 35.8 7.1 4.7 72.9

Other (7) 23.2 2.3 20.5 0.1 0.3

Total $ 3,313.9 $ 269.4 $ 430.6 $ 717.6 $ 1,896.3

(1) Long-term debt consists of our Senior Notes and the outstanding balance under our long-term revolving credit facility, and assumes no principal

repayment until the due dates of the instruments. The actual payments under our revolving credit facility may vary significantly.

(2) Interest payments on our Senior Notes are estimated assuming no principal repayment until the due dates of the instruments. Interest payments on

our credit facility have been estimated using a rate of 1.75 percent and assume no principal repayment until the May 27, 2016, due date.

(3) Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our operating

leases, contracts, and gathering, processing, and transportation through-put commitments.

(4) Amount shown represents only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices at

December 31, 2012, and excludes estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts

presented on the accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of

non-performance for us and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, however, as

they are subject to continuing market risk and commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part

II, Item 8 of this report for additional discussion regarding our derivative contracts.

(5) Amount shown represents undiscounted forecasted payments for the Net Profits Plan for the next six years. Payments are expected to gradually

decrease for the years beyond what are shown in this table and are not included due to these payments being highly variable, as outlined below.

The amount recorded on the accompanying balance sheets reflects all future Net Profits Plan payments and the impact of discounting, and

therefore differs from the amounts disclosed in this table. The variability in the amount of payments will be a direct reflection of commodity

prices, production rates, capital expenditures, and operating costs in future periods. Predicting the timing and amounts of payments associated

with this liability is contingent upon estimates of appropriate discount factors, adjusting for risk and time value, and upon a number of factors we

cannot control. Please refer to Note 7 – Compensation Plans and Note 11 - Fair Value Measurements in Part II, Item 8 of this report for

additional discussion regarding our Net Profits Plan liability.

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(6) Amount shown represents estimated future discounted abandonment costs. These obligations are recorded as liabilities on our December 31,

2012, accompanying balance sheets. The ultimate settlement of these obligations is unknown and can be impacted by federal and state regulations,

as well as economic factors and therefore the actual timing of abandonment costs may vary significantly. Please refer to Note 9 – Asset

Retirement Obligations in Part II, Item 8 of this report for additional discussion regarding our asset retirement obligations.

(7) The majority of the amount shown represents the remaining funded portion of our estimated pension liability of $20.0 million, although we

recognize that we cannot accurately determine the timing of future payments, as well as insignificant amounts related to uncertain tax positions

and our cash settlement balancing payable. We are expected to make contributions to the Pension Plan in 2013 of $373,000. We made

contributions of $5.4 million and $5.3 million in 2012 and 2011, respectively, toward our pension liability.

In addition to the amounts in the above table, we entered into a three-year capital project commencing in 2011 for the development of

infrastructure in our non-operated Eagle Ford shale play. Pursuant to the terms of the agreement for the construction, ownership and operation of the

assets, we are required to pay our portion of the costs. Based on current estimates, we do not expect costs to exceed approximately $67 million over

the remaining term of the agreement.

Off-balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial

partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of

facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2012, we have not been involved

in any unconsolidated special purpose entity transactions.

We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we are the primary beneficiary of a

variable interest entity, that entity is consolidated into our consolidated financial statements.

Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial

statements. The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States

(“GAAP”) requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the

disclosure of contingent assets and liabilities as of the date of our financial statements. We base our assumptions and estimates on historical

experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we

calculate due to changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting

policies is detailed in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below those

policies identified as being critical to the understanding of our business and results of operations and that require the application of significant

management judgment.

Oil and gas reserve quantities. Our estimated reserve quantities and future net cash flows are critical to the understanding of the value of

our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our financial statements, including

the calculations of depletion and impairment of proved oil and gas properties and the estimate of our Net Profits Plan liability. Future cash inflows and

future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis

differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected

cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a 10 percent

discount rate to

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be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than

those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, including using independent reserve

engineering consultants. We expect that periodic reserve estimates will change in the future as additional information becomes available and as

commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves at June 30 and December 31 of each year. For

purposes of depletion and impairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions. Changes

in depletion or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period the reserve estimates

change. Please refer to Supplemental Oil and Gas Information in Part II, Item 8 of this report.

The following table presents information about reserve changes from period to period due to items we do not control, such as price, and

from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted

from capital expenditures we incurred to develop other estimated proved reserves.

For the Years Ended December 31,

2012 2011 2010

BCFE BCFE BCFE

Change Change Change

Revisions resulting from price changes (72.7) (25.3) 42.6

Revisions resulting from performance (1) (92.0) 36.8 (17.9)

Total (164.7) 11.5 24.7

(1) Performance revisions include the removal of proved undeveloped reserves that are no longer in our development plan within five years. 2011 includes the

impact of our conversion to three stream production reporting.

As previously noted, commodity prices are volatile, and estimates of reserves are inherently imprecise. Consequently, we expect to continue

experiencing these types of changes. Please refer to additional reserves discussion under Overview of the Company.

The following table reflects the estimated BCFE change and percentage change to our total reported reserve volumes from the described

hypothetical changes:

For the Years Ended December 31,

2012 2011 2010

BCFE Percentage BCFE Percentage BCFE Percentage

Change Change Change Change Change Change

A 10% decrease in SEC

pricing (67.4) (4)% (22.2) (2)% (13.9) (1)%

A 10% decrease in proved

undeveloped reserves (76.1) (4)% (41.5) (3)% (29.7) (3)%

The table above solely reflects the impact of a 10 percent change in SEC pricing or decrease in proved undeveloped reserves and does not

include additional impacts to our proved reserves that may result from our internal intent to drill hurdles. Additional reserve information can be found

in the reserve table and discussion included in Items 1 and 2 of Part I of this report, and in Supplemental Oil and Gas Disclosures of Part II, Item

8 of this report.

Successful efforts method of accounting. GAAP provides for two alternative methods for the oil and gas industry to use in accounting

for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method.

Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different

financial

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statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more

detailed description is included in Note 1 - Summary of Significant Accounting Policies of Part II, Item 8 of this report.

Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of our results of operations and

our forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced

oil, gas, and NGLs. We report revenue as the gross amounts we receive before taking into account production taxes and transportation costs, which

are reported as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received

between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a

purchaser. At the end of each month, we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use

our knowledge of our properties, their historical performance, NYMEX and local spot market prices, and other factors as the basis for these

estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A 10 percent change in our

year end revenue accrual would have impacted net income before tax by approximately $16 million in 2012.

Change in Net Profits Plan Liability. We record the estimated liability of future payments for our Net Profits Plan. The estimated liability

is calculated based on a number of assumptions, including estimates of proved reserves, estimated future capital, present value discount factors,

pricing assumptions, and overall market conditions. Please refer to Note 11 - Fair Value Measurements in Part II, Item 8 of this report for

additional discussion.

Asset retirement obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our

oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based

on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of

our properties, assume what future inflation rates apply to external estimates, and determine what credit-adjusted risk-free discount rate to use. The

impact to the accompanying statements of operations from these estimates is reflected in our depreciation, depletion, and amortization calculations and

occurs over the remaining life of our respective oil and gas properties. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of

this report for additional discussion.

Impairment of oil and gas properties. Our proved oil and gas properties are recorded at cost. We evaluate our proved properties for

impairment when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We

estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying amount of the oil and

gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we

will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to,

estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates.

Unproved oil and gas properties are assessed periodically for impairment on a lease-by-lease basis based on the remaining lease terms,

drilling results, commodity price outlook, and future capital allocations. An impairment allowance is provided on unproven property when we

determine that the property will not be developed or the carrying value will not be realized. Please refer to Impairment of Proved and Unproved

Properties in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report for impairment results.

Derivatives and Hedging. We periodically enter into commodity derivative contracts to manage our exposure to oil, gas and NGL price

volatility. The accounting treatment for the change in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is

designated as a cash flow hedge. Effective January 1, 2011, we elected to de-designate all of our commodity derivatives that had previously been

designated as cash flow hedges as of December 31, 2010, and have elected to discontinue hedge accounting prospectively.

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Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in accumulated other

comprehensive loss until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value

hedge, to the extent the hedge is effective, have no effect on the statement of income because changes in fair value of the derivative offsets changes

in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or

a cash flow hedge, changes in fair value are recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the

derivative’s fair value and any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings. The

estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, whether or not the

forecasted hedged transaction will occur, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our

financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are

beyond our control.

Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount

in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability

is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is

more likely than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are

prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax

credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual

amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset

recovery and liability settlement could have an impact on our results of operations. A one percent increase and decrease in our effective tax rate would

have changed our calculated income tax benefit by approximately $832,000 and $839,000, respectively, for the year ended December 31, 2012.

Accounting Matters

Please refer to the section entitled Recently Issued Accounting Standards under Note 1 – Summary of Significant Accounting

Policies for additional information on the recent adoption of new authoritative accounting guidance in Part II, Item 8 of this report.

Environmental

We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future

expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes,

and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below,

may have on future capital expenditures, liquidity, and results of operations.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons,

particularly natural gas, from tight formations. For additional information about hydraulic fracturing and related environmental matters, see Risk

Factors – Risks Related to Our Business – Proposed federal and state legislation and regulatory initiatives relating to hydraulic

fracturing could result in increased costs and additional operating restrictions or delays.

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Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other ‘‘greenhouse gases’’

present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of

the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict

emissions of greenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas

emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates

emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the

reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on

an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities,

on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and

almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of

greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring

major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and

surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse

gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating

costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting

requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and

natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on

our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing

concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased

frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse

effect on our financial condition and results of operations.

In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative incentives, such as enhanced oil

recovery, carbon sequestration and low carbon fuel standards, could benefit us in a variety of ways. For example, although climate change legislation

could reduce the overall demand for the oil and natural gas that we produce, the relative demand for natural gas may increase because the burning of

natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources, such

as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity

supply. Also, if states adopt low-carbon fuel standards, natural gas may become a more attractive transportation fuel. Approximately 55 and 59

percent of our production on an MCFE basis in 2012 and 2011, respectively, was natural gas. Market-based incentives for the capture and storage of

carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could also benefit us through the potential to obtain greenhouse

gas emission allowances or offsets from or government incentives for the sequestration of carbon dioxide.

Non-GAAP Financial Measures

EBITDAX represents income (loss) before interest expense, interest income, income taxes, depreciation, depletion, amortization and

accretion, exploration expense, property impairments, non-cash stock compensation expense, unrealized derivative gains and losses, change in the

Net Profits Plan liability, and gains and losses on divestitures. EBITDAX excludes certain items that we believe affect the comparability of operating

results and can exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP

measure that is presented because we believe that it provides useful additional

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information to investors, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions,

and to service debt. We are also subject to a financial covenant under our credit facility based on our debt to EBITDAX ratio. In addition, EBITDAX

is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and

gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions.

EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by (used

in) operating activities, profitability, or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net

income (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. The

following table provides reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the periods presented:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Net income (loss) (GAAP) $ (54,249) $ 215,416 $ 196,837

Interest expense 63,720 45,849 24,196

Interest income (220) (466) (321)

Income tax (benefit) expense (29,268) 123,585 118,059

Depletion, depreciation, amortization, and asset retirement obligation liability accretion 727,877 511,103 336,141

Exploration 81,809 46,776 56,184

Impairment of proved properties 208,923 219,037 6,127

Abandonment and impairment of unproved properties 16,342 7,367 1,986

Stock-based compensation expense 30,185 26,824 26,743

Unrealized derivative (gain) loss (11,366) (62,757) 8,899

Change in Net Profits Plan liability (28,904) (25,477) (34,441)

(Gain) loss on divestiture activity 27,018 (220,676) (155,277)

EBITDAX (Non-GAAP) 1,031,867 886,581 585,133

Interest expense (63,720) (45,849) (24,196)

Interest income 220 466 321

Income tax benefit (expense) 29,268 (123,585) (118,059)

Exploration (81,809) (46,776) (56,184)

Exploratory dry hole expense 20,861 277 289

Amortization of debt discount and deferred financing costs 6,769 18,299 13,464

Deferred income taxes (29,638) 123,789 114,517

Plugging and abandonment (2,856) (5,849) (8,314)

Other 527 (6,027) (3,993)

Changes in current assets and liabilities 10,480 (40,794) (5,881)

Net cash provided by operating activities (GAAP) $ 921,969 $ 760,532 $ 497,097

Note: Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of

operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of

operations for the component of stock-based compensation expense recorded to exploration.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk and Summary of

Oil, Gas, and NGL Derivative Contracts in Place in Item 7 above and is incorporated herein by reference.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

SM Energy Company and Subsidiaries

Denver, Colorado

We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the “Company”) as of December 31,

2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of

the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our

responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards

require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An

audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes

assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement

presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of SM Energy Company and

subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended

December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal

control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued

by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 21, 2013, expressed an unqualified

opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

February 21, 2013

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SM ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share amounts)

December 31,

2012 2011

 ASSETS

Current assets:

Cash and cash equivalents $ 5,926 $ 119,194

Accounts receivable (note 2) 254,805 210,368

Refundable income taxes 3,364 5,581

Prepaid expenses and other 30,017 68,026

Derivative asset 37,873 55,813

Deferred income taxes 8,579 4,222

Total current assets 340,564 463,204

Property and equipment (successful efforts method), at cost:

Land 1,845 1,548

Proved oil and gas properties 5,401,684 4,378,987

Less - accumulated depletion, depreciation, and amortization (2,376,170) (1,766,445)

Unproved oil and gas properties 175,287 120,966

Wells in progress 273,928 273,428

Materials inventory, at lower of cost or market 13,444 16,537

Oil and gas properties held for sale net of accumulated depletion, depreciation and amortization of $20,676

in 2012 and $10,714 in 2011 33,620 246

Other property and equipment, net of accumulated depreciation of $22,442 in 2012 and $23,985 in 2011 153,559 71,369

Total property and equipment, net 3,677,197 3,096,636

Other noncurrent assets:

Derivative asset 16,466 31,062

Restricted cash 86,773 124,703

Other noncurrent assets 78,529 83,375

Total other noncurrent assets 181,768 239,140

Total Assets $ 4,199,529 $ 3,798,980

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable and accrued expenses (note 2) $ 525,627 $ 456,999

Derivative liability 8,999 42,806

Other current liabilities 6,920 6,000

Total current liabilities 541,546 505,805

Noncurrent liabilities:

Long-term credit facility 340,000 —

3.50% Senior Convertible Notes, net of unamortized discount of $2,431 in 2011 — 285,069

6.625% Senior Notes due 2019 350,000 350,000

6.50% Senior Notes due 2021 350,000 350,000

6.50% Senior Notes due 2023 400,000 —

Asset retirement obligation 112,912 87,167

Asset retirement obligation associated with oil and gas properties held for sale 1,393 1,277

Net Profits Plan liability 78,827 107,731

Deferred income taxes 537,383 568,263

Derivative liability 6,645 12,875

Other noncurrent liabilities 66,357 67,853

Total noncurrent liabilities 2,243,517 1,830,235

Commitments and contingencies (note 6)

Stockholders' equity:

Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 66,245,816 shares in 2012 and

64,145,482 shares in 2011; outstanding, net of treasury shares: 66,195,235 shares in 2012 and
64,064,415 shares in 2011 662 641

Additional paid-in capital 233,642 216,966

Treasury stock, at cost: 50,581 shares in 2012 and 81,067 shares in 2011 (1,221) (1,544)

Retained earnings 1,190,397 1,251,157

Accumulated other comprehensive loss (9,014) (4,280)

Total stockholders' equity 1,414,466 1,462,940

Total Liabilities and Stockholders' Equity $ 4,199,529 $ 3,798,980

The accompanying notes are an integral part of these consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

For the Years

Ended December 31,

2012 2011 2010

Operating revenues and other income:

Oil, gas, and NGL production revenue $ 1,473,868 $ 1,332,392 $ 836,288

Realized hedge gain (loss) 3,866 (20,707) 23,465

Gain (loss) on divestiture activity (27,018) 220,676 155,277

Marketed gas system revenue 52,808 69,898 70,110

Other operating revenue 1,578 1,059 7,694

Total operating revenues and other income 1,505,102 1,603,318 1,092,834

Operating expenses:

Oil, gas, and NGL production expense 391,872 290,111 195,075

Depletion, depreciation, amortization, and asset retirement obligation liability

accretion 727,877 511,103 336,141

Exploration 90,248 53,537 63,860

Impairment of proved properties 208,923 219,037 6,127

Abandonment and impairment of unproved properties 16,342 7,367 1,986

General and administrative 119,815 118,526 106,663

Change in Net Profits Plan liability (28,904) (25,477) (34,441)

Unrealized and realized derivative (gain) loss (55,630) (37,086) 8,899

Marketed gas system expense 47,583 64,249 66,726

Other operating expense 6,993 17,567 3,027

Total operating expenses 1,525,119 1,218,934 754,063

Income (loss) from operations (20,017) 384,384 338,771

Nonoperating income (expense):

Interest income 220 466 321

Interest expense (63,720) (45,849) (24,196)

Income (loss) before income taxes (83,517) 339,001 314,896

Income tax benefit (expense) 29,268 (123,585) (118,059)

Net income (loss) $ (54,249) $ 215,416 $ 196,837

Basic weighted-average common shares outstanding 65,138 63,755 62,969

Diluted weighted-average common shares outstanding 65,138 67,564 64,689

Basic net income (loss) per common share $ (0.83) $ 3.38 $ 3.13

Diluted net income (loss) per common share $ (0.83) $ 3.19 $ 3.04

The accompanying notes are an integral part of these consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

For the Years

Ended December 31,

2012 2011 2010

Net income (loss) $ (54,249) $ 215,416 $ 196,837

Other comprehensive income (loss), net of tax:

 Change in derivative instrument fair value — — 16,811

 Reclassification to earnings (2,264) 12,997 6,641

 Pension liability adjustment (2,470) (1,795) (980)

Total other comprehensive income (loss), net of tax (4,734) 11,202 22,472

Total comprehensive income (loss) $ (58,983) $ 226,618 $ 219,309

The accompanying notes are an integral part of these consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands, except share amounts)

Additional

Paid-in Capital

Accumulated Other

Comprehensive Loss

 Total

Stockholders’

Equity

Common Stock Treasury Stock Retained

Shares Amount Shares Amount Earnings

Balances, January 1, 2010 62,899,122 $ 629 $ 160,516 (126,893) $ (1,204) $ 851,583 $ (37,954) $ 973,570

Net income — — — — — 196,837 — 196,837

Other comprehensive income — — — — — — 22,472 22,472

Cash dividends, $ 0.10 per share — — — — — (6,297) — (6,297)

Issuance of common stock under

Employee Stock Purchase Plan 52,948 1 1,669 — — — — 1,670

Issuance of common stock upon vesting

of RSUs, net of shares used for tax

withholdings, including income tax cost

of RSUs 113,103 1 (2,094) — — — — (2,093)

Issuance of common stock upon stock

option exercises, including income tax

benefit 346,377 3 5,621 — — — — 5,624

Stock-based compensation expense 1,250 — 25,962 24,258 781 — — 26,743

Balances, December 31, 2010 63,412,800 $ 634 $ 191,674 (102,635) $ (423) $ 1,042,123 $ (15,482) $ 1,218,526

Net income — — — — — 215,416 — 215,416

Other comprehensive income — — — — — — 11,202 11,202

Cash dividends, $ 0.10 per share — — — — — (6,382) — (6,382)

Issuance of common stock under

Employee Stock Purchase Plan 41,358 — 2,300 — — — — 2,300

Issuance of common stock upon vesting

of RSUs and settlement of PSUs, net of

shares used for tax withholdings 278,773 3 (9,976) — — — — (9,973)

Issuance of common stock upon stock

option exercises 412,551 4 5,023 — — — — 5,027

Stock-based compensation expense — — 27,945 21,568 (1,121) — — 26,824

Balances, December 31, 2011 64,145,482 $ 641 $ 216,966 (81,067) $ (1,544) $ 1,251,157 $ (4,280) $ 1,462,940

Net loss — — — — — (54,249) — (54,249)

Other comprehensive loss — — — — — — (4,734) (4,734)

