Company: SOUTHWESTERN ENERGY CO
CIK: 7332
SIC: 1311
Filing Date: 2015-02-26 00:00:00

ITEM 1 - BUSINESS
ITEM 1. BUSINESS
Southwestern Energy Company (including its subsidiaries, collectively, “we”, “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production (“E&P”). We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services. We conduct substantially all of our business through subsidiaries.
Exploration and Production - Our primary business is the exploration for and production of natural gas and oil, with our current operations principally focused within the United States on development of two unconventional natural gas reservoirs located in Arkansas and Pennsylvania. Our operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale, and our operations in northeast Pennsylvania are focused on the unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”). Recently, we acquired a significant stake in properties located in West Virginia and southwest Pennsylvania, which we also intend to develop. These operations in West Virginia also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”). Collectively, our properties located in West Virginia and Pennsylvania are herein referred to as the “Appalachian Basin.” To a lesser extent, we have exploration and production activities ongoing in Colorado, Louisiana, Texas and in the Arkoma Basin in Arkansas and Oklahoma. We also actively seek to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which we refer to as “New Ventures,” and through acquisitions. We also operate drilling rigs in Arkansas and Pennsylvania, as well as in other operating areas, and provide oilfield products and services, principally serving our exploration and production operations.
Midstream Services - We engage in natural gas gathering activities in Arkansas, Texas, Louisiana, Pennsylvania, and West Virginia. These activities primarily support our E&P operations and generate revenue from fees associated with the gathering of natural gas. Our marketing activities capture downstream opportunities that arise through the marketing and transportation of the natural gas, oil and natural gas liquids (NGLs) produced in our E&P operations.
The vast majority of our operating income and earnings before interest, taxes, depreciation, depletion and amortization and any non-cash impairment of natural gas and oil properties or (gain) loss on derivatives, excluding derivatives, settled (“Adjusted EBITDA”), are derived from our E&P business. In 2014, 74% of our operating income and 82% of our Adjusted EBITDA were generated from our E&P business, compared to 73% of our operating income and 81% of our Adjusted EBITDA in 2013 and, 65% of our operating income, absent our $1,940 million, or $1,192 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties, and 79% of our Adjusted EBITDA in 2012. The remainder of our consolidated operating income and Adjusted EBITDA in each of these years was generated from Midstream Services. Adjusted EBITDA is a non-GAAP measure. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Reconciliation of Non-GAAP Measures” in Item 7 of Part II of this Annual Report for a table that reconciles Adjusted EBITDA to net income (loss).
In December 2014, our principal executive offices moved to 10000 Energy Drive, Spring, Texas 77389. Our telephone number is (832) 796-4700. Our website is www.swn.com. The information included on our website is not part of, or incorporated by reference into, this Annual Report.
Our Business Strategy
Since 1999, our management has been guided by our formula, which represents the essence of our corporate philosophy and how we operate our business:
Our formula, which stands for “The Right People doing the Right Things, wisely investing the cash flow from our underlying Assets will create Value+,” also guides our business strategy. We are focused on providing long-term growth in the net asset value of our business. In our E&P business, we prepare an economic analysis for each investment opportunity based upon the expected net present value added for each dollar to be invested, which we refer to as Present Value Index, or PVI. The PVI for each project is determined using a 10% discount rate. We target creating an average of at least $1.30 of pre-tax PVI for each dollar we invest in our E&P projects. Our actual PVI results are utilized to help determine the allocation of our future capital investments. The key elements of our business strategy are:
·
Exploit and Develop Our Positions in the Fayetteville Shale and the Appalachian Basin. A key focus of the Company is to maximize the value of our significant acreage position in the Fayetteville Shale, which has provided significant production and reserve growth since we began drilling in 2004. As of December 31, 2014, we held approximately 888,161 net acres in the Fayetteville Shale, accounting for approximately 47% of our total proved natural gas and oil
reserves and approximately 64% of our total natural gas and oil production during 2014. Additionally, we are actively drilling on portions of our 266,073 net acres in Northeast Appalachia and believe our production and reserves from the Marcellus Shale will grow substantially over the next few years. Our Northeast Appalachia acreage accounted for approximately 30% of our total proved natural gas and oil reserves and 33% of our total natural gas and oil production during 2014. We also closed a transaction for approximately 413,000 net acres, the “Chesapeake Property Acquisition,” in West Virginia and southwest Pennsylvania in December 2014 where we plan to target the Marcellus, Upper Devonian and Utica Shales, with an additional approximate 30,000 net acres which closed January 2015, the “Statoil Property Acquisition.” Additionally in January 2015, we closed a transaction for approximately 46,700 net acres in northeast Pennsylvania from WPX Energy, Inc. (“WPX”). We refer to the transaction with WPX as the “WPX Property Acquisition.” As of December 31, 2014, the reserves from the Chesapeake Property Acquisition accounted for approximately 22% of our total proved natural gas and oil reserves. We intend to further develop our acreage positions in the Fayetteville Shale and the Appalachian Basin and to improve our well results through the use of advanced technologies and detailed technical analysis of our properties. We refer to the Chesapeake, Statoil and WPX Property Acquisitions collectively as the “Acquisitions.”
·
Grow through New Exploration and Development Activities Focusing on Emerging Unconventional Plays. We actively seek to find and develop new natural gas and oil plays with significant exploration and exploitation potential. Our New Ventures prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria, and can be located both inside and outside of the United States. In addition to having E&P employees specifically focused on New Ventures activities, we also have a robust staff of employees focused on strategic business development activities. As of December 31, 2014, we held 4,170,687 net undeveloped acres in connection with our New Ventures prospects, of which 2,518,518 net acres are located in New Brunswick, Canada. During 2014, we purchased approximately 380,000 net acres in northwest Colorado principally in the Niobrara formation and are commencing exploration and development on these properties.
·
Maximize Efficiency through Vertical Integration and Economies of Scale. In our key operating areas, the concentration of our properties allows us to achieve economies of scale that result in lower costs. We seek to serve as the operator of the wells in which we have a significant interest. As the operator, we are better positioned to control the drilling, completing and producing of wells and the marketing of production to minimize costs and maximize both production volumes and realized price. In the Fayetteville Shale and the Appalachian Basin, we have achieved significant cost savings through our vertical integration. Our vertical integration includes ownership of a sand mine in the Fayetteville Shale, that is a source of proppant for our well completions, and through our operation of other associated oilfield services, including a fleet of drilling rigs and two pressure pumping equipment spreads used for well completions.
·
Enhance the Value of Our Midstream Operations. We have continued to design and improve our gas gathering infrastructure to better manage the physical movement of our production. As of December 31, 2014, we have invested approximately $1,184 million in the 2,017 mile gas gathering system built for our Fayetteville Shale asset, which was gathering approximately 2.4 Bcf per day at year-end, and have invested approximately $247 million in 146 miles of gas gathering lines in Pennsylvania, Louisiana and East Texas. Our gathering system in the Fayetteville Shale has developed into a strategic asset that supports our E&P operations.
Significant Accomplishments in 2014
Production and Reserve Growth. In 2014, our production was 768 Bcfe, or approximately 2.1 Bcfe per day, an increase of 17% from 2013 levels. This increase was driven primarily by production growth of 69% from our Northeast Appalachia division. Additionally, in 2014 our total proved reserves increased to the highest level in our company’s history, growing by 54% to approximately 10.7 Tcfe.
Low Cost Structure. Our cost structure continues to be one of the lowest in the industry, with an all-in cash operating cost of $1.32 per Mcfe in 2014, compared to $1.25 per Mcfe in 2013. All-in cash operating cost per Mcfe is defined as the per Mcfe sum of our E&P segment’s lease operating expenses, taxes (other than income taxes), general and administrative expenses, and net interest expense. We have included information concerning this ratio as it measures the cost efficiency of a company’s oil and gas producing operations and is a measure commonly used in our industry.
Northeast Appalachia Achieves Significant Growth. Our Northeast Appalachia division drove our overall production growth in 2014, with gross operated production surpassing 1.0 Bcfe per day at year-end 2014 compared to 700 MMcf per day at year-end 2013. Production increased to 254 Bcf in 2014, compared to 151 Bcf in 2013, while total proved reserves increased to approximately 3.2 Tcf, compared to 2.0 Tcf in 2013.