Cash dividends, $ 0.10 per share — — — — — (6,511) — (6,511)

Issuance of common stock under

Employee Stock Purchase Plan 66,485 1 2,775 — — — — 2,776

Issuance of common stock upon vesting

of RSUs and settlement of PSUs, net of

shares used for tax withholdings 929,375 9 (21,631) — — — — (21,622)

Issuance of common stock upon stock

option exercises 240,368 2 3,038 — — — — 3,040

Conversion of 3.50% Senior Convertible

Notes to common stock, including income

tax benefit of conversion 864,106 9 2,632 — — — — 2,641

Stock-based compensation expense — — 29,862 30,486 323 — — 30,185

Balances, December 31, 2012 66,245,816 $ 662 $ 233,642 (50,581) $ (1,221) $ 1,190,397 $ (9,014) $ 1,414,466

The accompanying notes are an integral part of these consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

For the Years Ended

December 31,

2012 2011 2010

Cash flows from operating activities:

Net income (loss) $ (54,249) $ 215,416 $ 196,837

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

(Gain) loss on divestiture activity 27,018 (220,676) (155,277)

Depletion, depreciation, amortization, and asset retirement obligation liability accretion 727,877 511,103 336,141

Exploratory dry hole expense 20,861 277 289

Impairment of proved properties 208,923 219,037 6,127

Abandonment and impairment of unproved properties 16,342 7,367 1,986

Stock-based compensation expense 30,185 26,824 26,743

Change in Net Profits Plan liability (28,904) (25,477) (34,441)

Unrealized derivative (gain) loss (11,366) (62,757) 8,899

Amortization of debt discount and deferred financing costs 6,769 18,299 13,464

Deferred income taxes (29,638) 123,789 114,517

Plugging and abandonment (2,856) (5,849) (8,314)

Other 527 (6,027) (3,993)

Changes in current assets and liabilities:

Accounts receivable (21,389) (41,998) (47,153)

Refundable income taxes 2,217 2,901 24,291

Prepaid expenses and other (1,484) 16,376 (35,363)

Accounts payable and accrued expenses 31,136 (18,073) 53,198

Excess income tax benefit from the exercise of stock awards — — (854)

Net cash provided by operating activities 921,969 760,532 497,097

Cash flows from investing activities:

Net proceeds from sale of oil and gas properties 55,375 364,522 311,504

Capital expenditures (1,507,828) (1,633,093) (668,288)

Acquisition of oil and gas properties (5,773) — (664)

Other 893 3,661 (4,125)

Net cash used in investing activities (1,457,333) (1,264,910) (361,573)

Cash flows from financing activities:

Proceeds from credit facility 1,609,000 322,000 571,559

Repayment of credit facility (1,269,000) (370,000) (711,559)

Debt issuance costs related to credit facility — (8,719) —

Net proceeds from 6.625% Senior Notes due 2019 — 341,122 —

Net proceeds from 6.50% Senior Notes due 2021 — 343,120 —

Net proceeds from 6.50% Senior Notes due 2023 392,138 — —

Repayment of 3.50% Senior Convertible Notes (287,500) — —

Proceeds from sale of common stock 5,816 7,327 6,440

Dividends paid (6,511) (6,382) (6,297)

Net share settlement from issuance of stock awards (21,622) (9,973) (2,093)

Excess income tax benefit from the exercise of stock awards — — 854

Other (225) — —

Net cash provided by (used in) financing activities 422,096 618,495 (141,096)

Net change in cash and cash equivalents (113,268) 114,117 (5,572)

Cash and cash equivalents at beginning of period 119,194 5,077 10,649

Cash and cash equivalents at end of period $ 5,926 $ 119,194 $ 5,077

The accompanying notes are an integral part of these consolidated financial statements.

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SM ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

Supplemental schedule of additional cash flow information and non-cash investing and financing activities:

For the Years Ended

December 31,

2012 2011 2010

(in thousands)

Cash paid for interest, net of capitalized interest $ (51,328) $ (22,133) $ (13,340)

Net cash refunded for income taxes $ 1,389 $ 4,046 $ 25,578

At December 31, 2012, 2011, and 2010, $262.8 million, $214.8 million, and $238.5 million, respectively, are included as additions to oil and gas

properties and accounts payable and accrued expenses. These oil and gas property additions are reflected in cash used in investing activities in the periods that

the payables are settled.

 

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SM ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

Description of Operations

SM Energy is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs

in onshore North America, with a current focus on oil and liquids-rich resource plays.

 

Basis of Presentation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been

prepared in accordance with GAAP and the instructions to Form 10-K and regulation S-X. Subsidiaries that the Company does not control are

accounted for using the equity or cost methods as appropriate. Equity method investments are included in other noncurrent assets in the accompanying

consolidated balance sheets (“accompanying balance sheets”). Intercompany accounts and transactions have been eliminated. In connection with the

preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2012,

through the filing date of this report.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the

reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial

statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates

of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization (“DD&A”), impairment of

proved properties, asset retirement obligations, and the Net Profits Interest Bonus Plan (“Net Profits Plan”) liability, each of which represents a

significant component of the accompanying consolidated financial statements.

Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying

value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Restricted Cash

The Company’s restricted cash balance represents cash payments received from Mitsui that are contractually restricted to be used solely for

development operations pursuant to the Company’s Acquisition and Development Agreement with Mitsui and accordingly are classified as non-current

assets. Please refer to Note 12- Acquisition and Development Agreement and Carry and Earning Agreement for additional information.

Accounts Receivable

The Company’s accounts receivables consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on

properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue

disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and

the Company has had minimal bad debts.

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Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is

influenced by the general economic conditions of the industry. Receivables are not collateralized. As of December 31, 2012, and 2011, the Company

had no allowance for doubtful accounts recorded.

Concentration of Credit Risk and Major Customers

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in

energy related industries. The creditworthiness of customers and other counterparties is subject to continuous review. During 2012, we had two

major customers, Regency Gas Services LLC and Plains Marketing LP, which accounted for approximately 21 percent and 13 percent, respectively,

of our total production revenue. During 2011 and 2010, we had one major customer, Regency Gas Services LLC, individually account for

approximately 18 percent and 11 percent, respectively, of our total production revenue.

The Company currently uses 10 separate counterparties for its oil, gas, and NGL commodity derivatives, all of which are participating

lenders in the Company’s credit facility. Two of our counterparties were downgraded during 2012, but all maintain investment grade ratings. Nine

counterparties carry corporate credit ratings at or exceeding A- and Baa2 by Standard & Poor’s and Moody’s, respectively. The remaining

counterparty fell to BBB- and Baa2, respectively. In response, the Company requires cash collateral to be posted when its portfolio of trades with that

counterparty is in an overall asset position.

The Company has accounts in the following locations with a national bank: Denver, Colorado; Shreveport, Louisiana; Houston, Texas;

Midland, Texas; and Billings, Montana. The Company has accounts with a local bank in Tulsa, Oklahoma. The Company’s policy is to invest in

highly-rated instruments and to limit the amount of credit exposure at each individual institution.

Oil and Gas Producing Activities

The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and

geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable

reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of

the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or

exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that

economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in cash flows

from investing activities as part of capital expenditures within the accompanying consolidated statements of cash flows (“accompanying statements

of cash flows”). The costs of development wells are capitalized whether those wells are successful or unsuccessful.

DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production

method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well

as the anticipated proceeds from salvaging equipment. As of December 31, 2012, and 2011, the Company’s estimated salvage value was $64.4

million and $64.1 million, respectively.

Materials Inventory

The Company’s materials inventory is primarily comprised of tubular goods to be used in future drilling operations. Materials inventory is

valued at the lower of cost or market and totaled $13.4 million and $16.5 million at December 31, 2012, and 2011, respectively. There were no

materials inventory write-downs for the years ended December 31, 2012, 2011, or 2010.

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Assets Held for Sale

Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the

accompanying balance sheets at the lower of net book value or fair value less the cost to sell. The asset retirement obligation liabilities related to such

properties have been reclassified to asset retirement obligations associated with oil and gas properties held for sale in the accompanying balance sheets.

For additional discussion on assets held for sale, please refer to Note 3 – Divestitures and Assets Held for Sale.

Other Property and Equipment

Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are

recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair

costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which

range from three to thirty years, or the unit of output method where appropriate. When other property and equipment is sold or retired, the capitalized

costs and related accumulated depreciation are removed from the accounts.

Intangible Assets

As of December 31, 2012, and 2011, the Company had $10.8 million and $7.1 million, respectively, of intangible assets consisting of

acquired water rights, which are included as other noncurrent assets in the accompanying balance sheets. All indefinite lived intangible assets are

evaluated for impairment if such indicators arise and at least annually.

Cash Settlement Balancing

The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers,

regardless of whether the sales are proportionate to the Company’s ownership in the property. An asset or liability is recognized to the extent that there

is an imbalance in excess of the remaining gas reserves on the underlying properties. As of December 31, 2012, and 2011, the Company has

recorded a receivable of $1.7 million and $1.9 million, respectively, and a liability of $1.3 million and $1.1 million, respectively, which is included

as other noncurrent assets and other noncurrent liabilities in the accompanying balance sheets.

Derivative Financial Instruments

The Company seeks to manage or reduce commodity price risk on production by entering into derivative contracts. The Company seeks to

minimize its basis risk and indexes its oil derivative contracts to NYMEX prices, its NGL derivative contracts to OPIS prices, and the majority of its

gas derivative contracts to various regional index prices associated with pipelines in proximity to the Company’s areas of gas production. For

additional discussion on derivatives, please see Note 10 – Derivative Financial Instruments.

Net Profits Plan

The Company records the estimated fair value of expected future payments made under the Net Profits Plan as a noncurrent liability in the

accompanying balance sheets. The underlying assumptions used in the calculation of the estimated liability include estimates of production, proved

reserves, recurring and workover lease operating expense, transportation, production and ad valorem tax rates, present value discount factors, pricing

assumptions, and overall market conditions. The estimates used in calculating the long-term liability are adjusted from period-to-period based on the

most current information attributable to the underlying assumptions. Changes in the estimated liability of future payments associated with the Net

Profits Plan are recorded as increases or decreases to expense in the current period as a separate line item in the accompanying consolidated statements

of operations (“accompanying statements of operations”), as these changes are considered changes in estimates.

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The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation related to periodic

operations are recognized as compensation expense and are included within general and administrative expense and exploration expense in the

accompanying statements of operations. The corresponding current liability is included in accounts payable and accrued expenses in the

accompanying balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas properties

in each respective pool of the Net Profits Plan. For additional discussion, please refer to the heading Net Profits Plan in Note 7 – Compensation

Plans and Note 11 – Fair Value Measurements.

Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for

the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a

well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The

Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted

liability over the remaining estimated economic lives of the respective oil and gas properties. For additional discussion, please refer to Note 9 – Asset

Retirement Obligations.

Revenue Recognition

The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. The Company reports revenue as the gross amount

received before taking into account production taxes and transportation costs, which are reported separately as expenses and are included in oil, gas,

and NGL production expense in the accompanying statements of operations. Revenue is recorded in the month the Company’s production is delivered

to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is

determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production

delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, their historical performance,

NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.

Impairment of Proved and Unproved Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is based on expected future discounted cash

flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows are calculated on all developed proved

reserves and risk adjusted proved undeveloped, probable, and possible reserves using a discount rate and price forecasts selected by the Company’s

management. The discount rate is a rate that management believes is representative of current market conditions. The prices for oil and gas are

forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each

commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively

trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment is

recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable.

The Company recorded $208.9 million, $219.0 million, and $6.1 million, of proved property impairments for the years ended

December 31, 2012, 2011, and 2010, respectively. The impairments in 2012 were a result of the Company’s write-down of Wolfberry assets in its

Permian region due to negative engineering revisions and the Company’s Haynesville shale assets as a result of low natural gas prices. The impairments

in 2011 were related to the Company’s James Lime, Cotton Valley, and Haynesville shale assets as a result of significantly lower natural gas prices at

the end of 2011.

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For the years ended December 31, 2012, 2011, and 2010, the Company recorded expense related to the abandonment and impairment of

unproved properties of $16.3 million, $7.4 million, and $2.0 million, respectively. The Company’s abandonment and impairment of unproved

properties in 2012 related to acreage that the Company no longer intends to develop in the Rocky Mountain region.

Sales of Proved and Unproved Properties

The partial sale of proved properties within an existing field is accounted for as normal retirement and no gain or loss on divestiture activity is

recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual

proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of

operations for all other sales of proved properties.

The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of

the cost applicable to the interest retained. A gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of

the unproved property. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved

property. For additional discussion, please refer to Note 3 – Divestitures and Assets Held for Sale.

Stock-Based Compensation

At December 31, 2012, the Company had stock-based employee compensation plans that included RSUs, PSUs, restricted stock awards,

and stock options issued to employees and non-employee directors, as more fully described in Note 7 - Compensation Plans. The Company

records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on

the estimated fair value of these awards determined at the time of grant.

Income Taxes

The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of

temporary differences between the carrying amounts on the financial statements and the tax basis of assets and liabilities, as measured using current

enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are

recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts

more likely than not to be realized based upon Company analysis.

Earnings per Share

Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic

weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of

shares of common stock made by the Company.

Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common

shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of in-themoney outstanding stock options, unvested RSUs, contingent PSUs, and shares into which the 3.50% Senior Convertible Notes were convertible.

When there is a loss from continuing operations, as was the case for the year ended December 31, 2012, all potentially dilutive shares are anti-dilutive

and are consequently excluded from the calculation of earnings per share.

PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of

shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of

potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting

period, assuming that

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date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation

Plans under the heading Performance Share Units Under the Equity Incentive Compensation Plan .

The Company called for redemption of its 3.50% Senior Convertible Notes on April 2, 2012, after which the majority of the holders of the

outstanding 3.50% Senior Convertible Notes elected to convert their notes. The Company issued 864,106 common shares upon conversion, and

these shares were included in the calculation of basic weighted-average common shares outstanding for the year ended December 31, 2012. Please

refer to Note 5 - Long-term Debt for additional discussion. Prior to calling the 3.50% Senior Convertible Notes for redemption, the Company’s

notes had a net-share settlement right giving the Company the option to irrevocably elect, by notice to the trustee under the indenture for the notes, to

settle the Company’s obligation, in the event that holders of the notes elected to convert all or a portion of their notes, by delivering cash in an amount

equal to each $1,000 principal amount of notes surrendered for conversion and, if applicable, at the Company’s option, shares of common stock or

cash, or any combination of common stock and cash, for the amount of conversion value in excess of the principal amount. Prior to the settlement of

the Company’s 3.50% Senior Convertible Notes, potentially dilutive shares associated with the conversion feature were accounted for using the

treasury stock method when shares of the Company’s common stock traded at an average closing price that exceeded the $54.42 conversion price.

Shares of the Company’s common stock traded at an average closing price exceeding the conversion price and were included on an adjusted weighted

basis for the portion of the year ended December 31, 2012, for which they were outstanding. Shares of the Company’s common stock traded at an

average closing price exceeding the $54.42 conversion price for the twelve-month period ended December 31, 2011, making the 3.50% Senior

Convertible Notes dilutive for that period. Shares of the Company's common stock did not trade at an average closing price exceeding the $54.42

conversion price for the year ended December 31, 2010. Therefore, the 3.50% Senior Convertible Notes were not dilutive and did not impact the

diluted earnings per share calculation for the year ended December 31, 2010.

The treasury stock method is used to measure the dilutive impact of in-the-money stock options, unvested RSUs, contingent PSUs, and

3.50% Senior Convertible Notes.

The following table details the weighted-average dilutive and anti-dilutive securities related to stock options, RSUs, PSUs, and the 3.50%

Senior Convertible Notes for the years presented:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Dilutive — 3,809 1,720

Anti-dilutive 2,102 — —

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The following table sets forth the calculations of basic and diluted earnings per share:

For the Years Ended December 31,

2012 2011 2010

(in thousands, except per share amounts)

Net income (loss) $ (54,249) $ 215,416 $ 196,837

Basic weighted-average common shares outstanding 65,138 63,755 62,969

Add: dilutive effect of stock options, unvested RSUs, and contingent

PSUs — 2,592 1,720

Add: dilutive effect of 3.50% Senior Convertible Notes — 1,217 —

Diluted weighted-average common shares outstanding 65,138 67,564 64,689

Basic net income (loss) per common share $ (0.83) $ 3.38 $ 3.13

Diluted net income (loss) per common share $ (0.83) $ 3.19 $ 3.04

Comprehensive Income (Loss)

Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income

(loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of

net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive

income (loss).

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The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table:

Change in Derivative

Instrument Fair Value

Derivative

Reclassification to

Earnings

Pension Liability

Adjustments

(in thousands)

For the year ended December 31, 2010

Before tax income (loss) $ 26,904 $ 10,608 $ (1,570)

Tax benefit (expense) (10,093) (3,967) 590

Income (loss), net of tax $ 16,811 $ 6,641 $ (980)

For the year ended December 31, 2011

Before tax income (loss) $ — $ 20,707 $ (2,779)

Tax benefit (expense) — (7,710) 984

Income (loss), net of tax $ — $ 12,997 $ (1,795)

For the year ended December 31, 2012

Before tax (loss) $ — $ (3,865) $ (3,909)

Tax benefit — 1,601 1,439

(Loss), net of tax $ — $ (2,264) $ (2,470)

Fair Value of Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost,

which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates

its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had $340.0 million of outstanding loans under

its credit facility as of December 31, 2012. The Company had no borrowings outstanding under its credit facility as of December 31, 2011. The

Company’s 3.50% Senior Convertible Notes, 2019 Notes, 2021 Notes, and 2023 Notes, are recorded at cost, and the fair values are disclosed in

Note 11 - Fair Value Measurements.The Company has derivative financial instruments that are recorded at fair value. Considerable judgment is

required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the

sale or refinancing of such instruments.

Industry Segment and Geographic Information

The Company operates exclusively in the exploration and production segment of the oil and gas industry and all of the Company’s operations

are conducted entirely in the United States. The Company reports as a single industry segment. The Company’s gas marketing function provides

mostly internal services and acts as the first purchaser of natural gas and natural gas liquids produced by the Company in certain cases. The Company

considers its marketing function as ancillary to its oil and gas producing activities. The amount of income these operations generate from marketing

gas produced by third parties is not material to the Company’s results of operations, and segmentation of such activity would not provide a better

understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties

are presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations.

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Off-Balance Sheet Arrangements

The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as

entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating

off-balance sheet arrangements or other contractually narrow or limited purposes. The Company has not been involved in any unconsolidated SPE

transactions.

The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy is the primary

beneficiary of a variable interest entity, that entity is consolidated into SM Energy.

Recently Issued Accounting Standards

On January 1, 2012, the Company adopted new fair value measurement authoritative accounting guidance issued by the FASB, that clarifies

the application of fair value measurement and disclosure requirements and changes particular principles and requirements for measuring fair value. For

each class of assets and liabilities not measured at fair value in the Company’s financial statements but for which fair value is disclosed, this guidance

requires the Company to disclose the nature, characteristics, and risks of the asset or liability and the level of the fair value hierarchy within which the

fair value measurement is categorized. Please refer to Note 11 - Fair Value Measurements in which the changes to the Company’s financial

statements resulting from the new authoritative guidance are presented.

On January 1, 2012, the Company adopted new authoritative accounting guidance issued by the FASB stating an entity that reports items of

other comprehensive income has the option to present the components of comprehensive income in either one continuous financial statement or two

consecutive financial statements, including reclassification adjustments. The adoption of this statement did not have a material impact on the

Company. The Company has elected to present a separate statement of comprehensive income, including the individual components, titled

Consolidated Statements of Comprehensive Income (Loss), as part of these financial statements. Additionally, the Company has elected to present the

reclassification adjustments under the heading Comprehensive Income (Loss), above.

On September 30, 2012, the Company elected to early adopt new authoritative accounting guidance issued by the FASB, which provided

that an entity that tests indefinite-lived intangible assets for impairment has the option to assess qualitative factors to determine whether it is more likely

than not that an asset is impaired as a basis for determining whether a quantitative test is necessary. The adoption of this statement did not have a

material impact on the Company’s financial statements.

 

There are no new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of

December 31, 2012.

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Note 2 – Accounts Receivable and Accounts Payable and Accrued Expenses

Accounts receivable are comprised of the following:

As of December 31,

2012 2011

(in thousands)

Accrued oil, gas, and NGL production revenue $ 160,568 $ 149,384

Amounts due from joint interest owners 42,740 30,784

Receivable due from Mitsui 19,931 —

State severance tax refunds 17,237 14,979

Other 14,329 15,221

Total accounts receivable $ 254,805 $ 210,368

Accounts payable and accrued expenses are comprised of the following:

As of December 31,

2012 2011

(in thousands)

Accrued drilling costs $ 243,611 $ 189,749

Revenue and severance tax payable 65,494 61,613

Accrued lease operating expense 28,037 25,197

Accrued property taxes 9,478 6,994

Joint owner advances 69,639 79,138

Accrued compensation 35,607 43,056

Accrued interest 25,027 14,646

Other 48,734 36,606

Total accounts payable and accrued expenses $ 525,627 $ 456,999

Note 3 – Divestitures and Assets Held for Sale

During 2012, the Company divested of various non-strategic properties located in its Rocky Mountain and Mid-Continent regions for a total

of $57.4 million in total divestiture proceeds, before marketing costs, Net Profits Plan payments, and legal fees (referred throughout this report as

“divestiture proceeds”). The estimated net gain on these divestitures is $6.9 million. The final sales prices related to these divestitures are subject to

normal post-closing adjustments and are expected to be finalized during the first half of 2013. See discussion below regarding the loss on

unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in the accompanying statements of operations.

2011 Divestiture Activity

• Eagle Ford Shale Divestiture. In August 2011, the Company divested of certain operated Eagle Ford shale assets located in its South

Texas & Gulf Coast region. This divestiture was comprised of the Company’s entire operated acreage in LaSalle County, Texas, as well as

an immaterial adjacent block of its operated acreage in Dimmit County, Texas. Total divestiture proceeds were $230.7 million. The final gain

on this divestiture was $193.8 million. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning

Agreement for information on additional Eagle Ford activity in 2011.

• Mid-Continent Divestiture. In June 2011, the Company divested of certain non-strategic assets located in its Mid-Continent region. Total

divestiture proceeds were $35.8 million. The final gain on this divestiture was $28.5 million. 

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• Rocky Mountain Divestiture. In January 2011, the Company divested of certain non-strategic assets located in its Rocky Mountain

region. Total divestiture proceeds were $45.5 million. The final gain on this divestiture was $27.2 million. 

2010 Divestiture Activity

• Permian Divestiture. In December 2010, the Company completed the divestiture of certain non-strategic assets located in its Permian

region. Total divestiture proceeds were $54.7 million. The final gain on this divestiture was $18.4 million.

• Sequel Divestiture. In March 2010, the Company completed the divestiture of certain non-strategic assets located in its Rocky Mountain

region. Total divestiture proceeds were $129.1 million. The final gain on this divestiture was $53.1 million. A portion of the transaction was

structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue

Code”).

• Legacy Divestiture. In February 2010, the Company completed the divestiture of certain non-strategic assets located in its Rocky

Mountain region. Total divestiture proceeds were $125.3 million. The final gain on this divestiture was $66.7 million. A portion of the

transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code.

Assets Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take

place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment

is performed to identify and expense any excess of carrying value over fair value less costs to sell. Subsequent changes to the estimated fair value less

the cost to sell will impact the measurement of assets held for sale for which fair value less costs to sell is determined to be less than the carrying value

of the assets.

As of December 31, 2012, the accompanying balance sheets present $33.6 million of assets held for sale, net of accumulated depletion,

depreciation, and amortization expense. A corresponding asset retirement obligation liability of $1.4 million is separately presented. The assets held

for sale include the Company’s Marcellus shale assets located in Pennsylvania and certain assets located in the Company’s Rocky Mountain region, all

of which are recorded at the lesser of their carrying values or their respective fair value less estimated costs to sell. Write-downs to fair value less

estimated costs to sell are reflected in the gain (loss) on divestiture activity line item in the accompanying statements of operations.

During 2012, the Company reclassified a portion of the assets previously held for sale to assets held and used, as the assets were no longer

being actively marketed. The assets were measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for

any DD&A that would have been recognized had the assets been continuously held and used, or the fair value of the assets at the date they no longer

met the criteria as held for sale. As a result of this measurement, the Company recognized $1.7 million of DD&A expense and a $33.9 million loss

on unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in the accompanying statements of operations.

Subsequent to December 31, 2012, the Company divested of a portion of its properties located in its Rocky Mountain region that were

classified as held for sale at year end. Total divestiture proceeds were $9.2 million. The estimated gain on this divestiture is $2.5 million and is

expected to be finalized during the first half of 2013.

The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accounting under financial

statement presentation authoritative guidance.

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Note 4 – Income Taxes

The provision for income taxes consists of the following:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Current portion of income tax benefit (expense)

Federal $ — $ 1,757 $ (2,903)

State (370) (1,553) (639)

Deferred portion of income tax benefit (expense) 29,638 (123,789) (114,517)

Total income tax benefit (expense) $ 29,268 $ (123,585) $ (118,059)

Effective tax rate 35.0% 36.5% 37.5%

The Company reduces its income tax payable to reflect employee stock option exercises. In 2010, the excess income tax benefit to the

Company associated with stock awards was $854,000. There was no excess income tax benefit associated with stock awards in 2012 or 2011.

The components of the net deferred income tax liabilities are as follows:

As of December 31,

2012 2011

(in thousands)

Deferred tax liabilities:

Oil and gas properties $ 678,624 $ 639,485

Unrealized derivative asset 15,942 13,274

Other 6,443 4,129

Total deferred tax liabilities 701,009 656,888

Deferred tax assets:

Federal and state tax net operating loss carryovers 113,522 23,651

Net Profits Plan liability 29,233 40,148

Stock compensation 18,026 17,728

Pension liability 6,849 5,902

Federal and state tax credit carryovers 5,271 4,301

Other long-term liabilities 4,619 4,908

Total deferred tax assets 177,520 96,638

Valuation allowance (5,315) (3,791)

Net deferred tax assets 172,205 92,847

Total net deferred tax liabilities 528,804 564,041

Less: current deferred income tax liabilities (5,442) (3,307)

Add: current deferred income tax assets 14,021 7,529

Non-current net deferred tax liabilities $ 537,383 $ 568,263

Current federal income tax refundable $ 2,511 $ 5,581

Current state income tax refundable $ 853 $ —

Current state income tax payable $ — $ 774

At December 31, 2012, the Company estimated its federal net operating loss carryforward at $376.6 million, which includes unrecognized

excess income tax benefits associated with stock awards of $93.4 million. The federal net operating loss carryforward begins to expire in 2031. The

Company has estimated state net

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operating loss carryforwards of $361.2 million that expire between 2013 and 2032. The Company has claimed federal research and development

(“R&D”) credit carryforwards of $5.0 million that expire between 2028 and 2031 and other state tax credits of $252,000 that expire between 2013

and 2022. The Company’s valuation allowance relates to charitable contribution carryfowards, state net operating loss carryforwards, state tax credits,

and state and federal income tax benefit amounts, which the Company anticipates will expire before they can be utilized. Permanent items included in

the calculation of income tax for certain states are anticipated to impact the Company’s ability to deduct operating losses and realize federal income tax

deduction benefits in those states, and the Company adjusts its valuation allowances accordingly. The change in the valuation allowance from 2011 to

2012, indicated below, primarily reflects a change in the Company’s position regarding anticipated utilization of charitable contribution carryforward

amounts and cumulative net operating losses attributed to Oklahoma.

Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to

income before income taxes primarily due to the effect of state income taxes, R&D credits, percentage depletion, changes in valuation allowances,

and other permanent differences, as follows:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Federal statutory tax benefit (expense) $ 29,231 $ (118,652) $ (110,214)

(Increase) decrease in tax resulting from:

State tax benefit (expense) (net of federal benefit) 992 (6,458) (7,750)

Research and development credit 970 4,516 —

Change in valuation allowance (1,524) (1,627) 1,039

Statutory depletion 210 341 266

Other (611) (1,705) (1,400)

Income tax benefit (expense) $ 29,268 $ (123,585) $ (118,059)

Acquisitions, divestitures, drilling activity, and basis differentials impacting the prices received for oil, gas, and NGLs affect apportionment

of taxable income to the states where the Company owns oil and gas properties. As its apportionment factors change, the Company’s blended state

income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total income tax reported in the current

year and is reflected in state taxes in the table above. Items affecting state apportionment factors are evaluated at the beginning of each year, after

completion of the prior year income tax return, and when significant acquisition, divestiture or changes in drilling activity occurs during the year.

The Company and its subsidiaries file income tax returns in the United States federal jurisdiction and in various states. With certain

exceptions, the Company is no longer subject to United States federal or state income tax examinations by these tax authorities for years before 2008.

In the third quarter of 2011, the Company completed a multi-year R&D credit study and filed amended federal returns to claim a credit for all open

years. Federal tax law allowing for the calculation of an R&D credit for 2012 was not enacted until after December 31, therefore, no 2012 research

activities are reflected in the table above.

In the first quarter of 2011, the Company received a $5.5 million refund from its 2006 tax year as a result of a net operating loss carryback

claim from the 2008 tax year. In the fourth quarter of 2010, the Internal Revenue Service initiated an audit of the Company for the 2009 tax year. The

audit was concluded in the second quarter of 2011 with a nominal decrease to the Company’s total 2005 refund claim of $25.0 million. A quick

refund claim of $22.9 million from 2005 was received in the third quarter of 2010. The balance was received in the fourth quarter of 2011. The

Internal Revenue Service initiated an audit in the first quarter of 2012 for the 2007 and 2010 tax years. This audit was still ongoing at year-end.

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The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax

benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations

includes a negligible amount associated with income taxes. In 2011, the Company also recorded a negligible amount of penalty expense associated

with income taxes as a general and administrative expense. There were no penalties for 2012 and 2010.

The total amount recorded for unrecognized tax benefits is presented below:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Beginning balance $ 1,961 $ 807 $ 884

Additions based on tax positions related to current year — 1,172 —

Additions for tax positions of prior years 317 183 244

Reductions for lapse of statute of limitations — (201) (321)

Ending balance $ 2,278 $ 1,961 $ 807

Note 5 – Long-term Debt

Revolving Credit Facility

The Company executed a Fourth Amended and Restated Credit Agreement on May 27, 2011. This amended revolving credit facility replaced

the Company’s previous facility. The Company incurred $8.7 million of deferred financing costs in association with the amended credit

facility. Borrowings under the facility are secured by substantially all of the Company’s proved oil and gas properties. The credit facility has a

maximum loan amount of $2.5 billion, current aggregate lender commitments of $1.0 billion, and a maturity date of May 27, 2016. The borrowing

base is subject to regular semi-annual redeterminations by the Company’s lenders. The borrowing base redetermination process considers the value of

the Company’s oil and gas properties. On August 31, 2012, the lending group redetermined the Company's reserve-backed borrowing base under the

credit facility at an amount of $1.55 billion, an increase from $1.4 billion. The next scheduled re-determination date is April 1, 2013.

The Company must comply with certain financial and non-financial covenants under the terms of its credit facility agreement, including the

limitation of the Company’s dividends to no more than $50.0 million per year. The Company was in compliance with all financial covenants under the

credit facility as of December 31, 2012, and through the filing date of this report. 

Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interest at the London

Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue

interest at Prime plus the applicable margin from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate

commitment amount and are included in interest expense in the accompanying statements of operations.

Borrowing Base Utilization Grid

Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90%

Eurodollar Loans 1.500% 1.750% 2.000% 2.250% 2.500%

ABR Loans or Swingline Loans 0.500% 0.750% 1.000% 1.250% 1.500%

Commitment Fee Rate 0.375% 0.375% 0.500% 0.500% 0.500%

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The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under our credit

facility as of February 14, 2013, December 31, 2012, and December 31, 2011.

As of February 14, 2013 As of December 31, 2012 As of December 31, 2011

(in millions)

Credit facility balance $ 407.5 $ 340.0 $ —

Letters of credit (1) $ 0.8 $ 0.8 $ 0.6

Available borrowing capacity $ 591.7 $ 659.2 $ 999.4

(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.

3.50% Senior Convertible Notes Due 2027

On April 2, 2012, the Company called for redemption all of its outstanding 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior

Convertible Notes”). The call for redemption resulted in holders of $281.3 million aggregate principal amount electing to convert their notes. The

Company settled the principal amount of all converted 3.50% Senior Convertible Notes in cash and settled the excess conversion value by issuing

864,106 shares of its common stock. The Company redeemed the remaining $6.2 million of aggregate principal amount of notes that were not

converted on the redemption date at par plus accrued interest in cash. The Company used funds borrowed under its credit facility to pay the cash

portion of the settlement.

2023 Notes

On June 29, 2012, the Company issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023. The 2023 Notes were

issued at par and mature on January 1, 2023. The Company received net proceeds of $392.1 million after deducting fees of $7.9 million, which are

being amortized as deferred financing costs over the life of the 2023 Notes. The net proceeds were used to reduce the Company’s outstanding credit

facility balance.

Prior to July 1, 2015, the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principal amount of the 2023

Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and

unpaid interest. The Company may also redeem the 2023 Notes, in whole or in part, at any time prior to July 1, 2017, at a redemption price equal to

100 percent of the principal amount of the 2023 Notes to be redeemed, plus a specified make-whole premium and accrued and unpaid interest to the

applicable redemption date.

On or after July 1, 2017, the Company may also redeem all or, from time to time, a portion of the 2023 Notes at the redemption prices set

forth below, during the twelve-month period beginning on July 1 of each applicable year, expressed as a percentage of the principal amount

redeemed, plus accrued and unpaid interest:

2017 103.250%

2018 102.167%

2019 101.083%

2020 and thereafter 100.000%

The 2023 Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future

unsecured senior debt, and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 2023 Notes. The

Company is subject to certain covenants under the indenture governing the 2023 Notes that limit the Company’s ability to incur additional

indebtedness, issue preferred stock, and make restricted payments, including dividends. However, the first $6.5 million of dividends paid each year

are not restricted by this covenant. The Company was in compliance with all covenants under its 2023 Notes as of December 31, 2012, and through

the filing date of this report.

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Additionally, on June 29, 2012, the Company entered into a registration rights agreement that provides holders of the 2023 Notes certain

registration rights under the Securities Act of 1933, as amended (the “Securities Act”). The Company satisfied its obligations to exchange its

outstanding $400.0 million 2023 Notes for notes registered under the Securities Act on October 30, 2012.

2021 Notes

On November 8, 2011, the Company issued $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021. The 2021 Notes

were issued at par and mature on November 15, 2021. The Company received net proceeds of $343.1 million after deducting fees of $6.9 million,

which are being amortized as deferred financing costs over the life of the 2021 Notes. The net proceeds were used for general corporate purposes and

to reduce the Company’s outstanding credit facility balance.

Prior to November 15, 2014, the Company may redeem up to 35 percent of the aggregate principal amount of the 2021 Notes with the net

cash proceeds of one or more equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The

Company may also redeem the 2021 Notes, in whole or in part, at any time prior to November 15, 2016, at a redemption price equal to 100% of the

principal amount, plus a specified make-whole premium and accrued and unpaid interest . 

The Company may also redeem all or, from time to time, a portion of the 2021 Notes on or after November 15, 2016, at the prices set forth

below, during the twelve-month period beginning on November 15 of the applicable year, expressed as a percentage of the principal amount

redeemed, plus accrued and unpaid interest:

2016 103.250%

2017 102.167%

2018 101.083%

2019 and thereafter 100.000%

The 2021 Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future

unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 2021 Notes. The

Company is subject to certain covenants under the indenture governing the 2021 Notes that limit incurring additional indebtedness, issuing preferred

stock, and making restricted payments, including dividends. The first $6.5 million of dividends paid each year are not restricted by this covenant. The

Company was in compliance with all covenants under its 2021 Notes as of December 31, 2012 and through the filing date of this report.

Additionally, on November 8, 2011, the Company entered into a registration rights agreement that provides holders of the 2021 Notes certain

registration rights for the 2021 Notes under the Securities Act. The Company satisfied its obligations to exchange its outstanding $350.0 million of its

2021 Notes for notes registered under the Securities Act on March 7, 2012.

2019 Notes

On February 7, 2011, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2019. The 2019

Notes were issued at par and mature on February 15, 2019. The Company received net proceeds of $341.1 million after deducting fees of $8.9

million, which are being amortized as deferred financing costs over the life of the 2019 Notes. The net proceeds were used to repay borrowings under

the Company’s previous credit facility, to fund the Company’s ongoing capital expenditure program, and for general corporate purposes.

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Prior to February 15, 2014, the Company may redeem up to 35 percent of the aggregate principal amount of the 2019 Notes with the net

cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount thereof, plus accrued and unpaid interest.

The Company may also redeem the 2019 Notes, in whole or in part, at any time prior to February 15, 2015, at a redemption price equal to 100% of

the principal amount, plus a specified make-whole premium and accrued and unpaid interest . 

The Company may also redeem all or, from time to time, a portion of the 2019 Notes on or after February 15, 2015, at the prices set forth

below, during the twelve-month period beginning on February 15 of the applicable year, expressed as a percentage of the principal amount redeemed,

plus accrued and unpaid interest:

2015 103.313%

2016 101.656%

2017 and thereafter 100.000%

The 2019 Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future

unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the 2019 Notes. The

Company is subject to certain covenants under the indenture governing the 2019 Notes that limit incurring additional indebtedness, issuing preferred

stock, and making restricted payments, including dividends. The first $6.5 million of dividends paid each year are not restricted by this covenant. The

Company was in compliance with all covenants under its 2019 Notes as of December 31, 2012 and through the filing date of this report.

Additionally, on February 7, 2011, the Company entered into a registration rights agreement that provides holders of the 2019 Notes certain

registration rights for the 2019 Notes under the Securities Act. The Company satisfied its obligations to exchange its outstanding $350.0 million of its

2019 Notes for notes registered under the Securities Act on January 11, 2012.

Capitalized Interest

Capitalized interest costs for the Company for the years ended December 31, 2012, 2011, and 2010, were $12.1 million, $10.8 million, and

$4.3 million, respectively.

Note 6 – Commitments and Contingencies

Commitments

The Company has entered into various agreements, which include drilling rig contracts of $91.4 million, gathering, transportation, and

processing through-put commitments of $858.7 million, office leases, including maintenance, of $55.3 million, and other miscellaneous contracts

and leases of $7.2 million. The annual minimum payments for the next five years and total minimum lease payments thereafter are presented below:

Years Ending December 31, (in thousands)

2013 $ 127,753

2014 111,674

2015 99,854

2016 102,540

2017 101,456

Thereafter 469,348

Total $ 1,012,625

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The Company has gathering, processing, and transportation through-put commitments with various parties that require delivery of a fixed

determinable quantity of product. The aggregate minimum commitment to deliver is 1,515 Bcf of natural gas and 36 MMBbls of oil. These contracts

expire at various dates through 2023, and the total amount of the commitment is approximately $858.7 million. The Company will be required to

make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. As of the filing date of this report, the

Company does not expect to incur any material shortfalls.

The Company leases office space under various operating leases with terms extending as far as May 31, 2024. Rent expense for 2012,

2011, and 2010 was $5.4 million, $3.7 million, and $2.7 million, respectively. The Company also leases office equipment under various operating

leases.

In addition to the amounts in the above table, the Company entered into a capital project commencing in 2011 for the development of

midstream infrastructure in the Company’s non-operated Eagle Ford shale play. Pursuant to the terms of the agreement for the construction, ownership

and operation of these assets, the Company is required to pay its portion of the costs for the next two years. Based on current estimates, the Company

does not expect its costs to exceed $67 million during this time.

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a

liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims

will not have a material effect on the results of operations, the financial position, or the cash flows of the Company.

The Company was a defendant in litigation wherein the plaintiffs claimed an aggregate overriding royalty interest of 7.46875 percent in

production from approximately 22,000 of the Company’s net acres in the Eagle Ford shale play in South Texas. The plaintiffs sought to quiet title to

their claimed overriding royalty interest and to recover unpaid overriding royalty interest proceeds allegedly due. The Company believes that the

claimed overriding royalty interest has been terminated under the governing agreements and the applicable law, and has contested the plaintiffs’ claims.