Fayetteville Shale Continues to Deliver. In 2014, our Fayetteville Shale division again had one of its best years ever. In its tenth year of development, the division achieved 24 of its best 30 wells based on average initial production rate as it applies the learnings obtained from its focus on innovation. Total proved reserves for the Fayetteville Shale increased in 2014 to approximately 5.1 Tcf, from 4.8 Tcf in 2013, and 2014 production increased to 494 Bcf, up from 486 Bcf in 2013.
Financial Flexibility. We ended 2014 with a capital structure that consisted of 60% debt and 40% equity and had approximately $1.7 billion of borrowing capacity available under our principal credit facility. In January 2015, we reduced our debt by approximately $2.3 billion through an equity offering. Had this equity offering occurred in 2014, our capital structure would have consisted of 40% debt and 60% equity. At December 31, 2014, our debt was rated as investment grade by three of the major rating agencies: “BBB” with a stable outlook by Standard and Poor’s (S&P), “BBB-” with a stable outlook by Fitch Ratings (Fitch) and “Baa3” with a stable outlook by Moody’s Investors Service (Moody’s). In January 2015, Standard and Poor’s (S&P) downgraded us to BBB- with a stable outlook. We are committed to maintaining financial flexibility as it moves forward with the integration and development of the recently acquired assets in the Appalachian Basin.
Recent Developments
2015 Planned Capital Investments and Production Guidance. Excluding the capital associated with the closing of the WPX and Statoil Property Acquisitions, our planned capital investment program for 2015 is approximately $2.0 billion, which includes approximately $1.9 billion for our E&P segment, $85 million for our Midstream Services segment and $40 million for E&P services and corporate. The planned capital program for 2015 is flexible, and we will reevaluate our proposed investments as needed to take into account prevailing market conditions. Based on our capital program, we are targeting 2015 natural gas and oil production of approximately 940 to 955 Bcfe, an increase of approximately 23% over our 2014 production, using midpoints.
Equity Offering. In January 2015, we completed concurrent underwritten public offerings of 30,000,000 shares of our common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares). Net proceeds from the offerings totaled approximately $2.3 billion after underwriting discount and offering expenses. The common stock offering was priced at $23.00 per share. Net proceeds, after underwriting discount and expenses, from the common stock offering were approximately $669 million. Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1.7 billion. Each depositary share represents a 1/20th interest in a share of our 6.25% Series B Mandatory Convertible Preferred Stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share). The proceeds from the offerings were used to partially repay borrowings under our $4.5 billion 364-day bridge term loan facility incurred in connection with the Chesapeake Property Acquisition.
Debt Offering. In January 2015, we completed a public offering of $350 million aggregate principal amount of our 3.300% senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of our 4.050% senior notes due 2020 (the “2020 Notes”) and $1 billion aggregate principal amount of our 4.950% senior notes due 2025 (the “2025 Notes” and together with the 2018 Notes and the 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses. The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 Notes. The proceeds from the offering were used to repay all principal and interest remaining outstanding under our $4.5 billion 364-day bridge term loan facility incurred in connection with the Chesapeake Property Acquisition and were used to repay a portion of amounts outstanding under our revolving credit facility.
Exploration and Production
Overview
Operations in our E&P segment are primarily in the Fayetteville Shale and Appalachian Basin assets. We also intend to conduct additional exploration and production activities in the Sand Wash Basin and other basins targeting various formations as part of our New Ventures projects. We continue to actively seek to acquire and develop both conventional and unconventional natural gas and oil resource plays with significant exploration and exploitation potential.
Our E&P segment recorded operating income of $1,013 million in 2014, operating income of $879 million in 2013, and an operating loss of $1,396 million in 2012 as a result of a $1,940 million, or $1,192 million net of taxes, non-cash ceiling test impairment of our United States natural gas and oil properties. Operating income for 2014 increased $134 million compared to 2013 as a result of an increase in revenue of $403 million from higher natural gas production volumes, an increase in revenue of $55 million from increased prices realized from the sale of our natural gas production, offset by an increase in operating costs and expenses of $324 million associated with the expansion of our operations and higher activity levels in the Fayetteville Shale and Northeast Appalachia. Operating income for 2013 increased $335 million
compared to 2012 (excluding the $1,940 million non-cash ceiling test impairment recorded in 2012) as a result of an increase in revenue of $316 million from higher natural gas production volumes, an increase in revenue of $118 million from increased prices realized from the sale of our natural gas production and an increase in revenues of $6 million from higher oil volumes, offset by an increase in operating costs and expenses of $106 million associated with the expansion of our operations and higher activity levels in the Fayetteville Shale and Northeast Appalachia. Adjusted EBITDA from our E&P segment was $1.9 billion in 2014, compared to $1.6 billion in 2013 and $1.3 billion in 2012. Our Adjusted EBITDA increased in 2014 and 2013 as higher realized gas prices and production volumes more than offset increased total operating costs and expenses due to increased activity levels. Adjusted EBITDA is a non-GAAP measure. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Reconciliation of Non-GAAP Measures” in Item 7 of Part II of this Annual Report for a table that reconciles Adjusted EBITDA to net income (loss).
Oilfield Services Vertical Integration
We seek to provide oilfield services that are strategic and economically beneficial for our E&P operations. This vertical integration lowers our net well costs, allows us to operate safely and efficiently and mitigates certain operational environmental risks. Among others, these services include drilling, hydraulic fracturing and the mining of proppant used for our well completions.
Sand Mine
Since 2009, we have owned and operated a sand mine to provide a reliable supply of proppant primarily used for the completion of our wells that we operate in the Fayetteville Shale. As of December 31, 2014, our sand mine is comprised of 570 acres and produces 30/70 and 100 mesh sized sand. In 2014, we provided sand for the completion of 453 wells operated by us in the Fayetteville Shale and were able to reduce our well completion costs on average by 9% per well for the wells for which we provided sand.
Hydraulic Fracturing
We provide pressure pumping services for a portion of our operated wells. As of December 31, 2014, we operated 2 leased pressure pumping spreads with a total capacity of approximately 72,000 horsepower to conduct a variety of completion services designed to stimulate natural gas production. In 2014, we provided pressure pumping services for 224 wells that we operated in the Fayetteville Shale and were able to reduce our well completion costs on average by 12% per well for the wells we completed.
Drilling Services
We conduct drilling operations for a portion of our operated wells. As of December 31, 2014, we operated 9 re-entry rigs and 2 spudder rigs which were operating in Arkansas, Pennsylvania and Louisiana. In 2014, we provided drilling services for 426 and 43 wells that we operate in the Fayetteville Shale and Northeast Appalachia, respectively, and were able to reduce our drilling costs on average by 4% and 1% per well for the wells we drilled in the Fayetteville Shale and Northeast Appalachia, respectively.
Our Proved Reserves
Our estimated proved natural gas and oil reserves were 10,747 Bcfe at year-end 2014, compared to 6,976 Bcfe at year-end 2013 and 4,018 Bcfe at year-end 2012. The significant increase in our reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, our successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia. Because our proved reserves are primarily natural gas, our reserve estimates and the after-tax PV-10 measure, or standardized measure of discounted future net cash flows relating to proved natural gas and oil reserve quantities, are highly dependent upon the natural gas price used in our reserve and after-tax PV-10 calculations. In order to value our estimated proved natural gas, NGL and oil reserves as of December 31, 2014, we utilized average prices from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.35 per MMBtu for natural gas, West Texas Intermediate oil of $91.48 per barrel for oil and $23.79 per barrel for NGLs compared to $3.67 per MMBtu for natural gas, $93.42 per barrel for oil, and $43.45 per barrel for NGLs at December 31, 2013 and $2.76 per MMBtu for natural gas and $91.21 per barrel for oil at December 31, 2012.
Our after-tax PV-10 was $7.5 billion at year-end 2014, $3.7 billion at year-end 2013, and $2.1 billion at year-end 2012. The increase in our after-tax PV-10 value in 2014 over 2013 was principally due to an increase in our reserves and higher average natural gas prices. The increase in our after-tax PV-10 value in 2013 over 2012 was principally due to an
increase in our reserves and higher average natural gas prices. The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2014 Proved Reserves by Category and Summary Operating Data table below) is the discounted value of future income taxes on the estimated cash flows. Our year-end 2014 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pre-tax PV-10, of $9.5 billion, compared to $5.1 billion at year-end 2013 and $2.3 billion at year-end 2012.