Both parties filed motions for summary judgment, and on February 8, 2011, the District Court in Webb County, Texas, issued an order granting

plaintiffs’ motion for summary judgment and denying the Company’s motion for summary judgment. On September 30, 2011, the District Court

entered final judgment for the plaintiffs and awarded then current damages of approximately $5.1 million, which included prejudgment interest. The

District Court also awarded attorneys’ fees and costs to the plaintiffs. The Company appealed the District Court’s judgment and obtained a stay

pending appeal that prevented the plaintiffs from executing on the judgment.

On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this case, which reversed the summary

judgment granted to the plaintiffs by the District Court and rendered judgment that the plaintiffs take nothing. Accordingly, based on the judgment of

the Fourth Court of Appeals, the plaintiffs are not entitled to their claimed aggregate 7.46875 percent overriding royalty interest, nor are they entitled

to the claimed damages related to the overriding royalty interest, attorneys fees or costs. The plaintiffs filed a petition with the Supreme Court of

Texas requesting a review of the Fourth Court of Appeals judgment. The Supreme Court of Texas denied this petition for review on February 15,

2013. As a result, the decision of the Fourth Court of Appeals is dispositive and its dismissal of the plaintiffs’ claims is final.

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On January 27, 2011, Chieftain filed a Class Action Petition against the Company in the District Court of Beaver County, Oklahoma,

claiming damages related to royalty valuation on all of the Company's Oklahoma wells. These claims include breach of contract, breach of fiduciary

duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of postproduction costs. The Company removed this lawsuit to the United States District Court for the Western District of Oklahoma on February 22, 2011.

The Company has responded to the petition and denied the allegations. The court has not yet ruled on Chieftain's motion to certify the putative class,

and has stayed any such ruling until the United States Court of Appeals for the Tenth Circuit issues its ruling on class certification in two similar

royalty class action lawsuits, where the defendants have appealed such certification. The opinion from the Tenth Circuit is expected during the

summer of 2013.

This case involves complex legal issues and uncertainties; a potentially large class of plaintiffs, and a large number of related producing

properties, lease agreements and wells; and an alleged class period commencing in 1988 and spanning the entire producing life of the wells. Because

the proceedings are in the early stages, with substantive discovery yet to be conducted, the Company is unable to estimate what impact, if any, the

action will have on its financial condition, results of operations or cash flows. The Company is still evaluating the claims, but believes that it has

properly valued and paid royalty under Oklahoma law and has and will continue to vigorously defend this case.

Note 7 – Compensation Plans

Cash Bonus Plan

The Company has a cash bonus plan based on a performance measurement framework whereby selected eligible employee participants may

be awarded an annual cash bonus. The plan document provides that no participant may receive an annual bonus under the plan of more than 200

percent of his or her base salary. As the plan is currently administered, any awards under the plan are based on Company and regional performance

and are then further refined by individual performance. The Company accrues cash bonus expense based upon the Company’s current year

performance. Included in general and administrative and exploration expense in the accompanying statements of operations are $16.3 million, $23.9

million, and $21.6 million of cash bonus expense related to the specific performance years ended December 31, 2012, 2011, and 2010, respectively.

Equity Plan

There are several components to the Company's Equity Plan that are described in this section. Various types of equity awards have been

granted by the Company in different periods.

As of December 31, 2012, 1.4 million shares of common stock remained available for grant under the Equity Plan. The issuance of a direct

share benefit such as a share of common stock, a restricted share, a RSU, or a PSU counts as 1.43 shares against the number of shares available to

be granted under the Equity Plan. Each PSU has the potential to count as 2.86 shares against the number of shares available to be granted under the

Equity Plan based on the final performance multiplier. Stock option grants count as one share for each instrument granted against the number of shares

available to be granted under the Equity Plan. Stock options were issued out of the St. Mary Land & Exploration Company Stock Option Plan and the

St. Mary Land & Exploration Company Incentive Stock Option Plan, both predecessors to the Equity Plan.

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Performance Share Units Under the Equity Incentive Compensation Plan

The Company grants PSUs to eligible employees as a part of its equity incentive compensation program. The PSU factor is based on the

Company’s performance after completion of a three-year performance period. The performance criteria for the PSUs are based on a combination of

the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative measure of the Company’s TSR compared

with the annualized TSR of an index comprised of certain peer companies for the performance period. PSUs are recognized as general and

administrative and exploration expense over the vesting period of the award.

The fair value of PSUs was measured at the grant date with a stochastic process method using the Geometric Brownian Motion Model

(“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not

deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of

the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year

performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these

simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are

stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by

which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend

yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three year vesting period, as well as the

volatilities and dividend yields for each of the Company’s peers.

Total expense recorded for PSUs was $18.2 million, $19.7 million, and $17.7 million for the years ended December 31, 2012, 2011, and

2010, respectively. As of December 31, 2012, there was $19.6 million of total unrecognized expense related to PSUs, which is being amortized

through 2015.

A summary of the status and activity of PSUs is presented in the following table:

For the Years Ended December 31,

2012 2011 2010

PSUs

WeightedAverage GrantDate Fair Value PSUsWeighted-Average

Grant-Date Fair

Value PSUs

WeightedAverage GrantDate Fair

Value

Non-vested at beginning of

year(1) 885,894 $ 57.52 1,110,666 $ 39.48 1,069,090 $ 32.52

Granted(1) 314,853 $ 51.98 266,282 $ 91.45 387,651 $ 52.35

Vested(1) (493,679) $ 44.72 (364,172) $ 35.74 (210,801) $ 31.18

Forfeited(1) (37,760) $ 65.35 (126,882) $ 33.32 (135,274) $ 34.28

Non-vested at end of year(1) 669,308 $ 63.91 885,894 $ 57.52 1,110,666 $ 39.48

(1) The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending on the ending three-year performance multiplier,

which ranges from zero to two.

The fair value of the PSUs granted in 2012, 2011, and 2010 was $16.4 million, $24.3 million, and $20.3 million for the 2012, 2011, and

2010 grants, respectively. The PSUs granted in 2012 will vest 1/3 on each of the first three anniversary dates of their issuance. PSUs granted prior to

2012 vest 1/7th, 2/7ths, and 4/7ths on the first three anniversary dates of their issuances.

The total fair value of PSUs that vested during the years ended December 31, 2012, 2011, and 2010 was $22.1 million, $13.0 million, and

$6.6 million, respectively.

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During the year ended December 31, 2012, the Company settled 609,714 PSUs that were granted in 2009, and which had earned a twotimes multiplier, by issuing a net 812,562 shares of the Company’s common stock in accordance with the terms of the PSU awards. The Company

and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the

plan document and award agreements. As a result, the remaining 406,866 shares were withheld to satisfy income and payroll tax withholding

obligations that occurred upon delivery of the shares underlying those PSUs for 2012.

During the year ended December 31, 2011, the Company settled PSUs that were granted in 2008, which earned a 0.8 times multiplier, by

issuing a net 206,468 shares of the Company’s common stock in accordance with the terms of the PSU awards. The Company and the majority of

grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and

award agreements. As a result, 98,955 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of

the shares underlying those PSUs for 2011.

Restricted Stock Units Under the Equity Incentive Compensation Plan

The Company grants RSUs to eligible employees as a part of its equity incentive compensation program. Restrictions and vesting periods for

the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each RSU represents

a right for one share of the Company’s common stock to be delivered upon settlement of the award at the end of a specified period. RSUs are

recognized as general and administrative and exploration expense over the vesting period of the award.

The total expense associated with RSUs for the years ended December 31, 2012, 2011, and 2010, was $9.8 million, $5.3 million, and

$7.7 million, respectively. As of December 31, 2012, there was $14.4 million of total unrecognized expense related to unvested RSU awards, which

is being amortized through 2015. The Company records compensation expense associated with the issuance of RSUs based on the fair value of the

awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of grant.

A summary of the status and activity of non-vested RSUs is presented below:

For the Years Ended December 31,

2012 2011 2010

RSUs

WeightedAverage

Grant-Date

Fair Value RSUs

WeightedAverage

Grant-Date

Fair Value RSUs

WeightedAverage

Grant-Date

Fair Value

Non-vested at beginning of year 308,877 $ 44.33 333,359 $ 31.16 407,123 $ 34.67

Granted 379,332 $ 49.47 98,952 $ 72.69 128,865 $ 40.31

Vested (166,672) $ 32.72 (105,820) $ 30.61 (160,398) $ 46.30

Forfeited (25,293) $ 51.06 (17,614) $ 36.80 (42,231) $ 35.43

Non-vested at end of year 496,244 $ 51.81 308,877 $ 44.33 333,359 $ 31.16

The fair value of RSUs granted in 2012, 2011, and 2010 was $18.8 million, $7.2 million, and $5.2 million, respectively. The RSUs

granted in 2012 will vest 1/3 on each of the first three anniversary dates of the award. RSUs granted prior to 2012 vest 1/7th, 2/7ths, and 4/7ths on the

first three anniversary dates of their issuances.

The total fair value of RSUs that vested during the years ended December 31, 2012, 2011, and 2010, was $5.4 million, $3.2 million, and

$7.4 million, respectively.

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During the years ended December 31, 2012, 2011, and 2010, the Company settled 166,670, 105,820, and 160,381 RSUs, respectively.

The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as

provided for in the plan document and award agreements. As a result, the Company issued net shares of common stock of 116,813, 72,305, and

113,103 for 2012, 2011, and 2010, respectively. The remaining 49,857, 33,515, and 47,278 shares were withheld to satisfy income and payroll

tax withholding obligations that occurred upon the delivery of the shares underlying those RSUs for 2012, 2011, and 2010, respectively.

Stock Option Grants Under the Equity Incentive Compensation Plan

The Company has previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary

Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options occurred on December 31, 2004. Stock options to

purchase shares of the Company’s common stock had been granted to eligible employees and members of the Board of Directors. All options granted

under the option plans were granted at exercise prices equal to the respective closing market price of the Company’s underlying common stock on the

grant dates. All stock options granted under the option plans are exercisable for a period of up to ten years from the date of grant. As of

December 31, 2012, there was no unrecognized compensation expense related to stock option awards.

A summary of activity associated with the Company’s Stock Option Plans during the last three years is presented in the following table:

Weighted -

Average Aggregate

Exercise Intrinsic

Shares Price Value

For the year ended December 31, 2010

Outstanding, start of year 1,274,920 $ 13.31

Exercised (346,377) $ 13.77 $ 11,281,865

Forfeited (7,778) $ 16.66

Outstanding, end of year 920,765 $ 13.11 $ 42,192,057

Vested and exercisable at end of year 920,765 $ 13.11 $ 42,192,057

For the year ended December 31, 2011

Outstanding, start of year 920,765 $ 13.11

Exercised (412,551) $ 12.19 $ 24,359,240

Forfeited — $ —

Outstanding, end of year 508,214 $ 13.86 $ 30,109,110

Vested and exercisable at end of year 508,214 $ 13.86 $ 30,109,110

For the year ended December 31, 2012

Outstanding, start of year 508,214 $ 13.86

Exercised (240,368) $ 12.65 $ 11,842,575

Forfeited — $ —

Outstanding, end of year 267,846 $ 14.95 $ 9,983,177

Vested and exercisable at end of year 267,846 $ 14.95 $ 9,983,177

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A summary of additional information related to options outstanding as of December 31, 2012, follows:

Options Outstanding and Exercisable

Number WeightedOf Options Average

Outstanding Remaining

Exercise and Contractual

Price(1) Exercisable Life

$ 12.53 33,805 0.25 years

$ 12.66 28,053 0.75 years

$ 13.39 17,142 0.81 years

$ 13.65 35,893 0.50 years

$ 14.25 104,093 1 year

$ 20.87 48,860 2 years

Total 267,846

(1) Exercise price is equal to the weighted average exercise price.

The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing model.

Cash flows resulting from excess tax benefits are classified as part of cash flows from financing activities. Excess tax benefits are realized

tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised options in excess of the deferred tax asset attributable to stock

compensation costs for such equity awards. The Company recorded $854,000 of excess tax benefits for the year ended December 31, 2010, as cash

inflows from financing activities. The Company recorded no excess tax benefits for the years ended December 31, 2012, and December 31, 2011.

Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2012, 2011, and 2010, was $3.0

million, $5.0 million, and $4.8 million, respectively.

Director Shares

In 2012, 2011, and 2010, the Company issued 30,486, 21,568, and 24,258 shares, respectively, of the Company’s common stock held as

treasury shares to its non-employee directors pursuant to the Company’s Equity Plan. The Company recorded compensation expense related to these

issuances of $1.3 million, $1.2 million, and $781,000 for the years ended December 31, 2012, 2011, and 2010, respectively.

Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock

through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in fair market value from purchases

for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the

purchase period. All shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to

qualify under Section 423 of the IRC. The Company has 1.3 million shares available under the ESPP for issuance as of December 31, 2012. Shares

issued under the ESPP totaled 66,485 in 2012, 41,358 in 2011, and 52,948 in 2010. Total proceeds to the Company for the issuance of these shares

were $2.8 million in 2012, $2.3 million in 2011, and $1.7 million in 2010, respectively.

The fair value of ESPP shares was measured at the date of grant using the Black-Scholes-Merton option-pricing model. Expected volatility

was calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates

with maturities consistent with a six month vesting period.

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The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions:

For the Years Ended December 31,

2012 2011 2010

Risk free interest rate 0.1% 0.2% 0.2%

Dividend yield 0.2% 0.2% 0.3%

Volatility factor of the expected market

price of the Company’s common stock 47.8% 36.3% 46.3%

Expected life (in years) 0.5 years 0.5 years 0.5 years

The Company expensed $948,000, $682,000, and $550,000 for the years ended December 31, 2012, 2011, and 2010, respectively, based

on the estimated fair value of grants.

401(k) Plan

The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act

of 1974. The 401(k) Plan allows eligible employees to contribute up to 60 percent of their base salaries up to the contribution limits established under

the IRC. The Company matches each employee’s contribution up to six percent of the employee’s base salary and may make additional contributions

at its discretion. The Company’s matching contributions to the 401(k) Plan were $3.5 million, $2.9 million, and $2.5 million for the years ended

December 31, 2012, 2011, and 2010, respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of these

years.

Net Profits Plan

Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during a year were designated within a specific

pool. Key employees recommended by senior management and designated as participants by the Compensation Committee of the Company’s Board of

Directors and employed by the Company on the last day of that year became entitled to payments under the Net Profits Plan after the Company has

received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, 10 percent of future net cash flows generated by the

pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the

participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the

Net Profits Plan at the 10 percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan.

As a result, the 2007 pool was the last Net Profits Plan pool established by the Company.

Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expense or exploration

expense are detailed in the table below:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

General and administrative expense $ 15,565 $ 19,326 $ 19,798

Exploration expense 1,751 2,091 2,633

Total $ 17,316 $ 21,417 $ 22,431

Additionally, the Company made or accrued cash payments under the Net Profits Plan of $2.3 million, $6.3 million, and $26.1 million for

the years ended December 31, 2012, 2011, and 2010, respectively, as a result of divestiture proceeds. The cash payments are accounted for as a

reduction in the gain on divestiture activity in the accompanying statements of operations.

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The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the

accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit in the current period. The

amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or

exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being

realized through current period production. If the Company allocated the change in liability to these specific functional line items, based on the current

allocation of actual distributions made by the Company, such expenses or benefits would predominately be allocated to general and administrative

expense. The amount that would be allocated to exploration expense is minimal in comparison. Over time, less of the amount distributed relates to

prospective exploration efforts as more of the amount distributed is to individuals that have terminated employment and do not provide ongoing

exploration support to the Company.

Note 8 – Pension Benefits

The Company has a non-contributory defined benefit pension plan covering substantially all employees who meet age and service

requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management

employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”).

Obligations and Funded Status for Both Pension Plans

The Company recognizes the funded status (i.e., the difference between the fair value of plan assets and the projected benefit obligation) of

the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to

accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by

plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit

obligation uses the same factors as the projected benefit obligation but excludes the effects of assumed future salary increases. The Company’s

measurement date for plan assets and obligations is December 31.

For the Years Ended December 31,

2012 2011

(in thousands)

Change in benefit obligation:

Projected benefit obligation at beginning of year $ 29,480 $ 23,867

Service cost 4,934 3,800

Interest cost 1,374 1,184

Plan amendments — 170

Actuarial loss 5,467 1,957

Benefits paid (1,018) (1,498)

Projected benefit obligation at end of year 40,237 29,480

Change in plan assets:

Fair value of plan assets at beginning of year 13,940 10,332

Actual return on plan assets 1,952 (176)

Employer contribution 5,380 5,260

Benefits paid (1,018) (1,476)

Fair value of plan assets at end of year 20,254 13,940

Funded status at end of year $ (19,983) $ (15,540)

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The Company’s underfunded status for the Pension Plans for the years ended December 31, 2012 and 2011, is $20.0 million and $15.5

million, respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. No plan assets of the Qualified

Pension Plan were returned to the Company during the fiscal year ended December 31, 2012. There are no plan assets in the Nonqualified Pension

Plan. The plan was amended in 2011 to increase the vesting percent to 40 percent after attaining two years of service and increasing by 20 percent per

year until fully vested. The impact of this change in the vesting schedule is reflected in plan amendments in the table above.

Information for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets for Both Plans

As of December 31,

2012 2011

(in thousands)

Projected benefit obligation $ 40,237 $ 29,480

Accumulated benefit obligation $ 29,437 $ 21,697

Less: Fair value of plan assets (20,254) (13,940)

Underfunded accumulated benefit obligation $ 9,183 $ 7,757

Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the

interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated

value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension

expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term

rate of return assumptions. Amortization of unrecognized net gain or loss resulting from actual experience different from that assumed and from

changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit

cost for a year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit

obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of

participating employees expected to receive benefits under the plan.

Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss as of

December 31, 2012, and 2011, consist of:

As of December 31,

2012 2011

(in thousands)

Unrecognized actuarial losses $ 12,427 $ 8,501

Unrecognized prior service costs 153 170

Unrecognized transition obligation — —

Accumulated other comprehensive loss $ 12,580 $ 8,671

The estimated net loss that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal

year is $876,000.

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Pre-tax changes recognized in other comprehensive income (loss) during 2012, 2011, and 2010, were as follows:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Net actuarial gain (loss) $ (4,680) $ (3,014) $ (1,937)

Prior service cost — (170) —

Less: Amortization of:

Prior service cost (17) — —

Actuarial loss (754) (405) (367)

Total other comprehensive income (loss) $ (3,909) $ (2,779) $ (1,570)

Components of Net Periodic Benefit Cost for Both Pension Plans

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Components of net periodic benefit cost

Service cost $ 4,934 $ 3,800 $ 3,392

Interest cost 1,374 1,184 1,120

Expected return on plan assets that reduces periodic

pension cost (1,165) (880) (638)

Amortization of prior service cost 17 — —

Amortization of net actuarial loss 754 405 367

Net periodic benefit cost $ 5,914 $ 4,509 $ 4,241

Gains and losses in excess of 10 percent of the greater of the benefit obligation and the market-related value of assets are amortized over the

average remaining service period of active participants.

Pension Plan Assumptions

Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows:

As of December 31,

2012 2011 2010

Projected benefit obligation

Discount rate 3.9% 4.7% 5.3%

Rate of compensation increase 6.2% 6.2% 6.2%

Net periodic benefit cost

Discount rate 4.7% 5.3% 6.1%

Expected return on plan assets 7.5% 7.5% 7.5%

Rate of compensation increase 6.2% 6.2% 6.2%

The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in

a manner necessary to meet the future benefit obligation of the Pension Plans. The policy does not permit the direct investment of plan assets in the

Company’s securities. The Qualified Pension Plan's investment horizon is long-term and accordingly the target asset allocations encompass a strategic,

long-term

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perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of

diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied.