We believe that the pre-tax PV-10 value of the estimated cash flows related to our estimated proved reserves is a useful supplemental disclosure to the after-tax PV-10 value. While pre-tax PV-10 is based on prices, costs and discount factors that are comparable from company to company, the after-tax PV-10 is dependent on the unique tax situation of each individual company. We understand that securities analysts use pre-tax PV-10 as one measure of the value of a company’s current proved reserves and to compare relative values among peer companies without regard to income taxes. We refer you to Note 4 in the consolidated financial statements for a discussion of our standardized measure of discounted future cash flows related to our proved natural gas and oil reserves, to the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in

ITEM 1A - RISK FACTORS
ITEM 1A. RISK FACTORS
In addition to the other information included in this Annual Report, the following risk factors should be considered in evaluating our business and future prospects. The risk factors described below represent what we believe are the most significant risk factors with respect to us and our business. In assessing the risks relating to our business, investors should also read the other information included in this Annual Report, including our financial statements and the related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation - Cautionary Statement about Forward-Looking Statements.”
Our revenues and the value of our assets are highly dependent on the prices for natural gas and, to a lesser extent, oil. These prices are volatile, and a substantial or extended decline in natural gas and oil prices would have a material adverse effect on us.
Our financial results and the value of our assets correlate closely to the prices we can and do obtain for what we produce, in particular natural gas, which historically has accounted for almost 100% of our production. Prices for natural gas and oil are highly volatile and unpredictable. The following factors, among others, affect the supply of and demand for natural gas and oil:
·
Changes in consumption patterns, including those resulting from population changes and migrations, new technologies and grown in emerging markets
·
Global and local economic conditions
·
Inventory levels
·
Ability and cost of transporting product to markets, including the ability to connect resources to pipelines or other means of transportation, bottlenecks in pipeline or other transportation capacity such as many are experiencing in the Marcellus and the Utica Shales, export and import controls and other constraints
·
Production disruptions
·
Actions of governments and multinational groups, such as the Organization of Petroleum Exporting Countries (OPEC)
·
Currency exchange rates
·
Competition from other producers and from other energy sources, including renewables, which affects the level of supply
·
Technological developments
·
Weather, earthquakes and other natural events
·
Market perceptions of future prices, whether due to the foregoing factors or others
A significant or extended decline in natural gas and oil prices, such as the one from 2008 into 2012 when the NYMEX natural gas price dropped from $13.58 to $1.91 per MMBtu, would have a material adverse effect on our financial position, our results of operations, our access to capital and the quantities of natural gas and oil that we can produce economically, including the following:
·
The cash flows from our operations would be reduced, decreasing funds available for capital investments employed to replace reserves or increase production.
·
Lower prices would reduce the value of our natural gas and oil assets and, in some cases, make them no longer be economic to produce. This could result in impairments to the values of our assets, such as occurred in 2012.
·
Access to other sources of capital, such as equity or debt markets, could be severely limited or unavailable.
·
We could fail to meet financial or other covenants in the documentation governing our debt, leading to mandatory prepayments or defaults.
·
Locational price differentials change, making it difficult to predict the best locations to conduct our activities.
·
Varying perceptions of future prices can lead to difficulties in agreeing on the value of assets in acquisitions or dispositions.
We endeavor to mitigate against these risks through hedging a significant portion of our production. Hedging also presents risks, including our failure to project the appropriate volumes and price points for hedges and the creditworthiness of our counterparties. For a discussion of our hedging activities, we refer you to Note 5 to the consolidated financial
statements included in this Annual Report. Additionally, we mitigate these risks, in part, through our Midstream Services business, which generates cash flow that is largely fee-based and thus not directly impacted by commodity price volatility.
Our ability to sell our natural gas and oil and/or to receive market prices for our production may be adversely affected by constraints or interruptions on gathering systems, pipelines, processing and transportation systems owned or operated by us or others.
The marketability of our natural gas and oil production depends in part on the availability, proximity, and capacity of gathering systems, processing 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 shutting in producing wells, delaying or discontinuing the development plans for our properties or receiving lower prices. Although we have some contractual control over the transportation and gathering of our production, material changes in these business relationships could materially affect our operations. Federal and state regulation of natural gas and oil production, processing 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, and transport natural gas. In particular, continued development in the Appalachian Basin by us and others could overtax the capacity of existing gathering and pipeline system, and new or expanded capacity may not be in place in time.
The vast majority of our current operations and production are in the Fayetteville Shale, Northeast Appalachia and Southwest Appalachia, and significant events or circumstances affecting one or more of these areas could have a material and adverse effect on our operations in those areas and thus our overall performance.
Production from the Fayetteville Shale and Northeast Appalachia accounted for 64% and 33%, respectively, of our consolidated production and, when considering both our E&P and Midstream Services business, essentially all of our operating income in 2014. Our current Fayetteville Shale operations are almost entirely in Arkansas, and our current Northeast Appalachia and Southwest Appalachia operations currently are only in Pennsylvania and West Virginia. Significant events or circumstances of the types described elsewhere in these Risk Factors or otherwise that affect one or more of these areas would affect a very large part of our operations simultaneously and, even if they do not affect the industry generally, would affect us disproportionately compared to other companies. Those events and circumstances include changes in local laws and regulations, constraints on transportation, natural events, localized price changes and availability of water, skilled personnel, equipment, services and supplies, among others.
If we fail to find or acquire additional reserves, our reserves and production will decline materially from their current levels.
The rate of production from natural gas and oil properties generally declines as reserves are depleted. Unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities, successfully apply new technologies or identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline materially as reserves are produced. Future natural gas and oil production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.
Our business could be adversely affected by competition with other companies.
The natural gas and oil industry is highly competitive, and our business could be adversely affected by companies that are in a better competitive position. As an independent natural gas and oil company, we frequently compete for reserve acquisitions, exploration leases, licenses and concessions, marketing agreements, transportation, equipment and labor against companies with financial and other resources substantially larger than those we possess. Many of our competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors have been operating in some of our core areas for a much longer time than we have or have established strategic long-term positions in geographic regions in which we may seek new entry.
Natural gas and oil exploration and production is an inherently risky business with many uncertainties and potential liabilities. The results of our activities may not be what we project, and not all our liabilities and other exposures may be covered by insurance.
By its nature, exploring for and producing natural gas and oil involves substantial capital investment with no assurance of return, or returns at expected levels, and the risk of environmental and other liability. Among other things:
·
Although we utilize sophisticated geological and geophysical tools to determine where to drill, these do not
predict with certainty the presence of natural gas or oil or the rate at which they can be produced. Some wells will result in no production, production that does not cover costs or production at lower levels than expected.
·
During drilling we can face difficulties in landing our wellbore in the desired zones, staying in the desired zones while drilling horizontally, penetrating rock formations, controlling well pressure, stimulating reservoirs through fracturing and cleaning the wellbore following fracturing and running casing the entire length of the wellbore. These circumstances can delay completion, increase costs and possibly lead to the abandonment of the particular location.
·
When we acquire properties or businesses through acquisitions, including properties already producing, we may fail to assess correctly the potential of the properties, the costs of integration and development, matters affecting legal title and thus the right to drill and ownership of production, the liabilities that we assume as part of the acquisition and the risks associated with ownership, development and operation.
·
Equipment can fail or not be available and pipelines can rupture.
·
We can encounter well blowouts, cratering, explosions, pipeline failure, fires, brine or other fluids, drainage of production from neighboring properties and other hazards.
·
Earthquakes and hurricanes, storms and other weather events can interfere with drilling activities and operations.
·
Although we believe we maintain a robust health, safety and environmental program, incidents can occur, whether due to natural events, the actions of third parties or our own errors or oversights. Spills, injuries or other calamities can result in liability for our Company, damage to our properties and interruption of our operations.
We maintain insurance against many potential losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent. Our insurance does not protect us against all operational risks; for example, we generally do not maintain business interruption insurance, and pollution and environmental risks generally are not fully insurable. These risks could give rise to significant costs not covered by insurance that could have a material adverse effect upon our financial results.