The Qualified Pension Plan's investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The

investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class

of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a

periodic basis to maintain the target allocations. The weighted-average asset allocation of the Qualified Pension Plan is as follows:

Target As of December 31,

Asset Category 2013 2012 2011

Equity securities 44.0% 42.7% 61.8%

Debt securities 33.0% 32.8% 37.7%

Other 23.0% 24.5% 0.5%

Total 100.0% 100.0% 100.0%

There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return on plan assets of

7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan for 2012 and 2011. Factors considered in determining

the expected rate of return include the long-term historical rate of return provided by the equity and debt securities markets and input from the

investment consultants and trustees managing the plan assets. The difference in investment income using the projected rate of return compared to the

actual rates of return for the past two years was not material and will not have a material effect on the accompanying statements of operations or cash

flows from operating activities in future years.

Fair Value Assumptions

The fair value of the Company’s Qualified Pension Plan assets as of December 31, 2012, utilizing the fair value hierarchy discussed in Note

11 – Fair Value Measurements is as follows:

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Fair Value Measurements Using:

Actual Asset

Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs

(in thousands)

Cash and Money Market Funds 3.8% $ 778 $ 778 $ — $ —

Equity Securities

Domestic (1) 29.2% 5,920 5,920 — —

International (2) 13.5% 2,740 2,740 — —

Total Equity Securities 42.7% 8,660 8,660 — —

Fixed Income Securities

High-Yield Bonds (3) 6.1% 1,240 1,240 — —

Core Fixed Income (4) 20.8% 4,204 4,204 — —

Floating Rate Corp Loans (5) 5.9% 1,186 1,186 — —

Total Fixed Income Securities 32.8% 6,630 6,630 — —

Other Securities:

Commodities (6) 3.3% 669 669 — —

Real Estate (7) 3.9% 783 — — 783

Hedge Fund (8) 13.5% 2,734 1,133 — 1,601

Total Other Securities 20.7% 4,186 1,802 — 2,384

Total Investments 100.0% $ 20,254 $ 17,870 $ — $ 2,384

(1) Equity securities of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand.

(2) International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid

markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial

productivity at attractive valuations.

(3) High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased

level of default risk, security selection focuses on credit-risk analysis.

(4) The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay's

Capital Aggregate Bond Index with a modest amount of variability in duration around the index. 

(5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level

of interest rates. 

(6) Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities.

(7) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate

entails a long-term time horizon, periodic valuations, and potentially low liquidity. 

(8) The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of

funds that invests both long and short using a variety of investment strategies. 

Included below is a summary of the changes in Level 3 plan assets (in thousands):

December 31, 2011 $ —

Purchases 2,329

Investment Returns 55

December 31, 2012 $ 2,384

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The fair value of the Company’s pension plan assets as of December 31, 2011, is as follows:

Fair Value Measurements Using:

Actual Asset

Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs

(in thousands)

Cash and Money Market Funds 0.5% $ 66 $ 66 $ — $ —

Equity Securities (1)

Domestic (2) 47.1% 6,568 6,568 — —

International (3) 14.7% 2,048 2,048 — —

Total Equity Securities 61.8% 8,616 8,616 — —

Fixed Income Securities

Intermediate Term Bond (4) 37.7% 5,258 5,258 — —

Total Investments 100.0% $ 13,940 $ 13,940 $ — $ —

(1) Certain amounts have been reclassified to conform to current-year presentation.

(2) United States equities are invested in companies that trade on active exchanges within the United States and are well diversified by industry sector and

equity style, such as growth and value strategies, and passive management strategies are employed.

(3) International equities are invested in companies that trade on active exchanges outside the United States and are well diversified among more developed

markets. Active and passive strategies are employed.

(4) Intermediate term bonds seek total return. At least 80% of this fund is invested in a diversified portfolio of bonds, which include all types of securities. It

invests primarily in bonds of corporate and governmental issues located in the United States and foreign countries, including emerging markets, all of

which trade on active exchanges.

Contributions

The Company contributed $5.4 million, $5.3 million, and $1.7 million, to the Pension Plans in the years ended December 31, 2012, 2011,

and 2010, respectively. The Company is required to make a $373,000 contribution to the Pension Plans in 2013.

Benefit Payments

The Pension Plans made actual benefit payments of $1.0 million, $1.5 million, and $1.7 million in the years ended December 31, 2012,

2011, and 2010, respectively. Expected benefit payments over the next ten years are as follows (in thousands):

Years Ending December 31,

2013 $ 2,631

2014 $ 2,385

2015 $ 2,715

2016 $ 3,298

2017 $ 3,885

2018 through 2022 $ 29,884

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Note 9 – Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for

the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time

a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The

Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted

liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included

in the operating section of the Company’s accompanying statements of cash flows.

The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives,

estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using the creditadjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s

abandonment liabilities range from 5.5 percent to 12 percent. Revisions to the liability could occur due to changes in estimated abandonment costs or

well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells.

A reconciliation of the Company’s asset retirement obligation liability is as follows:

As of December 31,

2012 2011

(in thousands)

Beginning asset retirement obligation $ 95,906 $ 82,849

Liabilities incurred 13,050 5,465

Liabilities settled (8,101) (8,365)

Accretion expense 4,679 5,948

Revision to estimated cash flows 14,984 10,009

Ending asset retirement obligation $ 120,518 $ 95,906

As of December 31, 2012, and 2011, the Company had $1.4 million and $1.3 million, respectively, of asset retirement obligation associated

with the oil and gas properties held for sale included in a separate line item on the Company’s accompanying balance sheets. Additionally, as of

December 31, 2012, and 2011, accounts payable and accrued expenses contain $6.2 million and $7.5 million, respectively, related to the Company’s

current asset retirement obligation liability for estimated plugging and abandonment costs associated with platforms that are being relinquished or

retired.

Note 10 – Derivative Financial Instruments

The Company has entered into various commodity derivative contracts to mitigate a portion of the exposure to potentially adverse market

changes in commodity prices and the associated impact on cash flows. The Company’s derivative contracts in place include swap and collar

arrangements for oil, gas, and NGLs. As of December 31, 2012, the Company has commodity derivative contracts outstanding through the third

quarter of 2015 for a total of 10.1 million Bbls of oil production, 80.7 million MMBtu of gas production, and 1.2 million Bbls of NGL production.

As of February 14, 2013, the Company had commodity derivative contracts in place through the fourth quarter of 2015 for a total of 14.5 million

Bbls of oil, 114.8 million MMBtu of gas, and 2.0 million Bbls of NGLs.

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets

and liabilities. The fair value of the commodity derivative contracts was a net asset of $38.7 million and $31.2 million at December 31, 2012, and

2011, respectively.

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Discontinuance of Cash Flow Hedge Accounting

Prior to January 1, 2011, the Company designated its commodity derivative contracts as cash flow hedges, for which unrealized changes in

fair value were recorded to AOCIL, to the extent the hedges were effective. As of January 1, 2011, the Company elected to de-designate all of its

commodity derivative contracts that had been previously designated as cash flow hedges at December 31, 2010. As a result, subsequent to

December 31, 2010, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather

than deferring any such amounts in AOCIL. The Company had no derivatives designated as cash flow hedges for the years ended December 31,

2012, and 2011, and as such, no ineffectiveness was recognized in earnings for the respective periods.

As a result of discontinuing hedge accounting on January 1, 2011, such fair values at December 31, 2010, were frozen in AOCIL as of the

de-designation date and are reclassified into earnings as the original derivative transactions settle. As of December 31, 2012, AOCIL included $1.1

million of net unrealized losses, net of income tax, on commodity derivative contracts that had been previously designated as cash flow hedges, all of

which will be reclassified to earnings from AOCIL during the next twelve months. Please refer to Note 11 – Fair Value Measurements for more

information regarding the Company’s derivative instruments.

The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category:

As of December 31, 2012

Derivative Assets Derivative Liabilities

Balance Sheet

 Classification Fair Value

Balance Sheet

 Classification Fair Value

(in thousands)

Commodity Contracts Current assets $ 37,873 Current liabilities $ 8,999

Commodity Contracts Noncurrent assets 16,466 Noncurrent liabilities 6,645

Derivatives not designated as hedging instruments $ 54,339 $ 15,644

As of December 31, 2011

Derivative Assets Derivative Liabilities

Balance Sheet

 Classification Fair Value

Balance Sheet

 Classification Fair Value

(in thousands)

Commodity Contracts Current assets $ 55,813 Current liabilities $ 42,806

Commodity Contracts Noncurrent assets 31,062 Noncurrent liabilities 12,875

Derivatives not designated as hedging instruments $ 86,875 $ 55,681

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The following table summarizes the components of unrealized and realized derivative (gain) loss presented in the accompanying statements of

operations:

For the Years Ended December 31,

2012 2011

(in thousands)

Cash settlement (gain) loss:

Oil contracts $ 11,893 $ 22,633

Gas contracts (47,270) (10,711)

NGL contracts (8,887) 13,749

Total cash settlement (gain) loss (44,264) 25,671

Unrealized (gain) loss on change in fair value:

Oil contracts (31,981) (3,391)

Gas contracts 31,777 (64,310)

NGL contracts (11,162) 4,944

Total net unrealized (gain) on change in fair value (11,366) (62,757)

Total unrealized and realized derivative (gain) $ (55,630) $ (37,086)

 

The following table details the effect of derivative instruments on AOCIL and the accompanying statements of operations (net of income

tax):

Location on

Accompanying

Statements of

Operations

For the Years Ended December 31,

Derivatives 2012 2011 2010

(in thousands)

Amount reclassified from AOCIL

Commodity

Contracts

Realized hedge gain

(loss) $ (2,264) $ 12,997 $ 6,641

 

The realized net hedge gain for the year ended December 31, 2012, and net hedge loss for December 31, 2011, are comprised of realized

cash settlements on commodity derivative contracts that were previously designated as cash flow hedges, whereas the realized net hedge gain for the

year ended December 31, 2010, is comprised of realized cash settlements on all commodity derivative contracts. Realized hedge gains or losses from

the settlement of commodity derivatives previously designated as cash flow hedges are reported in the total operating revenues and other income

section of the accompanying statements of operations. The Company realized a pre-tax net gain of $3.9 million, a net loss of $20.7 million, and a net

gain of $23.5 million from its commodity derivative contracts for the years ended December 31, 2012, 2011, and 2010, respectively.

As noted above, effective January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been

previously designated as cash flow hedges. No new gains or losses are deferred in AOCIL at December 31, 2012, and 2011, respectively.

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The Company had no derivatives designated as cash flow hedges at December 31, 2012, and 2011, respectively. The following table details

the ineffective portion of derivative instruments classified as cash flow hedges on the accompanying statements of operations for the year ended

December 31, 2010.

Loss Recognized in

Earnings 

(Ineffective Portion)

Location on Accompanying

 Statements of Operations

Derivatives Qualifying as Cash Flow

Hedges

For the Year Ended December 31,

2010

(in thousands)

Commodity Contracts Unrealized and realized derivative (gain) loss $ 8,899

Credit Related Contingent Features

As of December 31, 2012, and through the filing date of this report, all of the Company’s derivative counterparties were members of the

Company’s credit facility syndicate. The Company’s obligations under its credit facility and derivative contracts are secured by liens on substantially

all of the Company’s proved oil and gas properties.

Convertible Note Derivative Instrument

The contingent interest provision of the 3.50% Senior Convertible Notes was an embedded derivative instrument. The fair value of this

derivative was determined to be immaterial as of December 31, 2011. The 3.50% Senior Convertible Notes were settled during the second quarter of

2012. Please refer to Note 5 - Long-term Debt for additional discussion.

Note 11 – Fair Value Measurements

The Company follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fair value. That

authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an

orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by

assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is

based on the significance level of the following inputs:

• Level 1 – quoted prices in active markets for identical assets or liabilities

• Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that

are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

• Level 3 – significant inputs to the valuation model are unobservable

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The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the

fair value hierarchy as of December 31, 2012:

Level 1 Level 2 Level 3

(in thousands)

Assets:

Derivatives (1) $ — $ 54,339 $ —

Proved oil and gas properties (2) $ — $ — $ 209,959

Unproved oil and gas properties (2) $ — $ — $ 42,765

Liabilities:

Derivatives (1) $ — $ 15,644 $ —

Net Profits Plan (1) $ — $ — $ 78,827

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the

hierarchy as of December 31, 2011:

Level 1 Level 2 Level 3

(in thousands)

Assets:

Derivatives (1) $ — $ 86,875 $ —

Proved oil and gas properties (2) $ — $ — $ 139,992

Unproved oil and gas properties (2) $ — $ — $ 15,809

Liabilities:

Derivatives (1) $ — $ 55,681 $ —

Net Profits Plan (1) $ — $ — $ 107,731

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input

that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the

general classification of such instruments pursuant to the above fair value hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon

interpolated data. The Company derives internal valuation estimates taking into consideration the counterparties’ credit ratings, the Company’s credit

rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered

factors result in an estimated exit-price. Management believes this approach provides a reasonable and consistent methodology for valuing derivative

instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil,

gas, and NGL commodity derivative markets are highly active.

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Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an

adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company

monitors the credit ratings of its counterparties and may ask counterparties to post collateral if their ratings deteriorate. Currently, one counterparty

posts collateral when requested by the Company. In some instances the Company will attempt to novate the trade to a more stable counterparty.

Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any derivative liability position.

This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well

as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty

credit risk and takes into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last

measurement date. All of the Company’s derivative counterparties are members of the Company’s credit facility bank syndicate.

The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of

future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with accounting

authoritative guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or

assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments.

Net Profits Plan

The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. Certain

inputs for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income approach, which

converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations

of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a

direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher

commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability.

The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the

discounted value of estimated future payments associated with each individual pool. The calculation of this liability is a significant management

estimate. For those pools currently in payout, a discount rate of 12 percent is used to calculate this liability. A discount rate of 15 percent is used to

calculate the liability for pools that have not reached payout. 

The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and the overall market

conditions, all of which are continually evaluated to consider the current market environment. The Net Profits Plan liability is determined using price

assumptions of five one-year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price

differentials and to include the effects of the forecasted production covered by derivatives contracts in the relevant periods. The non-cash expense

associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the crude oil, gas, and

NGL commodity markets.

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If the commodity prices used in the calculation changed by five percent, the liability recorded at December 31, 2012, would differ by

approximately $7 million. A one percent increase in the discount rate would decrease the liability by approximately $3 million, whereas a one percent

decrease in the discount rate would increase the liability by approximately $4 million. Actual cash payments to be made to participants in future

periods are dependent on realized actual production, realized commodity prices, and actual costs associated with the properties in each individual pool

of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated.

No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. Consequently, the

recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation

of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash

flows, are derived from the Company’s own calculations and estimates.

 

The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Beginning balance $ 107,731 $ 135,850 $ 170,291

Net increase (decrease) in liability (1) (9,251) 2,269 14,063

Net settlements (1) (2) (3) (19,653) (30,388) (48,504)

Transfers in (out) of Level 3 — — —

Ending balance $ 78,827 $ 107,731 $ 135,850

(1) Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations.

(2) Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued under

the Net Profits Plan of $2.3 million, $6.3 million, and $26.1 million relating to divestiture proceeds for the years ended December 31, 2012, 2011, and

2010 respectively.

(3) During 2011, the Company elected to cash out several Net Profits Plan pools with a $2.6 million direct payment. As a result, the Company reduced its

Net Profits Plan liability by that amount. There was no impact on the accompanying statements of operations for the period ended December 31, 2011,

related to these settlements.

Long-term Debt

The following table reflects the fair value of the 3.50% Senior Convertible Notes, 2019 Notes, 2021 Notes, and 2023 Notes measured at fair

value using Level 1 inputs based on quoted secondary market trading prices:

As of December 31,

2012 2011

(in thousands)

3.50% Senior Convertible Notes (1) (2) $ — $ 394,068

2019 Notes $ 371,875 $ 359,408

2021 Notes $ 371,070 $ 360,283

2023 Notes (3) $ 424,200 $ —

(1) The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-term Debt for additional discussion.

(2) The estimated fair value of the embedded contingent interest derivative was immaterial as of December 31, 2011.

(3) The 2023 Notes were issued on June 29, 2012.

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There was no long-term debt measured at fair value on the accompanying balance sheets as of December 31, 2012, or 2011; all long-term

debt is presented at historical value.

Proved Oil and Gas Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs

may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future estimated cash flows to a single

present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the

Company’s management. The calculation of the discount rate is based on the best information available and was estimated to be 12 percent as of

December 31, 2012, and 2011. Management believes that the discount rate is representative of current market conditions and takes into account

estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and

nonperformance risk. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five

years. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after

which a flat terminal price is used for each commodity stream. Future operating costs are also adjusted as deemed appropriate for these estimates.

As a result of asset write-downs, the proved oil and gas properties measured at fair value within the accompanying balance sheets totaled

$210.0 million and $140.0 million as of December 31, 2012 and 2011, respectively.

Unproved Oil and Gas Properties

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs

may not be recoverable. The Company uses a market approach, which takes into account the following significant assumptions: future development

plans, risk weighted potential resource recovery, and estimated reserve values to measure the fair value of unproved properties. 

As a result of the asset write-downs, unproved oil and gas properties measured at fair value within the accompanying balance sheets totaled

$42.8 million as of December 31, 2012, and $15.8 million at December 31, 2011.

Materials Inventory

Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to measure the fair value of materials

inventory, which is primarily comprised of tubular goods. The Company uses third party market quotes and compares the quotes to the book value of

the materials inventory. If the book value exceeds the quoted market price, the Company reduces the book value to the market price. The considered

factors result in an estimated exit-price. Management believes this approach provides a reasonable and consistent methodology for valuing materials

inventory. There were no materials inventory measured at fair value within the accompanying balance sheets at December 31, 2012, and 2011.

Asset Retirement Obligations

The income valuation technique is utilized by the Company to determine the fair value of the asset retirement obligation liability at the point of

inception by applying a credit-adjusted risk-free rate, the time value of money, and the current economic state to the undiscounted expected

abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to

use Level 3 inputs. There were no asset retirement obligations measured at fair value within the accompanying balance sheets at December 31, 2012

and 2011.

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Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement

Acquisition and Development Agreement

In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui (the “Acquisition and Development

Agreement”). Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in

certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As

consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to

the Company’s remaining interest in these assets until Mitsui has expended an aggregate $680.0 million on behalf of the Company. Based on the

Company’s forecast of the operator’s drilling plans, it will take approximately two more years to fully utilize the carry. The Acquisition and

Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the Company that were

attributable to the transferred interest during the period between the effective date and the closing date, which the parties agreed would be applied over

the carry period to cover the Company’s remaining 10 percent of drilling and completion costs for the affected acreage.

As of December 31, 2012, the Company held $86.8 million in cash that is contractually restricted for use in the development of assets

covered by our Acquisition and Development Agreement with Mitsui. This cash relates to the reimbursement of net costs for the period between the

effective date and closing date, as discussed above, as well as an estimate of 90 percent of two months of activity of the Company’s proportionate

share of estimated drilling and completion costs. This restricted cash is classified as a non-current asset in the accompanying balance sheets. The

Company has recorded a corresponding liability equal to the restricted cash balance. The portion of the liability related to development operations

expected to occur within the next year is recorded in accounts payable and accrued expenses within the accompanying balance sheets. The portion of

the liability related to development operations expected to occur more than one year in the future is recorded in other noncurrent liabilities within the

accompanying balance sheets. There was no net impact on the accompanying statements of cash flows as restricted cash was offset against the

corresponding liability in investing activities. There is no direct impact to the accompanying statements of operations as a result of the Acquisition and

Development Agreement, with the exception of legal and commission costs associated with the execution of the arrangement which were expensed in

2011. Of the original $680.0 million carry amount, $277.5 million had been spent as of December 31, 2012.

Carry and Earning Agreement

On April 29, 2010, the Company entered into a Carry and Earning Agreement that provided for a third party to earn 95 percent of SM

Energy’s interest in approximately 8,400 net acres in a portion of the Company’s east Texas Haynesville shale acreage, as well as an interest in several

wells, and five percent of SM Energy’s interest in approximately 23,400 net acres in a separate portion of the Company’s Haynesville acreage in East

Texas. In exchange for these interests, the third party invested $91.3 million to fund the drilling and completion costs of wells in the portion of the

leases where the Company retained 95 percent of its interest. The parties now share all costs of operations within the area of joint ownership in

accordance with their respective ownership interests.

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Note 13 - Suspended Well Costs

The following table reflects the net changes in capitalized exploratory well costs during 2012, 2011, and 2010. The table does not include

amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Beginning balance on January 1, $ 18,600 $ 35,862 $ 34,384

Additions to capitalized exploratory well costs pending the determination of

proved reserves 9,100 15,618 35,862

Reclassifications to wells, facilities, and equipment based on the

determination of proved reserves (5,865) (32,880) (34,384)

Capitalized exploratory well costs charged to expense (12,735) — —

Ending balance at December 31, $ 9,100 $ 18,600 $ 35,862

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of

projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:

As of December 31,

2012 2011 2010

(in thousands)

Exploratory well costs capitalized for one year or less $ 9,100 $ 15,618 $ 35,862

Exploratory well costs capitalized for more than one year — 2,982 —

Ending balance at December 31, $ 9,100 $ 18,600 $ 35,862

Number of projects with exploratory well costs that have been capitalized

more than a year — 2 —

In the third quarter of 2012, the Company expensed $3.6 million of costs related to two exploratory wells that had been disclosed at

December 31, 2011, as suspended well costs being capitalized for more than one year.

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Supplemental Oil and Gas Information (unaudited)

Costs Incurred in Oil and Gas Producing Activities

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized

as follows:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Development costs (1) $ 1,346,216 $ 1,320,627 $ 379,636

Exploration costs 220,921 177,465 443,888

Acquisitions

Proved properties 5,773 — 664

Unproved properties (2) 114,971 55,237 53,192

Total, including asset retirement obligation (3)(4) $ 1,687,881 $ 1,553,329 $ 877,380

(1) Includes facility costs of $62.2 million, $112.4 million, and $80.3 million for the years ended December 31, 2012, 2011, and 2010, respectively.

(2) Includes $3.4 million of unproved properties acquired for the year ended December 31, 2012. The remaining balance relates to leasing activity.

(3) Includes capitalized interest of $12.1 million, $10.8 million, and $4.3 million for the years ended December 31, 2012, 2011, and 2010, respectively.

(4) Includes amounts relating to estimated asset retirement obligations of $30.6 million, $19.3 million, and $5.8 million for the years ended December 31,

2012, 2011, and 2010, respectively.

Oil and Gas Reserve Quantities

The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing

activities and SEC rules for oil and gas reporting reserve estimation and disclosure.

Proved reserves are the estimated quantities of oil, gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated

with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions,

operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that

renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions

include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the

12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-themonth price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future

conditions. All of the Company’s estimated proved reserves are located in the United States.

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The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period

ended December 31, 2012. The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the PV-10 value of its

estimated proved reserves in each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new

discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates

are expected to change as future information becomes available.

For the Years Ended December 31,

2012 (1) 2011 (2) 2010 (3)

Oil Gas NGLs Oil Gas NGLs Oil Gas NGLs

(MMBbl) (Bcf) (MMBbl) (MMBbl) (Bcf) (MMBbl) (MMBbl) (Bcf) (MMBbl)

Total proved reserves

Beginning of year 71.7 664.0 27.5 57.4 640.0 — 53.8 449.5 —

Revisions of previous

estimate (4.5) (123.3) (2.4) (0.9) (76.7) 15.6 3.1 6.1 —

Discoveries and

extensions 17.1 297.4 30.6 26.9 223.5 17.8 16.2 172.9 —

Infill reserves in an

existing proved field 19.2 125.1 12.7 2.8 14.8 0.5 2.8 97.2 —

Sales of

reserves (4) (1.0) (11.0) — (6.4) (37.3) (2.9) (12.1) (14.0) —

Purchases of minerals

in place 0.1 1.2 — — — — — 0.2 —

Production (10.4) (120.0) (6.1) (8.1) (100.3) (3.5) (6.4) (71.9) —

End of year (5) 92.2 833.4 62.3 71.7 664.0 27.5 57.4 640.0 —

Proved developed

reserves

Beginning of year 50.3 451.2 15.2 46.0 411.0 — 48.1 342.0 —

End of year 58.8 483.2 27.2 50.3 451.2 15.2 46.0 411.0 —

Proved undeveloped

reserves

Beginning of year 21.4 212.8 12.3 11.4 229.0 — 5.7 107.5 —

End of year 33.5 350.2 35.1 21.4 212.8 12.3 11.4 229.0 —

(1) Please refer to Part I, Items 1 and 2 and Part II, Item 7 for current year reserve discussion.

(2) For the year ended December 31, 2011, of the 11.5 BCFE upward revision of a previous estimate, (25.3) BCFE and 36.8 BCFE relate to price and

performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2011, were $96.19 per Bbl

and $4.12 per MMBtu, for oil and natural gas respectively. These prices were 21 percent higher and six percent lower, respectively, than the prices

used in 2010. The per Bbl price used to estimate proved NGL reserves as of December 31, 2011 was $59.37. There is no 2010 comparative price as

2010 NGL production volumes, revenues, and prices have not been reclassified to conform with current presentation given the immateriality of NGL

volumes in that period. Performance revisions in 2011 resulted in a net 36.8 BCFE increase in our estimate of proved reserves. This increase

includes the impact of the Company's conversion to three stream production, which is partially offset by downward engineering revisions due

primarily to the failure of Woodford shale wells in the Company's Mid-Continent region to satisfy internal economic hurdles. The Company added

526.1 BCFE from its drilling program, the majority of which related to activity in the Eagle Ford shale in South Texas. These additions are included

in discoveries and extensions and infill reserves.

(3) For the year ended December 31, 2010, of the 24.7 BCFE upward revision of a previous estimate, 42.6 BCFE and (17.9) BCFE relate to price and

performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2010, were $79.43 per Bbl

and $4.38 per MMBtu for oil and natural gas, respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used in

2009.

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Performance revisions in 2010 resulted in a net 11.2 BCFE decrease in the Company's estimate of proved reserves. While the Company recognized

upward performance revisions in every region on proved developed properties, it had approximately 19.3 BCFE of downward performance revisions

related to estimated proved undeveloped reserves in primarily dry gas assets, resulting from lower gas prices and higher well costs which negatively

impacted the economics of these assets. The Company added 384.2 BCFE from its drilling program, the majority of which related to activity in the

Eagle Ford shale in south Texas. These additions are included in discoveries and extensions and infill reserves.

(4) The Company divested of certain non-core assets during 2012, 2011, and 2010. Please refer to Note 3 - Divestitures and Assets Held for Sale for

additional information.

(5) For the years ended December 31, 2012, 2011, and 2010, amounts included approximately 299, 175, and 356 MMcf respectively, representing the

Company’s net underproduced gas balancing position.

 

Note: Prior to 2011, the Company reported its natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of

2011, the Company changed its reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing

consistent with title transfer for each product. Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices.

Standardized Measure of Discounted Future Net Cash Flows

The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in

accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and

costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. Each property the Company

operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current

statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present

value amounts by applying a 10 percent annual discount factor.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in

place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by

the central administrative office attributable to operating activities.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not

necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in

the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve

quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used

in the calculation of the standardized measure:

For the Years Ended December 31,

2012 2011 2010

Gas (per Mcf) $ 3.08 $ 4.72 $ 5.54

Oil (per Bbl) $ 86.80 $ 88.00 $ 70.60

NGLs (per Bbl) $ 41.00 $ 51.95 $ —

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The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based on the

standardized measure.

As of December 31,

2012 2011 2010

(in thousands)

Future cash inflows $ 13,129,243 $ 10,871,281 $ 7,598,159

Future production costs (5,013,720) (3,786,887) (2,512,091)

Future development costs (1,742,978) (1,036,352) (789,493)

Future income taxes (1,609,397) (1,740,394) (1,335,576)

Future net cash flows 4,763,148 4,307,648 2,960,999

10 percent annual discount (1,742,134) (1,727,608) (1,294,632)

Standardized measure of discounted future net cash

flows $ 3,021,014 $ 2,580,040 $ 1,666,367

The principle sources of change in the standardized measure of discounted future net cash flows are:

For the Years Ended December 31,

2012 2011 2010

(in thousands)

Standardized measure, beginning of year $ 2,580,040 $ 1,666,367 $ 1,015,967

Sales of oil, gas, and NGLs produced, net of production costs (1,081,997) (1,042,281) (641,213)

Net changes in prices and production costs (550,293) 454,646 557,681

Extensions, discoveries and other including infill reserves in an

existing proved field, net of production costs 1,872,810 1,816,640 989,365

Sales of reserves in place (41,020) (369,820) (151,315)

Purchase of reserves in place 3,785 — 804

Development costs incurred during the year 163,937 49,246 43,900

Changes in estimated future development costs 47,980 (31,410) 49,531

Revisions of previous quantity estimates (452,454) 32,992 66,759

Accretion of discount 346,118 234,433 128,408

Net change in income taxes 53,005 (203,169) (409,848)

Changes in timing and other 79,103 (27,604) 16,328

Standardized measure, end of year $ 3,021,014 $ 2,580,040 $ 1,666,367

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Quarterly Financial Information (unaudited)

The Company’s quarterly financial information for fiscal years 2012 and 2011 is as follows (in thousands, except per share amounts):

First Second Third Fourth (1)

Quarter Quarter Quarter Quarter

Year Ended December 31, 2012

Total operating revenues $ 377,423 $ 304,420 $ 378,951 $ 444,308

Total operating expenses 321,198 252,029 421,787 530,105

Income (loss) from operations $ 56,225 $ 52,391 $ (42,836) $ (85,797)

Income (loss) before income taxes $ 42,017 $ 39,684 $ (61,072) $ (104,146)

Net income (loss) $ 26,336 $ 24,889 $ (38,336) $ (67,138)

Basic net income (loss) per common share $ 0.41 $ 0.39 $ (0.58) $ (1.02)

Diluted net income (loss) per common share $ 0.39 $ 0.37 $ (0.58) $ (1.02)

Dividends declared per common share $ 0.05 $ — $ 0.05 $ —

Year Ended December 31, 2011

Total operating revenues $ 315,329 $ 377,873 $ 530,574 $ 379,542

Total operating expenses 335,301 166,166 157,786 559,681

Income (loss) from operations $ (19,972) $ 211,707 $ 372,788 $ (180,139)

Income (loss) before income taxes $ (29,558) $ 197,384 $ 363,443 $ (192,268)

Net income (loss) $ (18,503) $ 124,533 $ 230,097 $ (120,711)

Basic net income (loss) per common share $ (0.29) $ 1.96 $ 3.60 $ (1.89)

Diluted net income (loss) per common share $ (0.29) $ 1.86 $ 3.41 $ (1.89)

Dividends declared per common share $ 0.05 $ — $ 0.05 $ —

(1) The fourth quarter of 2012 and 2011 included $170.4 million and $170.5 million, respectively, of impairment of proved properties expense. Please refer

to the caption Impairment of Proved and Unproved Properties included in Note 1 - Summary of Significant Accounting Policies for additional

discussion.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL

DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed

in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to

reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief

Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and

procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A

control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control

system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be

considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance

that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that

judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be

circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of

any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any

design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control

system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as

necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered

by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive

Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these

Disclosure Controls

are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our

internal control over financial reporting.

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Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in

Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting

is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external

purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies

and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets

of the Company;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with

generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with

authorizations of management and directors of the Company; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s

assets that have a material effect on the financial statements.

Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems

determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of

any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or

that the degree of compliance with the policies and procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. In making this

assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal

Control-Integrated Framework.

Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial

reporting as of December 31, 2012.

The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal controls over

financial reporting. That report immediately follows this report.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

SM Energy Company and Subsidiaries

Denver, Colorado

We have audited the internal control over financial reporting of SM Energy Company and subsidiaries (the “Company”) as of December 31, 2012,

based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway

Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of

the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial

Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards

require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was

maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a

material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing

such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and

principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other

personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external

purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies

and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions

of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial

statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in

accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely

detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override

of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the

effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of

changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based

on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway

Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated

financial statements as of and for the year ended December 31, 2012, of the Company and our report dated February 21, 2013, expressed an

unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

February 21, 2013

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ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The information required by this Item concerning SM Energy’s Directors and corporate governance is incorporated by reference to the

information provided under the captions Structure of the Board of Directors, Proposal 1 - Election of Directors, and Corporate Governance in SM

Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012.

The information required by this Item concerning compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated

by reference to the information provided under the caption Section 16(a) Beneficial Ownership Reporting Compliance in SM Energy’s definitive

proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the names, ages and positions of SM Energy’s executive officers. The age of the executive officers is as of

February 14, 2013.

Name Age Position

Anthony J. Best 63 Chief Executive Officer

Javan D. Ottoson 54 President and Chief Operating Officer

A. Wade Pursell 47 Executive Vice President and Chief Financial Officer

David W. Copeland 56 Senior Vice President, General Counsel and Corporate Secretary

Gregory T. Leyendecker 55 Senior Vice President and Regional Manager

Mark D. Mueller 48 Senior Vice President and Regional Manager

Lehman E. Newton, III 57 Senior Vice President and Regional Manager

Herbert S. Vogel 52 Senior Vice President - Portfolio Development and Technical Services

Kenneth J. Knott 48 Vice President - Land

Mary Ellen Lutey 41 Vice President and Regional Manager

Mark T. Solomon 44 Vice President - Controller and Assistant Secretary

David J. Whitcomb 50 Vice President - Marketing

Dennis A. Zubieta 46 Vice President - Engineering, Evaluation and A&D

Anthony J. Best. Mr. Best joined the Company in June 2006 as President and Chief Operating Officer. In December 2006, Mr. Best

relinquished his position as Chief Operating Officer when the Board appointed Javan D. Ottoson to that office. Mr. Best was elected Chief Executive

Officer and a director of the Company in February 2007. Mr. Best relinquished his position as President when the Board appointed Mr. Ottoson to that

office in October 2012. From November 2005 to June 2006, Mr. Best was developing a business plan and securing capital commitments for a new

exploration and production entity. From 2003 to October 2005, Mr. Best was President and Chief Executive Officer of Pure Resources, Inc., an

independent oil and natural gas exploration and production company that was a subsidiary of Unocal, where he managed all of Unocal’s onshore

United States assets. From 2000 to 2002, Mr. Best had an oil and gas consulting practice, working with various energy firms. From 1979 to 2000,

Mr. Best was with ARCO in a variety of positions, including serving as President-ARCO Latin America, President-ARCO Permian, Field Manager

for Prudhoe Bay and VP-External Affairs for ARCO Alaska. Mr. Best has over 34 years of experience in the energy industry.

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Javan D. Ottoson. Mr. Ottoson joined the Company in December 2006 as Executive Vice President and Chief Operating Officer. Mr.

Ottoson was appointed as President of the Company in October 2012. Mr. Ottoson has been in the energy industry for over 31 years. From April 2006

until he joined the Company in December 2006, Mr. Ottoson was Senior Vice President-Drilling and Engineering at Energy Partners, Ltd., an

independent oil and natural gas exploration and production company, where his responsibilities included overseeing all aspects of its drilling and

engineering functions. Mr. Ottoson managed Permian Basin assets for Pure Resources, Inc., a Unocal subsidiary, and its successor owner, Chevron,

from July 2003 to April 2006. From April 2000 to July 2003, Mr. Ottoson owned and operated a homebuilding company in Colorado and ran his family

farm. Prior to 2000, Mr. Ottoson worked for ARCO in management and operational roles, including serving as President of ARCO China,

Commercial Director of ARCO United Kingdom, and Vice President of Operations and Development, ARCO Permian.

A. Wade Pursell. Mr. Pursell joined the Company in September 2008 as Executive Vice President and Chief Financial Officer. Mr. Pursell

was Executive Vice President and Chief Financial Officer for Helix Energy Solutions Group, Inc., a global provider of life-of-field services and

development solutions to offshore energy producers and an oil and gas producer, from February 2007 to September 2008. From October 2000 to

February 2007, he was Senior Vice President and Chief Financial Officer of Helix. He joined Helix in May 1997, as Vice President-Finance and

Chief Accounting Officer. From 1988 through May 1997, Mr. Pursell was with Arthur Andersen LLP, serving lastly as an Experienced Manager

specializing in the offshore services industry. Mr. Pursell has over 25 years of experience in the energy industry.

David W. Copeland. Mr. Copeland joined the Company in January 2011 as Senior Vice President and General Counsel. He was appointed

as the Company’s Corporate Secretary in July 2011. Mr. Copeland has over 31 years of experience in the legal profession, including over 21 years as

internal counsel for various energy companies. Prior to joining the Company, he co-founded Concho Resources Inc., in Midland, Texas, where he

served as its Vice President, General Counsel and Secretary from April 2004 through November 2009, and then as its Senior Counsel through

December 2010. From August 1997 through March 2004, Mr. Copeland served as an executive officer and general counsel of two energy companies

he co-founded in Midland, Texas with others. Mr. Copeland started his career in 1982 with the Stubbeman, McRae, Sealy, Laughlin & Browder law

firm in Midland, Texas.

Gregory T. Leyendecker.Mr. Leyendecker was appointed Senior Vice President and Regional Manager in May 2010. From July 2007 to

May 2010, he served as Vice President and Regional Manager. Mr. Leyendecker joined the Company in December 2006 as Operations Manager for

the South Texas & Gulf Coast region in Houston, Texas. Mr. Leyendecker has over 32 years of experience in the energy industry, and held various

positions with Unocal Corporation, an independent oil and natural gas exploration and production company, from 1980 until its acquisition in 2005.

During his career with Unocal, he was the Asset Manager for Unocal Gulf Region USA from 2003 to June 2004 and Production and Reservoir

Engineering Technology Manager for Unocal from June 2004 to August 2005. He was appointed Drilling and Workover Manager for the San Joaquin

Valley business unit of Chevron, as successor-by-merger of Unocal Corporation, in Bakersfield, California in August 2005, and held this position

until January 2006. Immediately prior to joining the Company, Mr. Leyendecker was Vice President of Drilling Management Services from February

2006 to November 2006 for Enventure Global Technology, a provider of solid expandable tubular technology.

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Mark D. Mueller. Mr. Mueller joined the Company in September 2007 as Senior Vice President. Mr. Mueller was appointed as the Regional

Manager of the Rocky Mountain region effective January 1, 2008. Mr. Mueller has been in the energy industry for over 26 years. From September

2006 to September 2007, he was Vice President and General Manager at Samson Exploration Ltd., an oil and gas exploration and production

company that was a subsidiary of Samson Investment Company, in Calgary, Canada, where his responsibilities included fiscal performance, reserves,

and all operational functions of the company. From April 2005 until its sale in August 2006, Mr. Mueller was Vice President and General Manager for

Samson Canada Ltd., an oil and gas exploration and production company that was a subsidiary of Samson Investment Company, where he was

responsible for all business units and the eventual sale of the company. Mr. Mueller joined Samson Canada Ltd. as Project Manager in May 2003 to

build a new basin-centered gas business unit and was Vice President from December 2003 to August 2006. Prior to joining Samson, Mr. Mueller was

West Central Alberta Engineering Manager for Northrock Resources Ltd., a Canadian oil and gas company that was a wholly-owned subsidiary of

Unocal Corporation, in Calgary, Canada. From 1986 to 2003, Mr. Mueller held positions of increasing responsibility in engineering and management

for Unocal throughout North America and Southeast Asia.

Lehman E. Newton, III. Mr. Newton joined the Company in December 2006 as General Manager for the Midland, Texas office, was

appointed Vice President and Regional Manager of the Permian region in June 2007, and was appointed Senior Vice President and Regional Manager

in May 2010. Mr. Newton has over 34 years of experience in the energy industry. From November 2005 to November 2006, Mr. Newton served as

Project Manager for one of Chevron’s largest Lower 48 projects. Mr. Newton joined Pure Resources in February 2003 as the Business Development

Manager and worked in that capacity until October 2005. Mr. Newton was a founding partner in Westwin Energy, an independent Permian Basin

exploration and production company, from June 2000 to January 2003. Prior to that, Mr. Newton spent 21 years with ARCO in various engineering,

operations and management roles, including as Asset Manager, ARCO’s East Texas operations, Vice President, Business Development, ARCO

Permian, and Vice President of Operations and Development, ARCO Permian.