Our business strategy depends on executing extensive drilling programs and controlling costs to improve our overall return. Shortages of oilfield equipment, services, supplies, raw materials and qualified personnel could adversely affect our ability to implement our programs or to achieve our desired levels of costs.
We are engaged in large-scale programs to develop our assets, particularly in the Fayetteville Shale, Northeast Appalachia and Southwest Appalachia. We are achieving economies of scale through our sizeable operations in these two areas and, in some cases, vertical integration in certain oilfield services, such as drilling, sand mining and pressure control. We nonetheless compete with other companies for oilfield equipment, services, supplies, raw materials and qualified personnel. In particular, the demand for qualified and experienced field personnel to drill wells and conduct field operations and for geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These factors also cause significant increases in costs for equipment, services, personnel and raw materials (such as sand, cement, manufactured proppants and other materials utilized in the provision of the oilfield services). Higher natural gas and oil prices generally stimulate increased demand and result in increased costs for professional personnel, drilling rigs, crews and associated supplies, equipment, services and raw materials. In addition, our E&P operations also require local access to large quantities of water supplies and disposal services for produced water in connection with our hydraulic fracture stimulations due to prohibitive transportation costs. We cannot be certain when we will experience shortages or cost increases, which could adversely affect our profit margin, cash flow and operating results or restrict our ability to drill wells and conduct ordinary operations.
Our announced drilling plans can change due to various factors.
As of December 31, 2014, we had drilled and completed 3,742 operated wells relating to our Fayetteville Shale play and 277 operated wells relating to Northeast Appalachia. At year-end 2014, after the exclusion of our acreage in the traditional Fairway and the approximately 158,000 net federal acres we hold in the Ozark Highlands Unit, approximately 85% of our leasehold acreage in the Fayetteville Shale was held by production. Approximately 23% and 54% of our leasehold acreage in Northeast Appalachia and Southwest Appalachia was held by production at year-end 2014, respectively. Our drilling plans are flexible and are dependent upon a number of factors, including the extent to which we can replicate the results of our most successful wells in addition to the natural gas and oil commodity price environment. The determination as to whether we continue to drill wells in our operating areas may depend on any one or more of the following factors:
·
our ability to determine the most effective and economic fracture stimulation;
·
our ability to transport our production to the most favorable markets;
·
material changes in natural gas prices (including regional basis differentials);
·
changes in the costs to drill, complete or operate wells and our ability to reduce drilling risks;
·
the extent of our success in drilling and completing horizontal wells;
·
the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment services
·
success or failure of wells drilled in similar formations of which would use the same production facilities;
·
receipt of additional seismic or other geologic data or reprocessing of existing data;
·
the extent to which we are able to effectively operate our own drilling rigs;
·
availability and cost of capital; or
·
the impact of federal, state and local government regulation, including any increase in severance taxes.
We continue to gather data about our prospects in our operating areas, and it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all.
Our ability to produce natural gas and oil could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.
Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our E&P 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 waste, 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.
Our financial condition and results of operation could be adversely affected by legislative and regulatory initiatives in the United States and elsewhere relating to environmental matters, particularly hydraulic fracturing and climate change, which could result in increased costs and additional operating restrictions or delays or prevent us from realizing the value of undeveloped acreage.
As described more fully under “Other - Environmental Regulation” in Item 1 of Part I of this Annual Report our operations are subject to extensive environmental regulation. New regulations can increase costs or delay or prevent us from achieving our goals. In particular, we often utilize hydraulic fracturing in our drilling activities, and it forms a critical part of our cost structure and success. As also described there, various governmental and non-governmental groups are advocating restrictions and, in some instances, outright bans on the use of hydraulic fracturing.
Our E&P operations are currently focused on the production of hydrocarbons from unconventional sources, and we expect to continue to focus on such resources in the future. The production of hydrocarbons from these sources has an energy intensity that is a number of times higher than that for production from conventional sources. Therefore, we expect that the greenhouse gas intensity of our production will increase in the long-term. We actively seek to reduce the environmental impact of our operations by pursuing more efficient use of natural resources such as hydrocarbons and water and managing and mitigating the emissions to the air, water and soil, with a focus on the reduction of greenhouse gas emissions. With the efforts of our Health, Safety and Environmental Department, we have been able to plan for and comply with environmental initiatives without materially altering our operating strategy. We anticipate making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment that will increase the cost of equipment, materials and services whose production utilizes hydrocarbons. We may also face increased competition from alternative energy sources that do not rely on hydrocarbons. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters and if we are unable to find solutions to environmental initiatives as they arise, including reducing the greenhouse gas emissions for our existing projects, we may have additional costs as well as compliance and operational risks with respect to our existing operations as well as facing difficulties in pursuing new projects.
Although our estimated natural gas and oil reserve data is independently audited, our estimates are only estimates and thus may prove to be inaccurate.
As described in more detail under “Critical Accounting Policies and Estimates - Natural Gas and Oil Properties” in Item 7 of Part II of this Annual Report, our reserve data represents the estimates of our reservoir engineers made under the supervision of our management, and our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm. Natural gas and oil reserves cannot be measured exactly, however, and our estimates of natural gas and oil reserves requires extensive judgments of reservoir engineering data and projections of cost that will be incurred in developing and producing reserves, along with pricing. Recovery of undeveloped reserves generally requires significant capital investments and successful drilling operations. Actual reserves, costs and prices may differ dramatically from our estimates.
Our operations can be impacted by events beyond our control, adversely affecting our cash flows 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, earthquakes, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes or voluntarily curtailment in response to market conditions. Further, although we operate most of the wells in which we have interests, some are operated by third parties. Although we endeavor to assure that third parties conduct their activities with rigorous regard for health, safety, environment and cost, we do not control them and therefore cannot be sure they will operate to the same standards that we would. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows and results of operations. Counterparties to contracts, whether those providing us with goods or services or those owing us payments for production or services, may breach their obligations.
We may have difficulty financing our planned capital investments, which could adversely affect our growth.
We have experienced and expect to continue to experience substantial capital investment and working capital needs to implement our drilling program. Our planned capital investments for 2015 are expected to exceed the net cash generated by our operations under current natural gas prices. We expect to be able to borrow under our revolving credit facility to fund capital investments to the extent they exceed our net cash flow and cash on hand. Our ability to borrow under our revolving credit facility is subject to certain conditions. As of December 31, 2014, we would satisfy those conditions; however, if conditions were not satisfied and we were not otherwise able to borrow funds, we would need to curtail our drilling, development and other activities or be forced to sell some of our assets on a possibly unfavorable basis. Any such curtailment or sale could have a material adverse effect on our results and future operations.
We have made significant investments in pipelines and gathering systems and contracts and in oilfield service businesses, including our drilling rig, pressure pumping equipment and sand mine operations, to lower costs and secure inputs for our operations and transportation for our production. If our exploration and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations. In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers.
Through December 31, 2014, we had invested approximately $1,184 million in our gas gathering system built for the Fayetteville Shale and approximately $247 million in our gas gathering system built for our operations in Northeast Appalachia. To the extent necessary to gather our production, we may make further substantial investments in the expansion of our gas gathering systems. We have also entered into multiple firm transportation agreements relating to natural gas volumes produced from the Fayetteville Shale as well as a number of firm transportation and gathering agreements relating to the Marcellus Shale. As of December 31, 2014, our aggregate demand charge commitments under these firm transportation agreements and gathering agreements were approximately $5.4 billion. Our gas gathering business will largely rely on natural gas sourced from our operations. If our Fayetteville Shale and Northeast Appalachia programs fail to produce significant quantities of natural gas within expected timeframes, our investments in our gas gathering operations could be lost, and we could be forced to pay demand or other charges for transportation on pipelines and gathering systems that we would not be using.
We also have made significant investments to meet certain of our oilfield services needs, including establishing our own drilling rig operation, sand mine and pressure pumping capability. If our level of operations is reduced, we may not be able to recover these investments. Further, entering into these service and supply sectors, including competing with them for qualified personnel and supplies, may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.
Our drilling plans are subject to change.