Herbert S. Vogel. Mr. Vogel joined the Company in March 2012 as Senior Vice President-Portfolio Development and Technical Services,

and is responsible for Corporate Exploration, Engineering, Land, Marketing and EHS activities. Mr. Vogel has over 28 years of experience in the oil

and gas business. He joined the Company after his retirement from BP, where he most recently served as the President of BP Energy Co. and Regional

Business Unit Leader of North American Gas & Power. His previous roles included COO-NGL, Power & Financial Products in Houston, Managing

Director Gas Europe & Africa in London, and Sr. VP of the Tangguh LNG Project in Indonesia. Mr. Vogel started his career as a reservoir engineer

with ARCO Alaska, Inc., and progressed through a series of positions of increasing responsibility in engineering, operations management, new

ventures development, and business unit management at ARCO and BP.

Kenneth J. Knott. Mr. Knott was appointed Vice President - Land in October 2012, and is responsible for all of the Company's regional

and administrative land functions. Mr. Knott was appointed Vice President of Business Development & Land and Assistant Secretary in August 2008.

Mr. Knott joined SM Energy in November 2000 as Senior Landman for the Gulf Coast region in Lafayette, Louisiana, and later assumed the position

of Gulf Coast Regional Land Manager when the office was moved to Houston in March 2004.

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Mary Ellen Lutey. Ms. Lutey was appointed Vice President and Regional Manager of the Mid-Continent region in December 2012. She

joined SM Energy in June 2008 as North Rockies Asset Manager, where she managed the Company's activities in the Williston Basin. Prior to joining

SM Energy, Ms. Lutey held various technical and managerial positions in several regions of the United States and Canada. She was a Senior

Reservoir Engineer with Chesapeake Energy Corporation from September 2007 until June 2008, where she was responsible for the resource

development of the Fayetteville Shale in Arkansas. Ms. Lutey was a Team Lead for Engineering and Geoscience, with ConocoPhillips Canada from

April 2006 until September 2007, where she was responsible for the technical and business performance of two multi-discipline groups in Western

Canada. From July 2005 until April 2006, she was a Team Lead for Engineering and Geoscience, with Burlington Resources Canada where she

managed the growth and development of resource plays in Western Canada. From 1994 until 2005, Ms. Lutey held various engineering and leadership

positions of increasing responsibility for Burlington Resources. Ms. Lutey has over 21 years of experience in the energy industry.

Mark T. Solomon. Mr. Solomon was appointed Vice President-Controller and Assistant Secretary of the Company in May 2011. He was

appointed Controller of the Company in January 2007. Mr. Solomon served as the Company’s Acting Principal Financial Officer from April 2008, to

September 2008, which was during the period of time that the Company’s Chief Financial Officer position was vacant. Mr. Solomon joined the

Company in 1996. He served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice President-Financial Reporting

from September 2002 to May 2006 and Assistant Vice President-Assistant Controller from May 2006 to January 2007. Prior to joining the Company,

Mr. Solomon was an auditor with Ernst & Young. Mr. Solomon has over 16 years of experience in the energy industry.

David J. Whitcomb. Mr. Whitcomb was appointed Vice President - Marketing in August 2008. Mr. Whitcomb joined SM Energy in

November 1994 as Gas Contract Analyst and was named Assistant Vice President of Gas Marketing in October 1995. In March 2007, his

responsibilities were expanded to include oil marketing, at which time his title was changed to Assistant Vice President and Director of Marketing.

Dennis A. Zubieta. Mr. Zubieta was appointed Vice President-Engineering, Evaluation and A&D in October 2012. He was appointed Vice

President-Engineering and Evaluation of the Company in August 2008. Mr. Zubieta joined the Company in June 2000 as Corporate A&D Engineer,

assumed the role of Reservoir Engineer in February 2003, and was appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was

employed by Burlington Resources from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta has over

25 years of experience in the energy industry.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the information provided under the captions, Executive Compensation

and Director Compensation in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from

December 31, 2012.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED

STOCKHOLDER MATTERS

The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by

reference to the information provided under the caption Security Ownership of Certain Beneficial Owners and Management in SM Energy’s

definitive proxy statement for the 2013 annual meeting of stockholders to be filed within 120 days from December 31, 2012.

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Securities Authorized for Issuance Under Equity Compensation Plans. SM Energy has the Equity Plan under which options and

shares of SM Energy common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the

Board of Directors. Our stockholders have approved this plan. See Note 7 – Compensation Plans included in Part II, Item 8 of this report for

further information about the material terms of our equity compensation plans. The following table is a summary of the shares of common stock

authorized for issuance under the equity compensation plans as of December 31, 2012:

(a) (b) (c)

Plan category

Number of

securities to be

issued upon exercise

of outstanding

options, warrants,

and rights

Weighted-average

exercise price of

outstanding options,

warrants, and rights

Number of securities

remaining available for

future issuance under

equity compensation plans

(excluding securities

reflected in column (a))

Equity compensation plans approved by security holders:

Equity Incentive Compensation Plan

Stock options and incentive stock options (1) 267,846 $ 14.95

Restricted stock (1)(3) 496,244 N/A

Performance share units (1)(3)(4) 899,604 N/A

Total for Equity Incentive Compensation Plan 1,663,694 $ 14.95 1,366,465

Employee Stock Purchase Plan (2) - - 1,307,484

Equity compensation plans not approved by security holders - - -

Total for all plans 1,663,694 $ 14.95 2,673,949

 

(1) In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options,

incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and

members of the Board of Directors of SM Energy or any affiliate of SM Energy. The Equity Plan serves as the successor to the St. Mary Land &

Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the SM Energy Company Restricted

Stock Plan, and the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All

grants of equity are now made under the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a

Predecessor Plan immediately prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments

evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan in 2009 and 2010 and each amended plan was

approved by stockholders at the respective annual stockholders’ meetings. The awards granted in 2012, 2011, and 2010 under the Equity Plan were

724,671, 386,802, and 540,774, respectively.

(2) Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of

their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the

six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended

to qualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 66,485, 41,358, and 52,948 in 2012, 2011, and 2010,

respectively.

(3) RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share fair value, which is presented in order to

provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per share fair value for the outstanding

RSUs and PSUs was $51.81 and $63.08, respectively. Please refer to Note 7 - Compensation Plan for additional discussion.

(4) The number of awards vested assumes a one multiplier. The final number of shares issued upon settlement may vary depending on the three-year

multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item is incorporated by reference to the information provided under the caption Certain Relationships and

Related Transactions, and Corporate Governance, in SM Energy’s definitive proxy statement for the 2013 annual meeting of stockholders to be filed

within 120 days from December 31, 2012.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference to the information provided under the caption Independent Registered

Public Accounting Firm and Audit Committee Preapproval Policy and Procedures in SM Energy’s definitive proxy statement for the 2013 annual

meeting of stockholders to be filed within 120 days from December 31, 2012.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:

Report of Independent Registered Public Accounting Firm 89

Consolidated Balance Sheets 90

Consolidated Statements of Operations 91

Consolidated Statements of Comprehensive Income (Loss) 92

Consolidated Statements of Stockholders’ Equity 93

Consolidated Statements of Cash Flows 94

Notes to Consolidated Financial Statements 96

All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of

the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.

(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:

Exhibit

Number Description

2.1 Purchase and Sale Agreement dated December 17, 2009 and effective as of November 1, 2009, between Legacy Reserves

Operating LP and St. Mary Land & Exploration Company (filed as Exhibit 2.5 to the registrant’s Annual Report on Form 10-K

for the year ended December 31, 2009 and incorporated herein by reference)

2.2 Purchase and Sale Agreement dated January 7, 2010 and effective as of November 1, 2009, between Sequel Energy Partners

LP, Bakken Energy Partners, LLC, Three Forks Energy Partners, LLC and St. Mary Land & Exploration Company (filed as

Exhibit 2.6 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by

reference)

2.3 Purchase and Sale Agreement dated June 9, 2011, among SM Energy Company, Statoil Texas Onshore Properties LLC, and

Talisman Energy USA Inc. (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June

30, 2011 and incorporated herein by reference)

2.4 Acquisition and Development Agreement dated June 29, 2011 between SM Energy Company and Mitsui E&P Texas LP (filed

as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 and incorporated herein by

reference)

2.5 First Amendment to Acquisition and Development Agreement dated October 13, 2011 between SM Energy Company and

Mitsui E&P Texas (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30,

2011 and incorporated herein by reference)

3.1 Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the

registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)

3.2 Amended and Restated By-Laws of SM Energy Company amended effective as of January 1, 2013 (filed as Exhibit 3.1 to the

registrant’s Current Report on Form 8-K filed on January 7, 2013, and incorporated herein by reference)

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4.1 Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007, between St. Mary Land &

Exploration Company and Wells Fargo Bank, National Association, as trustee (including the form of 3.50% Senior Convertible

Note due 2027) (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on April 4, 2007 and incorporated

herein by reference)

4.2 Indenture related to the 6.625% Senior Notes due 2019, dated as of February 7, 2011, by and between SM Energy Company,

as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K

filed on February 10, 2011, and incorporated herein by reference)

4.3 Indenture related to the 6.50% Senior Notes due 2021, dated as of November 8, 2011, by and among SM Energy Company, as

issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K

filed on November 10, 2011, and incorporated herein by reference)

4.4 Indenture related to the 6.50% Senior Notes due 2023, dated June 29, 2012, between SM Energy Company, as Issuer, and U.S.

Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on July 3,

2012, and incorporated herein by reference)

4.5 Registration Rights Agreement, dated June 29, 2012, among SM Energy Company and Wells Fargo Securities LLC, Merrill

Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of several purchasers (filed as

Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on July 3, 2012, and incorporated herein by reference)

10.1† Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement on Form S-8

(Registration No. 333-106438) and incorporated herein by reference)

10.2† Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the registrant’s Registration Statement on

Form S-8 (Registration No. 333-106438) and incorporated herein by reference)

10.3† Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Quarterly Report on Form

10-Q for the quarter ended September 30, 2001 and incorporated herein by reference)

10.4† Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.9 to the registrant’s

Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference)

10.5† Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K

filed on May 4, 2006 and incorporated herein by reference)

10.6 Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture

Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated

effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and

incorporated herein by reference)

10.7 Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as

Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference)

10.8† Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as Exhibit 10.1 to the registrant’s

Current Report on Form 8-K filed on May 27, 2009, and incorporated herein by reference)

10.9† Equity Incentive Compensation Plan As Amended and Restated as of April 1, 2010 (filed as Exhibit 10.1 to the registrant’s

Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference)

10.10s SM Energy Company Equity Incentive Compensation Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.7 to the

registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)

10.11† Third Amendment to Employee Stock Purchase Plan dated September 23, 2009 (filed as Exhibit 10.3 to the registrant’s

Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, and incorporated herein by reference)

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10.12† Fourth Amendment to Employee Stock Purchase Plan dated December 29, 2009 (filed as Exhibit 10.46 to the registrant’s

Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference)

10.13s Employee Stock Purchase Plan, As Amended and Restated as of July 30, 2010 (filed as Exhibit 10.4 to the registrant’s Quarterly

Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)

10.14 Carry and Earning Agreement between St. Mary Land & Exploration Company and Encana Oil & Gas (USA) Inc. executed as

of April 29, 2010 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010

and incorporated herein by reference)

10.15† Form of Performance Share and Restricted Stock Unit Award Agreement as of July 1, 2010 (filed as Exhibit 10.3 to the

registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)

10.16† Form of Performance Share and Restricted Stock Unit Award Notice as of July 1, 2010 (filed as Exhibit 10.4 to the registrant’s

Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)

10.17† Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the

registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference)

10.18*** Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed as

Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated

herein by reference)

10.19s Cash Bonus Plan, As Amended on July 30, 2010 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q for

the quarter ended September 30, 2010 and incorporated herein by reference)

10.20s Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the

registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)

10.21s SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan, As Amended as of July 30, 2010 (filed as

Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated

herein by reference)

10.22†

Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s

Current Report on Form 8-K filed on December 29, 2010, and incorporated herein by reference)

10.23† Amendment to A.J. Best Employment Agreement dated December 31, 2010 (filed as Exhibit 10.28 to the registrant’s Annual

Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)

10.24

Purchase Agreement, dated January 31, 2011, among SM Energy Company and Merrill Lynch, Pierce, Fenner & Smith

Incorporated and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers named therein (filed as Exhibit 10.1

to the registrant’s Current Report on Form 8-K filed on February 1, 2011, and incorporated herein by reference)

10.25 Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit 10.30 to

the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)

10.26+ SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of November 9, 2010 (filed as

Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated

herein by reference)

10.27*† Summary of Compensation Arrangements for Non-Employee Directors

10.28 Fourth Amended and Restated Credit Agreement dated May 27, 2011 among SM Energy Company, Wells Fargo Bank, National

Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Quarterly Report on

Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)

10.29 Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company (filed as

Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by

reference)

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10.30 Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company and ETC Texas

Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and

incorporated herein by reference)

10.31 Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM Energy Company (filed as

Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by

reference)

10.32† Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to the registrant’s

Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)

10.33† Form of Performance Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.6 to the registrant’s Quarterly

Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)

10.34† Form of Restricted Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.7 to the registrant’s Quarterly Report

on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)

10.35† Form of Performance Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.1 to the registrant’s Quarterly

Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference)

10.36† Form of Restricted Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.2 to the registrant’s Quarterly

Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference)

10.37 Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filed as Exhibit

10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by

reference)

10.38 Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filed as Exhibit

10.42 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by

reference)

12.1* Computation of Ratio of Earnings to Fixed Charges

21.1* Subsidiaries of Registrant

23.1* Consent of Deloitte & Touche LLP

23.2* Consent of Ryder Scott Company L.P.

24.1* Power of Attorney

31.1* Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002

31.2* Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002

32.1** Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002

99.1* Ryder Scott Audit Letter

101.INS**** XBRL Instance Document

101.SCH  XBRL Schema Document

101.CAL** ** XBRL Calculation Linkbase Document

101.LAB  XBRL Label Linkbase Document

101.PRE** ** XBRL Presentation Linkbase Document

101.DEF**** XBRL Taxonomy Extension Definition Linkbase Document

 

* Filed with this Form 10-K.

** Furnished with this Form 10-K.

*** Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission

pursuant to Rule 24b-2 under the Securities Exchange Act of 1934.

**** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of

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Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the

Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under

these sections.

† Exhibit constitutes a management contract or compensatory plan or agreement.

s Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the recent

change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the

substantive terms and conditions in this document.

+ Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make

technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and

conditions in this document.

(c) Financial Statement Schedules. See Item 15(a) above.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be

signed on its behalf by the undersigned, thereunto duly authorized.

SM ENERGY COMPANY

(Registrant)

Date: February 21, 2013 By: /s/ ANTHONY J. BEST

Anthony J. Best

Chief Executive Officer

(Principal Executive Officer)

GENERAL POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Anthony J.

Best and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full

power to act alone, for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual

Report on Form 10-K for the fiscal year ended December 31, 2012, and to file the same, with exhibits thereto and other documents in connection

therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or

substitutes, may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the

registrant and in the capacities and on the dates indicated.

Signature Title Date

/s/ ANTHONY J. BEST Chief Executive Officer and Director February 21, 2013

Anthony J. Best (Principal Executive Officer)

/s/ A. WADE PURSELL Executive Vice President and Chief Financial Officer February 21, 2013

A. Wade Pursell (Principal Financial Officer)

/s/ MARK T. SOLOMON Vice President - Controller and Assistant Secretary February 21, 2013

Mark T. Solomon (Principal Accounting Officer)

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Signature Title Date

/s/ WILLIAM D. SULLIVAN Chairman of the Board of Directors February 21, 2013

William D. Sullivan

/s/ BARBARA M. BAUMANN Director February 21, 2013

Barbara M. Baumann

/s/ LARRY W. BICKLE Director February 21, 2013

Larry W. Bickle

/s/ STEPHEN R. BRAND Director February 21, 2013

Stephen R. Brand

/s/ WILLIAM J. GARDINER Director February 21, 2013

William J. Gardiner

/s/ LOREN M. LEIKER Director February 21, 2013

Loren M. Leiker

/s/ JULIO M. QUINTANA Director February 21, 2013

Julio M. Quintana

/s/ JOHN M. SEIDL Director February 21, 2013

John M. Seidl

156
EXHIBIT 10.27

SUMMARY OF COMPENSATION ARRANGEMENTS FOR NON-EMPLOYEE DIRECTORS

The following is a description of the standard arrangements pursuant to which directors of SM Energy are compensated for

services provided as a director, including additional amounts payable for committee participation:

DIRECTOR COMPENSATION

Employee directors do not receive additional compensation for serving on the Board of Directors or any committee.

For service in 2012 - 2013 as it relates to the fiscal period from May 2012 through May 2013, target compensation for each member of the

Board of Directors has been set at $160,000 annually, plus a retainer paid in lieu of committee and attendance fees. As described more fully below, the

actual value of compensation may be higher or lower depending on the results of the restricted stock component of director compensation. Primary

director compensation is in the form of stock grants and is fully described below. The retainer component of director compensation for non-employee

directors consists of an annual retainer of $55,000 for committee and board meeting fees paid in SM Energy common stock or cash as selected by the

director; provided that in the event any director attends in excess of 30 Board and committee meetings in the aggregate during the period from May

2012 through May 2013, such director shall receive $1,500 per meeting for each meeting in excess of 30. In addition, each non-employee director is

reimbursed for expenses incurred in attending Board and committee meetings.

The committee chairs receive the cash payments identified in the list below in recognition of the additional workload of their respective committee

assignments. These amounts are paid at the beginning of the annual service period.

 

• Audit Committee - $20,000

• Compensation Committee - $15,000

• Nominating and Corporate Governance Committee - $10,000

The stock compensation for non-employee directors is as follows:

1) Annual compensation payable upon election to the Board by the stockholders, valued at $160,000. This resulted in a grant of

restricted stock to each non-employee director of 2,884 shares of SM Energy common stock issued on May 24, 2012, under SM

Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year board service period and carry a

subsequent one-year transfer restriction imposed by SM Energy.

2) A retainer for the Non-Executive Chairman of the Board valued at $75,000. This resulted in a grant of 1,352 shares of SM Energy

common stock issued on May 24, 2012, under SM Energy's Equity Incentive Compensation Plan. These shares are earned over the

one-year board service period and carry a subsequent one-year transfer restriction imposed by SM Energy.

3) Barbara M. Baumann, Larry W. Bickle, William J. Gardiner, Julio M. Quintana and William D. Sullivan each elected to receive SM

Energy common stock for their retainer, which resulted in a grant of 992 shares of SM Energy common stock issued on May 24,

2012, under SM Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year Board service period and

carry a subsequent one-year transfer restriction imposed by SM Energy. Stephen R. Brand and John M. Seidl each elected to

receive a $55,000 cash payment for their retainer.

4) Loren M. Leiker joined the Board of Directors effective July 16, 2012. Mr. Leiker received a pro rata grant of restricted stock of

2,966 shares on July 16, 2012, under SM Energy's Equity Incentive Compensation Plan. Mr. Leiker elected to receive SM Energy

common stock for the pro rata share of his retainer, which resulted in a grant of 1,020 shares issued on July 16, 2012, under SM
Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year board service period and carry a

subsequent one-year transfer restriction imposed by SM Energy.
EXHIBIT 12.1

SM Energy Company

Ratio of Earnings to Fixed Charges

Year Ended December 31,

2012 2011 2010 2009 2008

(in thousands, except ratios)

Pretax income from continuing operations $ (83,517) $ 339,001 $ 314,896 $ (159,464) $ 144,736

Add: Fixed charges 77,841 58,030 29,558 31,702 32,604

Add: Amortization of capitalized interest 9,095 5,107 2,991 2,697 2,387

Less: Capitalized interest (12,135) (10,785) (4,337) (1,902) (4,668)

Earnings before fixed charges $ (8,716) $ 391,353 $ 343,108 $ (126,967) $ 175,059

Fixed charges:

Interest expense (1) 63,720 45,849 24,196 28,856 26,950

Capitalized interest 12,135 10,785 4,337 1,902 4,668

Interest expense component of rent (2) 1,986 1,396 1,025 944 986

Total fixed charges $ 77,841 $ 58,030 $ 29,558 $ 31,702 $ 32,604

Ratio of earnings to fixed charges — 6.7 11.6 — 5.4

Insufficient coverage $ 86,557 $ — $ — $ 158,669 $ —

(1) Includes amortization of discount and deferred financing costs.