As of December 31, 2014, we had drilled and completed 3,742 operated wells relating to our Fayetteville Shale play and 277 operated wells relating to Northeast Appalachia. At year-end 2014, after the exclusion of our acreage in the traditional Fairway and the approximately 158,000 net federal acres we hold in the Ozark Highlands Unit, approximately 85% of our leasehold acreage in the Fayetteville Shale was held by production. Approximately 23% and 54% of our leasehold acreage in Northeast Appalachia and Southwest Appalachia was held by production at year-end 2014, respectively. Our drilling plans are flexible and are dependent upon a number of factors, including the extent to which we can replicate the results of our most successful wells in addition to the natural gas and oil commodity price environment. The determination as to whether we continue to drill wells in our operating areas may depend on any one or more of the following factors:
·
our ability to determine the most effective and economic fracture stimulation;
·
our ability to transport our production to the most favorable markets;
·
material changes in natural gas prices (including regional basis differentials);
·
changes in the costs to drill, complete or operate wells and our ability to reduce drilling risks;
·
the extent of our success in drilling and completing horizontal wells;
·
the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment services
·
success or failure of wells drilled in similar formations of which would use the same production facilities;
·
receipt of additional seismic or other geologic data or reprocessing of existing data;
·
the extent to which we are able to effectively operate our own drilling rigs;
·
availability and cost of capital; or
·
the impact of federal, state and local government regulation, including any increase in severance taxes.
We continue to gather data about our prospects in our operating areas, and it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all.
If we fail to drill all of the wells that are necessary to hold our acreage, the lease terms could expire, which would result in the loss of certain leasehold rights.
Leases on approximately 175,220 (including 158,231 net acres held on federal lands which are currently suspended by the Bureau of Land Management) net acres of our Fayetteville Shale acreage will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases. Approximately 133,624 and 131,782 net acres of our Northeast Appalachia and Southwest Appalachia acreage, respectively, will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases. As discussed above under “Our drilling plans are subject to change,” our ability to drill wells depends on a number of factors, including certain factors that are beyond our control. With the exception of the Ozark Highlands Unit, which is leased from the Federal Government, the current rules in Arkansas relating to the Fayetteville Shale provide that each drilling unit would consist of a governmental section of approximately 640 acres and operators are permitted to drill up to 16 wells per drilling unit for each unconventional source of supply. In Pennsylvania, the location of our Northeast Appalachia acreage, there are currently no rules establishing requirements for drilling units. In West Virginia, where the bulk of our Southwest Appalachia acreage is located, there is no procedure to compel holders of neighboring interests to join into units. Current rules in these states may change in ways that could impair our ability to drill or maintain our acreage position. In addition, other E&P operator drilling activity could impair our ability to drill and maintain acreage positions. To the extent that any field rules prevent us from successfully drilling wells in certain areas, we may not be able to drill the wells required to maintain our leasehold rights and our leasehold investments could be lost.
We depend upon our management team and our operations require us to attract and retain experienced technical personnel.
The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy depends, in part, on our experienced management team, as well as certain key geoscientists, geologists, engineers and other professionals employed by us. The success of our technological initiatives that support our business enterprise is also dependent upon attracting and retaining experienced technical professionals. The loss of key members of our management team or other highly qualified technical professionals could have a material adverse effect on our business, financial condition and operating results.
Certain U.S. 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.
The elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration and production companies has been proposed in recent years. These changes have included, among other proposals:
·
Repeal of the percentage depletion allowance for oil and natural gas properties
·
Elimination of current deductions for intangible drilling and development costs
·
Elimination of the deduction for certain domestic production activities
·
Extension of the amortization period for certain geological and geophysical expenditures
It is unclear whether these or similar changes will be enacted. The passage of these or any similar changes in federal income tax laws to eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development could have an adverse effect on our financial position, results of operations and cash flows.
Cyber attacks or terrorist attacks could affect our assets, cash flows and results of operations.
Cyber attacks on businesses are occurring with greater frequency, and natural gas and oil infrastructure and systems could become targets of terrorists. We rely on electronic systems and networks to control and manage our exploration and production, pipeline and marketing operations and have multiple layers of security to mitigate risks of cyber attack. We also have security in place around our physical operations. If we nonetheless were to experience an attack and our security measures failed, the potential consequences to our businesses and the communities in which they operate could be significant.
Our Canadian exploration and production activities are subject to different risks and uncertainties, different from or in addition to those we face in our U.S. operations.
In addition to the various risks associated with our U.S. operations, we are subject to risks and uncertainties related to our Canadian exploration and production activities, including risks related to increases in taxes and governmental royalties, changes in laws and policies governing operations of foreign-based companies, restrictions on imports and exports, expropriation of property, cancellation of contract rights, environmental protection controls, environmental compliance requirements and laws pertaining to workers’ health and safety. Consequently, our exploration, development and production activities in Canada could be substantially affected by factors beyond our control. In addition, the rights of aboriginal peoples, called First Nations in Canada, are not clear. Our operations in New Brunswick have been subject to local protests, causing several temporary interruptions to our exploration activities. In addition, the newly elected provincial government in New Brunswick recently announced an intent to impose a moratorium on hydraulic fracturing until a list of conditions is met and has introduced authorizing legislation in the provincial legislature. We have applied for an extension of our licenses past the end of the moratorium, but as of this time that extension has not been granted. The list of conditions that the provincial government has announced is subjective, and we cannot predict the duration of the moratorium or whether we will be granted the extension requested or any other extension. Unless and until the moratorium is lifted and our licenses are extended, we will not be able to continue with our program in New Brunswick.
Because we have no plans to pay dividends on our common stock, investors in our common stock must look solely to stock appreciation for a return on their investment in us.
We do not currently pay cash dividends on our common stock, and we do not anticipate paying cash dividends in the foreseeable future. We currently intend to retain all future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying cash dividends on our common stock in the foreseeable future. Payment of any future dividends on our common stock will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansions. Any future dividends on our common stock may also be restricted by any loan agreements which we may enter into from time to time and from the future issuances of preferred stock. However, until the depositary shares representing the 1/20th interest in our 6.25% Series B Mandatory Preferred Stock convert to common stock, we will pay quarterly dividends to the holders of such depositary shares.
Anti-takeover provisions in our organizational documents and under Delaware law may impede or discourage a takeover, which could cause the market price of our common stock to decline.
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders, which, under certain circumstances, could reduce the market price of our common stock. In addition, protective provisions in our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws or the implementation by our board of directors of a stockholder rights plan could prevent a takeover, which could harm our stockholders.
Our current and future levels of indebtedness and the terms of our financing arrangements may adversely affect our results and limit our growth.
At December 31, 2014, we had long-term indebtedness of $2.5 billion, including borrowings of $300 million under our revolving credit facility and $500 million under our Term Loan Facility. Also at December 31, 2014, we had short-term indebtedness of $4.5 billion relating to our bridge facility which was repaid in full in January 2015 in part through the issuance of $2.2 billion of additional long-term senior notes. See Note 16 - Subsequent Events within Item 8 of this Annual Report for further details on indebtedness incurred subsequent to December 31, 2014.
The terms of the indentures relating to our outstanding senior notes, our credit facilities, and the master lease agreements relating to our drilling rigs and other equipment, which we collectively refer to as our “financing agreements,” impose restrictions on our ability and, in some cases, the ability of our subsidiaries to take a number of actions that we may otherwise desire to take, which may include, without limitation, one or more of the following:
·
incurring additional debt;
·
redeeming stock or redeeming debt;
·
making investments;
·
creating liens on our assets; and
·
selling assets.
Although the indenture governing the notes contains covenants that apply to us, covenants limiting liens and sale and leasebacks covenants contain exceptions and limitations that would allow us, pursuant to the terms of the indenture, to create, grant or incur certain liens or security interests. Moreover, the indenture does not contain any limitations on the ability of us or our subsidiaries to incur debt, pay dividends, make investments, or limit the ability of our subsidiaries to make distributions to us. Such activities may, however, be limited by our other financing agreements in certain circumstances.
Our level of indebtedness and off-balance sheet obligations, and the covenants contained in our financing agreements, could have important consequences for our operations, including:
·
requiring us to dedicate a substantial portion of our cash flow from operations to required payments, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
·
limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;
·
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
·
detracting from our ability to successfully withstand a downturn in our business or the economy generally.
Our ability to comply with the covenants and other restrictions in our financing agreements may be affected by events beyond our control, including prevailing economic and financial conditions.