(2) Represents a reasonable approximation of the rental factor.
EXHIBIT 21.1

SUBSIDIARIES

OF

SM ENERGY COMPANY

A. Wholly-owned subsidiaries of SM Energy Company, a Delaware corporation:

1. Four Winds Marketing, LLC, a Colorado limited liability company

2. SMT Texas LLC, a Colorado limited liability company

3. Energy Leasing, Inc., an Oklahoma corporation

4. Belring GP LLC, a Delaware limited liability company

5. St. Mary Energy Louisiana LLC, a Delaware limited liability company

6. Hilltop Investments, a Colorado general partnership

7. Parish Ventures, a Colorado general partnership

B. Other subsidiaries of SM Energy Company:

1. Box Church Gas Gathering, LLC, a Colorado limited liability company (59%)

C. Partnership or limited liability company interests held by SM Energy Company:

1. Potato Creek Midstream, LLC, a Pennsylvania limited liability company (70%)

2. Wilkinson Pipeline, LLC, a Mississippi limited liability company (24%)

3. Trinity River Systems, LTD, a Texas limited partnership (21%)

4. 1977 H.B Joint Account, a Colorado general partnership (8%)

5. 1976 H.B Joint Account, a Colorado general partnership (9%)

6. 1974 H.B Joint Account, a Colorado general partnership (4%)

7. Sycamore Gas Systems, an Oklahoma general partnership (3%)

D. Partnership interests held by SMT Texas, LLC:

1. St. Mary Land East Texas LP, a Texas limited partnership (99%) (the remaining 1% interest is held by SM Energy Company)
EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Post-Effective Amendment No. 1 to Registration Statement Nos. 333-30055, 333-106438, 333-

35352, and 333-88780 on Form S-8, and Registration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740, and 333-

170351 on Form S-8 of our reports dated February 21, 2013, relating to the consolidated financial statements of SM Energy Company and

subsidiaries and the effectiveness of SM Energy Company and subsidiaries' internal control over financial reporting appearing in this Annual Report

on Form 10-K of SM Energy Company for the year ended December 31, 2012.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

February 21, 2013
EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of

SM Energy Company for the year ended December 31, 2012. We hereby further consent to the use of information contained in our reports, and the

use of our audit letter, as of December 31, 2012, relating to estimates of revenues from SM Energy Company's oil, gas, and NGL reserves. We

further consent to the incorporation by reference thereof into SM Energy Company's Post-Effective Amendment No. 1 to Registration Statement

Nos. 333-30055, 333-35352, 333-88780, and 333-106438 on Form S-8, and Registration Statement Nos. 333-58273, 333-134221, 333-

151779, 333-165740, and 333-170351 on Form S-8.

/s/ RYDER SCOTT COMPANY, L.P.

Ryder Scott Company, L.P. 

Denver, CO

February 21, 2013
EXHIBIT 31.1

CERTIFICATION

I, Anthony J. Best, certify that:

1. I have reviewed this annual report on Form 10-K of SM Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make

the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered

by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material

respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined

in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us

by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under

our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial

statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about

the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such

evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's

most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is

reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,

to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are

reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's

internal control over financial reporting.

Date: February 21, 2013

/s/ ANTHONY J. BEST

Anthony J. Best

Chief Executive Officer
EXHIBIT 31.2

CERTIFICATION

I, A. Wade Pursell, certify that:

1. I have reviewed this annual report on Form 10-K of SM Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make

the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered

by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material

respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined

in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us

by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under

our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial

statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about

the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such

evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's

most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is

reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,

to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are

reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's

internal control over financial reporting.

Date: February 21, 2013

/s/ A. WADE PURSELL

A. Wade Pursell

Executive Vice President and Chief Financial Officer
EXHIBIT 32.1

CERTIFICATION

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of SM Energy Company (the “Company”) for the fiscal year ended December 31,

2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Anthony J. Best, as Chief Executive Officer of the

Company, and A. Wade Pursell, as Executive Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to and

solely for the purpose of 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge and

belief, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m

or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the

Company.

/s/ ANTHONY J. BEST

Anthony J. Best

Chief Executive Officer

February 21, 2013

/s/ A. WADE PURSELL

A. Wade Pursell

Executive Vice President and Chief Financial Officer

February 21, 2013
EXHIBIT 99.1

SM ENERGY COMPANY

Estimated

Future Reserves

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2012

 /s/ Michael F. Stell /s/ James L. Baird

Michael F. Stell, P.E. James L. Baird, P.E.

TBPE License No. 56416 Colorado License No. 41521

Advising Senior Vice President Managing Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580
January 2, 2013

Ms. Kelly Sutton

Manager of Reserves

SM Energy Company

1775 Sherman Street, Suite 1200

Denver, Colorado 80203

Ladies & Gentlemen:

At the request of SM Energy Company (SM Energy), Ryder Scott Company, L.P. (Ryder Scott) has conducted a

reserves audit of the estimates of the proved reserves as of December 31, 2012 prepared by SM Energy's engineering and

geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission

(SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released

January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 2, 2013

and presented herein, was prepared for public disclosure by SM Energy in filings made with the SEC in accordance with the

disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent SM Energy's

estimated net reserves attributable to the leasehold interests in certain properties owned by SM Energy and the portion of

those reserves reviewed by Ryder Scott, as of December 31, 2012. The properties reviewed by Ryder Scott incorporate SM

Energy reserve determinations and are located in the states of Louisiana, Montana, North Dakota, New Mexico, Oklahoma,

Texas and Wyoming.

The properties reviewed by Ryder Scott account for a portion of SM Energy's total net proved reserves as of December

31, 2012. Based on the estimates of total net proved reserves prepared by SM Energy, the reserves audit conducted by

Ryder Scott addresses 81.1 percent of the total proved developed net liquid hydrocarbon reserves, 72.0 percent of the total

proved developed net gas reserves, 95.8 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 89.2

percent of the total proved undeveloped net gas reserves of SM Energy.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating

and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of

reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves

prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the

adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the

classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve

quantities.”

Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our

opinion that the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved

reserves as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves for the

reviewed properties as estimated by SM Energy are, in the aggregate, reasonable within the established audit tolerance

guidelines of 10 percent as set forth in the SPE auditing standards.
The estimated reserves presented in this report are related to hydrocarbon prices. SM Energy has informed us that in

the preparation of their reserve and income projections, as of December 31, 2012, they used average prices during the 12-

month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of

the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual

arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by

SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ

significantly from the estimated quantities presented in this report. The net reserves as estimated by SM Energy attributable to

SM Energy's interest in properties that we reviewed and the reserves of properties that we did not review are summarized as

follows:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold Interests of

SM Energy Company

As of December 31, 2012

Proved

Developed Total

Producing Non-Producing Undeveloped Proved

Net Reserves of Properties

Audited by Ryder Scott

 Oil/Condensate - MBarrels 44,984 25 32,276 77,285

 Plant Products - MBarrels 24,647 76 33,413 58,136

 Gas - MMCF 346,792 1,009 312,375 660,176

Net Reserves of Properties

Not Audited by Ryder Scott

 Oil/Condensate - MBarrels 12,686 1,065 1,194 14,945

 Plant Products - MBarrels 2,316 182 1,663 4,161

 Gas - MMCF 103,739 31,662 37,831 173,232

Total Net Reserves

 Oil/Condensate - MBarrels 57,670 1,090 33,470 92,230

 Plant Products - MBarrels 26,963 258 35,076 62,297

 Gas - MMCF 450,531 32,671 350,206 833,408

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis”

expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas

reserves are located. MBarrels means thousand barrels of oil.

Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and

Exchange Commission's Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a)

entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves

Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behindpipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically

producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve

an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less

than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of

reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative

degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or

unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as

probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At SM Energy's request,

this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data,

can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves

included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined

reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or

as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of

geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate

recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”

Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental

agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and

should not be construed as being exact quantities, and if recovered could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the

quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with

those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission's

Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of

certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1)

performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in

combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select

the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of

reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance

characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this

data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a

range in the quantity of reserves is identified, the evaluator must
determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated

using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is

addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as

proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved

reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more

likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to

be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC

states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and

the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible

reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional

geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve

categories may also be revised due to other factors such as changes in economic conditions, results of future operations,

effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties that we reviewed were estimated by performance methods, the volumetric

method, analogy, or a combination of methods. Approximately 100 percent of the proved producing reserves attributable to

producing wells and/or reservoirs that we reviewed were estimated by performance methods or a combination of methods.

These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir

simulation which utilized extrapolations of historical production and pressure data available through December 2012, in those

cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by

SM Energy or obtained from public data sources and were considered sufficient for the purpose thereof.

Approximately 100 percent of the proved developed non-producing and undeveloped reserves that we reviewed were

estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well and

seismic data furnished to Ryder Scott by SM Energy for our review or which we have obtained from public data sources that

were available through December 2012. The data utilized from the analogues in conjunction with well and seismic data

incorporated into the volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves, we consider many factors and assumptions

including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which

cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future

production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be

economically producible from a given date forward based on existing economic conditions including the prices and costs at

which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future

prices received for the sale of production and the operating costs and other costs relating to such production may increase or

decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC,

omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward

based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be

determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible,

we have reviewed certain primary economic data utilized by SM Energy relating to hydrocarbon prices and costs as noted

herein.

The hydrocarbon prices furnished by SM Energy for the properties reviewed by us are based on SEC price

parameters using the average prices during the 12-month period prior to the ending date of the
period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-themonth for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products

sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were

used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic

average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2012 for the properties reviewed by us were determined

using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the

hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table

below summarizes the “benchmark prices” and “price reference” used by SM Energy for the geographic area reviewed by us.

In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by SM Energy to determine the future gross revenue for each property

reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market,

referred to herein as “differentials.” The differentials used by SM Energy were accepted as factual data and reviewed by us for

their reasonableness; however, we have not conducted an independent verification of the data used by SM Energy.

The table below summarizes SM Energy's net volume weighted benchmark prices adjusted for differentials for the

properties reviewed by us and referred to herein as SM Energy's “average realized prices.” The average realized prices

shown in the table below were determined from SM Energy's estimate of the total future gross revenue before production taxes

for the properties reviewed by us and SM Energy's estimate of the total net reserves for the properties reviewed by us for the

geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of

the geographic areas reviewed by us.

Geographic Area Product

Price

Reference

Average

Benchmark

Prices

Average Realized

Prices

North America

 United States Oil/Condensate WTI Cushing $94.71/Bbl $87.22/Bbl

NGLs MT. Belvieu $45.65/Bbl $41.09/Bbl

Gas Henry Hub $2.76/MMBTU $3.08/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in SM

Energy's individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates

reviewed. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Operating costs furnished by SM Energy are based on the operating expense reports of SM Energy and include only

those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of

general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include

an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties

include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements .

The operating costs furnished by SM Energy were accepted as factual data and reviewed by us for their reasonableness;

however, we have not conducted an independent verification of the data used by SM
Energy. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that

were not charged directly to the leases or wells.

Development costs furnished by SM Energy are based on authorizations for expenditure for the proposed work or

actual costs for similar projects. The development costs furnished by SM Energy were accepted as factual data and reviewed

by us for their reasonableness; however, we have not conducted an independent verification of the data used by SM Energy.

The estimated net cost of abandonment and salvage was included by SM Energy for properties where abandonment costs

and salvage were significant. SM Energy's estimates of the net abandonment costs were accepted without independent

verification.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been

incorporated herein in accordance with SM Energy's plans to develop these reserves as of December 31, 2012. The

implementation of SM Energy's development plans as presented to us is subject to the approval process adopted by SM

Energy's management. As the result of our inquiries during the course of our review, SM Energy has informed us that the

development activities for the properties reviewed by us have been subjected to and received the internal approvals required

by SM Energy's management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as

noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement

(JOA) requirements or other administrative approvals external to SM Energy. Additionally, SM Energy has informed us that

they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by SM Energy were held constant throughout the life of the properties.

SM Energy's forecasts of future production rates are based on historical performance from wells currently on

production. If no production decline trend has been established, future production rates were held constant, or adjusted for the

effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was

then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for

estimating future production rates.

Test data and other related information were used by SM Energy to estimate the anticipated initial production rates for

those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence

at an anticipated date furnished by SM Energy. Wells or locations that are not currently producing may start producing earlier

or later than anticipated in SM Energy's estimates due to unforeseen factors causing a change in the timing to initiate

production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or

recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may

be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions

related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market

demand and/or allowables or other constraints set by regulatory bodies.

SM Energy's operations may be subject to various levels of governmental controls and regulations. These controls and

regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce

hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various

taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations

and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to

differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which SM

Energy owns an interest; however, we have not made any field examination of the
properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs

included by SM Energy for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of SM Energy are responsible for the preparation of reserve estimates on new properties

and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary

data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had

access to their workpapers and supporting data in the course of our audit.

SM Energy has informed us that they have furnished us all of the material accounts, records, geological and

engineering data, and reports and other data required for this investigation. In performing our audit of SM Energy's forecast of

future proved production, we have relied upon data furnished by SM Energy with respect to property interests owned,

production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as

transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment

costs and salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological

structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data

for its reasonableness; however, we have not conducted an independent verification of the data furnished by SM Energy. The

data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our

examination, a matter of question came to our attention in which case the data were not accepted until all questions were

satisfactorily resolved. We consider the factual data furnished to us by SM Energy to be appropriate and sufficient for the

purpose of our review of SM Energy's estimates of reserves. In summary, we consider the assumptions, data, methods and

analytical procedures used by SM Energy and as reviewed by us appropriate for the purpose hereof, and we have used all

such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions

set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our

opinion that the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved

reserves as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves for the

reviewed properties as estimated by SM Energy are, in the aggregate, reasonable within the established audit tolerance

guidelines of 10 percent as set forth in the SPE auditing standards.

We were in reasonable agreement with SM Energy's estimates of proved reserves for the properties which we

reviewed. As a consequence, it is our opinion that on an aggregate basis the data presented herein for the properties that we

reviewed fairly reflects the estimated net reserves owned by SM Energy.

Other Properties

Other properties, as used herein, are those properties of SM Energy which we did not review. The proved net reserves

attributable to the other properties account for 12.4 percent of the total proved net liquid hydrocarbon reserves and 20.8 percent

of the total proved net gas reserves based on estimates prepared by SM Energy as of December 31, 2012. The other

properties represent 15.6 percent of the total proved discounted future net income based on the unescalated pricing policy of

the SEC as taken from reserve and income projections prepared by SM Energy as of December 31, 2012.

The same technical personnel of SM Energy were responsible for the preparation of the reserve estimates for the

properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting

services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas;

Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By

virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a

material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and

gas company and are separate and independent from the operating and investment decision-making process of our clients.

This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum

focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical

papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by

actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received

professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified

professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized selfregulating professional organization.

We are independent petroleum engineers with respect to SM Energy. Neither we nor any of our employees have any

interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our

estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and

engineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible for

overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure

requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by

SM Energy.

SM Energy makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, SM

Energy has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed

Form 10-K is incorporated by reference. We have consented to the incorporation by reference thereof into the Company's

Post-Effective Amendment No. 1 to Registration Statement Nos. 333-30055, 333-35352, 333-88780, and 333-106438 on

Form S-8 and Registration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740 and 333-170351 on Form

S-8 of SM Energy of the references to our name as well as to the references to our third party report for SM Energy, which

appears in the December 31, 2011 annual report on Form 10-K of SM Energy. Our written consent for such use is included

as a separate exhibit to the filings made with the SEC by SM Energy.

We have provided SM Energy with a digital version of the original signed copy of this report letter. In the event there are

any differences between the digital version included in filings made by SM Energy and the original signed report letter, the

original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in

our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580
/s/ Michael F. Stell

Michael F. Stell, P.E.

TBPE License No. 56416

Advising Senior Vice President

/s/ James L. Baird

James L. Baird, P.E.

Colorado License No. 41521

Managing Senior Vice President
Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and

engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing

the estimate of the reserves, future production and income.

Mr. Stell, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is

responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation

studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company

and Landmark Concurrent Solutions. For more information regarding Mr. Stell's geographic and job specific experience, please

refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of

Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional

Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum

Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers

requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional

ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13

hours of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in

the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas

Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of

formalized in-house training as well as an additional five hours of formalized external training during 2009 covering such topics

as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum

economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education

hours, Mr. Stell attended an internally presented six hours of formalized training and ten hours of formalized external training

covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve

reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves,

evaluation of enhanced oil recovery reserves, and ethics training. For 2011 and 2012, as of the date of this report, Mr. Stell has

20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.

Based on his educational background, professional training and over 30 years of practical experience in the estimation and

evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves

Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information”

promulgated by the Society of Petroleum Engineers as of February 19, 2007.
Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and

engineers from Ryder Scott Company L.P. James Larry Baird was the primary technical person responsible for overseeing the

estimate of the reserves.

Mr. Baird, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President and also

serves as Manager of the Denver office, responsible for coordinating and supervising staff and consulting engineers of the

company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Baird served in a number of

engineering positions with Gulf Oil Corporation, Northern Natural Gas and Questar Exploration & Production. For more

information regarding Mr. Baird's geographic and job specific experience, please refer to the Ryder Scott Company website at

www.ryderscott.com/Experience/Employees.

Mr. Baird earned a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970 and

is a registered Professional Engineer in the States of Colorado and Utah. He is also a member of the Society of Petroleum

Engineers.

In addition to gaining experience and competency through prior work experience, the Colorado and Utah Board of Professional

Engineers recommend continuing education annually, including at least one hour in the area of professional ethics, which Mr.

Baird fulfills. As part of his 2011 continuing education hours, Mr. Baird attended an internally presented sixteen hours of

formalized training as well as an eight hour public forum. Mr. Baird attended the 2010 and 2011 RSC Reserves Conference

and various professional society presentations specifically on the new SEC regulations relating to the definitions and disclosure

guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations,

Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Baird attended an

additional sixteen hours of formalized in-house training during 2011 and 2012 covering such topics as the

SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum

economics evaluation methods, reserve reconciliation processes, overviews of the various productive basins of North America,

evaluations of resource play reserves, procedures and software and ethics for consultants. Mr. Baird was a keynote speaker,

presenting the Changing Landscape of the SEC Reporting, at the 2009 Unconventional Gas International Conference held in

Fort Worth, Texas.

Based on his educational background, professional training and more than 40 years of practical experience in the estimation

and evaluation of petroleum reserves, Mr. Baird has attained the professional qualifications as a Reserves Estimator and

Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves

Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of

Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The

“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of

Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies

Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to

Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take

effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after

January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part

210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC

document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically

producible, as of a given date, by application of development projects to known accumulations. All reserve estimates

involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or

less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the

amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The

relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or

unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as

probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC

regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of

probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit

disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any

document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state

law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as

economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods

include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.

Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding,

and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the

future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum

accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics,

extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include

coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale

deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing

prior to sale.
Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from

different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be

economically producible, as of a given date, by application of development projects to known accumulations. In addition,

there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue

interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and

financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing,

faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to

areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e., absence of reservoir,

structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially

recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as

follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of

geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given

date forward, from known reservoirs, and under existing economic conditions, operating methods, and government

regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal

is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project

to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the

project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous

with it and to contain economically producible oil or gas on the basis of available geoscience and engineering

data.

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known

hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable

technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the

potential exists for an associated gas cap, proved oil reserves may be assigned in the
structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable

technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including,

but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in

the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or

other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on

which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including

governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be

determined. The price shall be the average price during the 12-month period prior to the ending date of the period

covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each

month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon

future conditions.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be

made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following

reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the

aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as

follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required

equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate

if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further subclassified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing

at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:
(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional

completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a

new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as

follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on

undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas

that are reasonably certain of production when drilled, unless evidence using reliable technology

exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been

adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances,

justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for

which an application of fluid injection or other improved recovery technique is contemplated, unless such

techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as

defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing

reasonable certainty.