If we fail to comply with the covenants and other restrictions, it could lead to an event of default and the acceleration of our obligations under the notes or our other financing agreements, and in the case of the lease agreements for drilling rigs, loss of use of our drilling rigs. In particular, a significant or extended decline in natural gas or oil prices would have a material adverse effect on our results of operations, our access to capital and the quantities of natural gas and oil that we can produce economically. For example, the New York Mercantile Exchange, or NYMEX, natural gas prices traded at a high of $5.56 in February 2014 and a low of $3.73 in November 2014 based on last-day-of-month settlement. We may not have sufficient funds to make such payments. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure
you that we will be able to generate sufficient cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations. The terms of our financing agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure you that any such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.
A downgrade in our credit rating could negatively impact our cost of and ability to access capital.
Actual or anticipated changes or downgrades in our credit ratings, including any announcement that our ratings are under further review for a downgrade, could affect the market value of our senior notes and increase our corporate borrowing costs. Such ratings are limited in scope, and do not address all material risks relating to us, but rather reflect only the view of each rating agency at the time the rating is issued. An explanation of the significance of such rating may be obtained from such rating agency. Although we are currently rated “investment grade,” there can be no assurance that such credit ratings will remain in effect for any given period of time or that such ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant.
We may be subject to risks in connection with acquisitions, including the Acquisitions, and the integration of significant acquisitions may be difficult.
We have consummated several acquisitions and we periodically evaluate other potential acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of properties, including the Acquisitions, requires an assessment of several factors, including:
·
recoverable reserves;
·
future oil and natural gas prices and their appropriate differentials;
·
availability and cost of transportation of production to markets;
·
availability and cost of drilling equipment and of skilled personnel;
·
development and operating costs and potential environments and other liabilities;
·
regulatory, permitting and similar matters; and
·
our ability to obtain external financing to fund the purchase price.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities associated with the assets to be acquired, we are entitled to indemnification for only certain environmental liabilities. In addition, we waived or did not include certain environmental and title indemnification in our acquisitions in Southwest Appalachia in exchange for downward adjustments to the purchase prices.
Significant acquisitions, including the Acquisitions, and other strategic transactions may involve other risks, including:
·
diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
·
the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
·
difficulty associated with coordinating geographically separate assets;
·
the challenge of attracting and retaining personnel associated with acquired operations; and
·
the failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

ITEM 1B - UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.

ITEM 2 - PROPERTIES
ITEM 2. PROPERTIES
The summary of our oil and natural gas reserves as of fiscal year-end 2014 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2014 Proved Reserves by Category and Summary Operating Data” in “Business - Exploration and Production - Our Proved Reserves” in Item 1 of this Annual Report and incorporated by reference into this Item 2. Our proved reserves are based upon estimates prepared for each of our properties annually by the reservoir engineers assigned to the asset management team in the geographic locations in which the property is located. These estimates are reviewed by senior engineers who are not part of the asset management teams and by our Reservoir Supervisor - Reserves, who is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Reservoir Supervisor - Reserves has more than 28 years of experience in petroleum engineering, including the estimation of oil and natural gas reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining us in 2009, our Reservoir Supervisor - Reserves served in various reservoir engineering roles for Citation Oil & Gas Corporation, Mitchell Energy and Development Corporation, Whites Stone Energy and H.J. Gruy & Associates and is a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers and is a Licensed Professional Engineer in the state of Texas. He reports to our Vice President and General Manager - Strategy, Performance and Innovation who has more than 28 years of experience in reservoir engineering including the estimation of oil and natural gas reserves in multiple basins in the United States. Prior to joining Southwestern in 1993, our Vice President and General Manager - Strategy, Performance and Innovation served in various engineering roles for Conoco Inc. and is a member of the Society of Petroleum Engineers, Society of Petroleum Evaluation Engineers, American Institute of Professional Geologists, IPAA and TIPRO. He is also a Licensed Professional Engineer in the state of Texas. On our behalf, the Vice President and General Manager - Strategy, Performance and Innovation engages NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves estimates (1) have over 32 years and over 12 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 22 years and over 12 years of experience in the estimation and evaluation of reserves, respectively; (3) each has a college degree; (4) each is a Licensed Professional Geoscientist in the State of Texas or a Licensed Professional Engineer in the State of Texas; (5) each meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and (6) each is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates is also separately reviewed by our accounting staff. Our proved reserves estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our Chief Executive Officer. Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors with whom final authority over the estimates of our proved reserves rests. A copy of NSAI's report has been filed as Exhibit 99.1 to this Annual Report.
The information regarding our proved undeveloped reserves required by Item 1203 of Regulation S-K is included under the heading “Proved Undeveloped Reserves” in “Business - Exploration and Production - Our Proved Reserves” in Item 1 of this Annual Report.
The information regarding delivery commitments required by Item 1207 of Regulation S-K is included under the heading “Sales, Delivery Commitments and Customers” in the “Business - Exploration and Production - Our Operations” in Item 1 of this Annual Report and incorporated by reference into this Item 2. For additional information about our natural gas and oil operations, we refer you to Note 4 to the consolidated financial statements. For information concerning capital investments, we refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Investments.” We also refer you to Item 6, “Selected Financial Data” in Part II of this Annual Report for information concerning natural gas and oil produced.
The information regarding oil and gas properties, wells, operations and acreage required by Item 1208 of Regulation S-K is set forth below. Figures as of December 31, 2014 exclude assets acquired in 2015, such as those in the Appalachian Basin.
Leasehold acreage as of December 31, 2014:
(1)
Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 15,289 net acres in 2015, 921 net acres in 2016 and 779 net acres in 2017 (excluding 158,231 net acres held on federal lands which are currently suspended by the Bureau of Land Management).
(2)
Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 35,215 net acres in 2015, 28,912 net acres in 2016 and 69,497 net acres in 2017.
(3)
Assuming successful wells are not drilled to develop the acreage and leases are not extended leasehold expiring over the next three years will be 46,342 net acres in 2015, 41,184 net acres in 2016 and 44,256 net acres in 2017. Of this acreage, 16,876 net acres in 2015, 17,798 net acres in 2016 and 15,691 net acres in 2017 can be extended for an average of an additional 4.6 years.
(4)
Includes 123,442 net developed acres and 432 net undeveloped acres in the Arkoma Basin that are also within our Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above. Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 15,332 net acres in 2015, 5,533 net acres in 2016 and 986 net acres in 2017.
(5)
Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 64 net acres in 2015, zero net acres in 2016 and zero net acres in 2017.
(6)
Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 153,866 net acres in 2015, 60,078 net acres in 2016 and 17,057 net acres in 2017.
(7)
Assuming successful wells are not drilled to develop the acreage and our exploration license agreements are not extended, leasehold expiring over the next three years will be 107,963 net acres in 2015, 85,977 net acres in 2016, and 34,970 net acres in 2017.
(8)
Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 143,109 net acres in 2015, 253,728 net acres in 2016 and 72,709 net acres in 2017.
(9)
Assuming successful wells are not drilled to develop the acreage and our exploration license agreements are not extended, leasehold expiring over the next years will be 2,518,518 net acres in 2015, 48,960 net acres in 2016, and 148,480 net acres in 2017.
Producing wells as of December 31, 2014:
(1)
Includes 226 gross natural gas wells in which we own an overriding royalty interest.
(2)
Includes 140 gross natural gas wells in which we own an overriding royalty interest.
(3)
Includes 1 gross oil well and 11 gross natural gas wells in which we own an overriding royalty interest.
The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation S-K is set forth below:
(1)
We have not drilled any exploratory or development wells in Canada in the past three years.
(2)
2013 dry wells include 2 gross wells in the Fayetteville Shale that were plugged and abandoned after being spud due to changes in the development plans.
(3)
2012 dry wells include 5 gross wells that were used for science in the Ozark Highlands Unit that were not intended to produce.
The following table presents the information regarding our present activities required by Item 1206 of Regulation S-K:
Wells in progress as of December 31, 2014: (1,2)
(1)
As of December 31, 2014, we did not have any drilling activities in Canada.
(2)
Includes 42 wells in progress acquired in the Chesapeake Property Acquisition.
The information regarding oil and gas production, production prices and production costs required by Item 1204 of Regulation S-K is set forth below:
Production, Average Sales Price and Average Production Cost:
(1)
Our Fayetteville Shale and Northeast Appalachia operations did not produce any oil for the years ended December 31, 2014, 2013 and 2012.
During 2014, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas Reserves,” with the U.S. Department of Energy. The basis for reporting reserves on Form 23 is not comparable to the reserve data included in Note 4 to the consolidated financial statements in Item 8 to this Annual Report. The primary differences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we are the operator.
Miles of Pipe
As of December 31, 2014, our Midstream Services segment had 2,017 miles, 105 miles, 25 miles and 16 miles of pipe in its gathering systems located in Arkansas, Pennsylvania, Texas and Louisiana, respectively.
Title to Properties
We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other
burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we endeavor to perform a title investigation that is thorough but less vigorous than that we endeavor to conduct prior to drilling, which is consistent with standard practice in the oil and natural gas industry. Generally, before we commence drilling operations on properties that we operate, we conduct a title examination and perform curative work with respect to significant defects that we identify. We believe that we have performed title examination with respect to substantially all of our active properties that we operate.

ITEM 3 - LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
We are subject to laws and regulations relating to the protection of the environment. Our policy is to accrue environmental and cleanup related costs of a non-capital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position, results of operations, and cash flows.
Tovah Energy
In February 2009, one of our subsidiaries was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et al., pending in the 273rd District Court in Shelby County, Texas. By the time of trial in December 2010, Ms. Berry-Helfand (the only remaining plaintiff) alleged that, in 2005, she provided our subsidiary with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that our subsidiary refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom. Among other things, she alleged various statutory and common law claims, including, but not limited to, claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by our subsidiary between February 2005 and February 2006. She also sought disgorgement of our subsidiary’s profits. A former associate of the plaintiff intervened in the matter claiming to have helped develop the prospect years earlier.
The jury found in favor of the plaintiff and the intervenor with respect to all of the statutory and common law claims and awarded $11 million in compensatory damages but no special, punitive or other damages. Separately, the jury determined that our subsidiary’s profits for purposes of disgorgement, if ordered as a remedy, were $382 million. (Disgorgement of profits is an equitable remedy determined by the judge, and it is within the judge’s discretion to award none, some or all of unlawfully obtained profits.) In August 2011, a judgment was entered pursuant to which the plaintiff and the intervenor were entitled to recover approximately $11 million in actual damages and approximately $24 million in disgorgement as well as prejudgment interest and attorneys’ fees, which currently are estimated to be up to $9 million, and all costs of court of the plaintiff and intervenor.
Both sides appealed and in July 2013, the Tyler Court of Appeals ordered that (1) the judgment awarding the plaintiff and the intervenor $24 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11 million for actual damages, insofar as it is based on the jury’s findings of breach of fiduciary duty, fraud, breach of contract, and theft of trade secret is reversed and judgment rendered that the plaintiff and the intervenor take nothing under those theories of recovery, (3) the award of $11 million to the plaintiff and the intervenor as damages for misappropriation of trade secret is affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for our subsidiary as the prevailing party under the Texas Theft Liability Act, and (5) in all other respects, the judgment is affirmed. All parties petitioned for rehearing. The Tyler Court of Appeals denied rehearing in November 2013.
Our subsidiary filed a petition for review in the Supreme Court of Texas in February 2014. The plaintiff and the intervenor filed cross-petition for review in April 2014, but conditioned their filing on the court’s granting our subsidiary’s petition for review; i.e., if the court denies our subsidiary’s petition for review, then the plaintiff and the intervenor are not seeking further review of the court of appeals’ judgment. On October 24, 2014, the Supreme Court requested full briefing on the merits of the case. Based on our understanding and judgment of the facts and merits of this case, including appellate matters, and after considering the advice of counsel, we have determined that, although reasonably possible, a materially adverse final outcome to this action is not probable. As such, we have not accrued any amounts with respect to this action. If the Supreme Court declines to rule on the case or affirms all aspects of the court of appeals’ judgment, then our subsidiary would owe the $11 million in damages, plus interest and attorneys’ fees, offset by any award of attorneys’ fees for its prevailing on the theft count. Our assessment may change in the future due to occurrence of certain events, such as the result of the petitions for review at the Supreme Court of Texas, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the our results of operations, financial position or cash flows.
Arkansas Royalty Litigation
Certain of our subsidiaries are defendants in two cases filed in Arkansas state court in 2010 and 2013, and we and certain subsidiaries are defendants in a case filed in federal court in 2014, in each instance brought on behalf of putative classes of royalty owners on some of our leases located in Arkansas. The chief complaint in all three cases is that one of our subsidiaries underpaid the royalty owners by, among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in excess of what is permitted by the relevant leases. Our subsidiaries removed the two cases filed in state court to federal court, but both were remanded to state court during the third quarter of 2014. In September and October 2014 the judges in the two Arkansas state actions entered orders certifying classes of royalty owners who are citizens of Arkansas. Our subsidiaries are appealing those orders. Discovery regarding the plaintiffs’ theories of liability and amount of claimed damages is in the very early stages. Management believes that the deductions from royalty payments as calculated are permitted and intends to defend the cases vigorously. Our assessment may change in the future due to the occurrence of certain events, such as adverse judgments, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to our results of operations, financial position or cash flows.
Other
We are subject to various litigation, claims and proceedings that have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.

ITEM 4 - RESERVED
ITEM 4. MINE SAFETY DISCLOSURES
Our sand mining operations in support of our E&P business are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report.
PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange (the “NYSE”) under the symbol “SWN.” On February 24, 2015, the closing price of our common stock trading under the symbol “SWN” was $27.74 and we had 3,277 stockholders of record, respectively. The following table presents the high and low sales prices for closing market transactions for our common stock trading under the symbol “SWN” as reported on the NYSE.
We do not currently pay quarterly cash dividends on our common stock.
Issuer Purchases of Equity Securities
The table below sets forth information with respect to purchases of our common stock made by us or on our behalf during the quarter ended December 31, 2014:
(1)
Reflects shares retired by us to satisfy applicable tax withholding obligations due on employee stock plan share issuances. All changes in common stock in treasury in 2014 were due to purchases and sales of shares held on behalf of participants in a non-qualified deferred compensation supplemental retirement savings plan.
Recent Sales of Unregistered Equity Securities
We did not sell any unregistered equity securities during 2014, 2013 or 2012.
STOCK PERFORMANCE GRAPH
The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index. The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2009, and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance. This year we are changing the index we will be using to show our performance relative to peers. In the past we have used the Dow Jones Oil & Gas Exploration & Production Index. As now configured, that index includes refining and fully integrated companies as well as companies that, like ours, are largely focused on exploration and production. Going forward, we will be using the same group of peer companies that we use in determining our annual incentive awards, which are all predominately E&P companies. This graph includes both the Dow Jones Index and the peer group, as well as the S&P 500 Index, which we will continue to use. The peer group includes Cabot Oil & Gas Corp, Cimarex Energy Co, Concho Resources Inc, Continental Resources Inc, Denbury Resources Inc, Devon Energy Corp, EOG Resources Inc, Newfield Exploration Co, Noble Energy Inc, Pioneer Natural Resources Co, Range Resources Corp, Sandridge Energy Inc, SM Energy Co, and Ultra Petroleum Corp.

ITEM 6 - SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2014. This information and the notes thereto are derived from our consolidated financial statements. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data.”
(1)
Capital investments include an increase of $155 million for 2014, decreases of $25 million and $37 million for 2013 and 2012, respectively, and increases of $4 million and $14 million for 2011 and 2010, respectively, related to the change in accrued expenditures between years.

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This Annual Report contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in the “Cautionary Statement About Forward-Looking Statements” below, in Item 1A - “Risk Factors” in Part I and elsewhere in this Annual Report. You should read the following discussion with Item 6 - Selected Financial Data and our consolidated financial statements and related notes included in this Annual Report.
OVERVIEW
Background
Southwestern Energy Company is an independent energy company engaged in natural gas and oil exploration, development and production, or E&P. We also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services. We operate principally in two segments: E&P and Midstream Services.
Our primary business is the exploration for and production of natural gas and oil, with our current operations principally focused within the United States on development of two unconventional natural gas reservoirs located in Arkansas and Pennsylvania. Our operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale, and our operations in northeast Pennsylvania are focused on an unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”). Recently, we acquired a significant stake in properties located in West Virginia and southwest Pennsylvania which we also intend to develop. These operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”). Collectively, our properties located in West Virginia and Pennsylvania are herein referred to as the “Appalachian Basin.” To a lesser extent, we have exploration and production activities ongoing in Colorado, Louisiana, Texas and in the Arkoma Basin in Arkansas and Oklahoma. We also actively seek to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which we refer to as “New Ventures,” and through acquisitions. We also operate drilling rigs in Arkansas and Pennsylvania, as well as in other operating areas, and provide oilfield products and services, principally serving our exploration and production operations.
We are focused on providing long-term growth in the net asset value per share of our business. We derive the vast majority of our operating income and cash flow from the production associated with our E&P business and expect this to continue in the future. We expect that growth in our operating income and revenues will depend primarily on natural gas and oil prices and our ability to increase our production. We expect our production volumes will continue to increase due to ongoing development in our Fayetteville Shale, Northeast Appalachia and Southwest Appalachia divisions. The price we expect to receive for our production is a critical factor in the capital investments we make in order to develop our properties. In recent years, there has been significant volatility in natural gas prices as evidenced by New York Mercantile Exchange, or NYMEX, natural gas prices ranging from a high of $13.58 per MMBtu in 2008 to a low of $1.91 per MMBtu in 2012. Natural gas prices fluctuate due to a variety of factors we cannot control or predict. These factors, which include increased supplies of natural gas due to greater exploration and development activities, weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which in turn determines the sale prices for our production. Going forward, we will be impacted by crude oil prices which have ranged from approximately $145 per barrel in July 2008 to approximately $45 per barrel in January 2015. In addition to the factors identified above, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices.
Recent Financial and Operating Results
In 2014, our net income was $924 million, or $2.62 per diluted share, up from net income of $704 million, or $2.00 per diluted share in 2013. Our net loss was $707 million, or $2.03 per diluted share in 2012. In 2012, we incurred a $1,940 million, or $1,192 million net of taxes, non-cash ceiling test impairment of our United States natural gas and oil properties that resulted from a significant decline in natural gas prices during 2012.
In 2014, our natural gas and oil production increased 17% to 768 Bcfe, up from 657 Bcfe in 2013. The 111 Bcfe increase in our 2014 production resulted from a 103 Bcf increase in net production from our Northeast Appalachia properties and an 8 Bcf increase in net production from our Fayetteville Shale properties. In 2013, our natural gas and oil production increased to 657 Bcfe, up from 565 Bcfe in 2012. We are targeting 2015 natural gas and oil production of 940 to 955 Bcfe, an increase of approximately 23% over our 2014 production, using midpoints. Our year-end reserves
increased 54% in 2014 to 10,747 Bcfe, up from 6,976 Bcfe at the end of 2013 and 4,018 Bcfe at the end of 2012. The overall increase in total estimated proved reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia which increased reserves by 33%, our successful drilling programs in the Fayetteville Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia where reserves grew 63% from 2013. The overall increase in total estimated proved reserves in 2013 was primarily due to significant additions in our Fayetteville Shale reserves including substantial additions of proved undeveloped reserves primarily driven by an increase in average natural gas prices in 2013 and a 141% growth rate in our reserves in Northeast Appalachia.
Our E&P segment operating income was $1,013 million in 2014, up from an operating income of $879 million in 2013. Operating income in 2014 increased $134 million over 2013 as the revenue impact of our 17%, or 111 Bcfe, increase in production and 2%, or $0.07, increase in our average realized natural gas price more than offset the $324 million increase in operating costs and expenses that resulted from our production growth. Operating income was $879 million in 2013, up from an operating loss of $1,396 million in 2012. The operating loss in 2012 included a $1,940 million non-cash ceiling test impairment of our United States natural gas and oil properties. Excluding the non-cash ceiling test impairment, operating income in 2013 increased $335 million over 2012 as the revenue impact of our 16%, or 92 Bcfe, increase in production and 6%, or $0.21, increase in our average realized natural gas price more than offset the $105 million increase in operating costs that resulted from our production growth.
Operating income for our Midstream Services segment was $361 million in 2014, up from $325 million in 2013 and $294 million in 2012. Operating income for our Midstream Services segment increased in 2014 due to an increase of $46 million in gathering revenues and a $12 million increase in the margin generated from our natural gas marketing activities, which was partially offset by a $22 million increase in operating costs and expenses, exclusive of natural gas purchase costs, that resulted from our continued growth in volumes gathered. Volumes gathered grew to 963 Bcf in 2014 compared to 900 Bcf in 2013. Operating income for our Midstream Services segment increased in 2013 due to an increase of $42 million in gathering revenues and a $17 million increase in the margin generated from our natural gas marketing activities which was partially offset by an increase of $28 million in operating costs and expenses, exclusive of natural gas purchase costs, that resulted from our growth in volumes gathered. Volumes gathered grew to 900 Bcf in 2013 compared to 846 Bcf in 2012.
We had total capital investments of $7.4 billion in 2014, compared to $2.2 billion in 2013 and $2.1 billion in 2012. Of our total capital investments, $7.3 billion was invested in our E&P segment in 2014 which included $5.2 billion primarily related to the Chesapeake Property Acquisition compared to $2.1 billion in 2013 which included $96 million primarily related to the acquisition of properties in Northeast Appalachia and $1.9 billion in 2012.
Outlook
We believe the outlook for our business is favorable despite the continued uncertainty of natural gas and crude oil prices in the United States and the legislative and regulatory challenges facing our industry. Our resource base, financial strength and disciplined investment of capital provide us with an opportunity to exploit and develop our position through our Fayetteville Shale, Northeast Appalachia and Southwest Appalachia divisions to maximize efficiency through economies of scale in our key operating areas, enhance our overall returns through our Midstream Services operations and grow through our E&P development activities. Our capital investment plan for 2015 is flexible and may be adjusted based on actual and expected natural gas and oil prices.
RESULTS OF OPERATIONS
The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense and income tax expense are discussed on a consolidated basis.
Exploration and Production
(1)Represents the gain (loss) on derivatives, settled, associated with derivatives not designated for hedge accounting.
(2)Including the gain (loss) on derivatives excluding derivatives, settled effects of commodity hedging contracts not designated for hedge accounting, results in an average price of $3.90, $3.68 and $3.43 for the year ended December 31, 2014, 2013 and 2012, respectively.
Revenues
Revenues for our E&P segment were up $458 million, or 19%, in 2014 compared to 2013. Higher natural gas production volumes in 2014 increased revenues by $403 million, and higher realized prices for our natural gas production increased revenue by $55 million compared to 2013. E&P revenues were up $440 million, or 22%, in 2013 compared to 2012. Higher natural gas production volumes in 2013 increased revenues by $316 million, higher realized prices for our natural gas production increased revenue by $118 million, and higher oil production volumes in 2013 increased revenues by $6 million compared to 2012. We expect our natural gas production volumes to continue to increase due to the development of our Northeast and Southwest Appalachia properties. Natural gas and oil prices are difficult to predict and are subject to wide price fluctuations. As of February 24, 2015, we had hedged 240 Bcf of our remaining 2015 natural gas production to help limit our exposure to price fluctuations. For more information about our derivatives and risk management activities, we refer you to Note 5 to the consolidated financial statements included in this Annual Report and to “Commodity Prices” below for additional information.
Production
In 2014, our natural gas and oil production increased 17% to 768 Bcfe, up from 657 Bcfe in 2013. The 111 Bcfe increase in our 2014 production resulted from a 103 Bcf increase in net production from our Northeast Appalachia properties, and an 8 Bcf increase in net production from our Fayetteville Shale properties. In 2013, our natural gas and oil production increased to 657 Bcfe, up from 565 Bcfe in 2012. The 92 Bcfe increase in our 2013 production resulted from a 97 Bcf increase in net production from our Northeast Appalachia properties and a 2 Bcfe increase in net production in our New Ventures and Fayetteville Shale properties, which more than offset a combined 7 Bcfe decrease in net production from our East Texas and Arkoma Basin properties. Our net production from the Fayetteville Shale was 494 Bcf in 2014, up from 486 Bcf in 2013 and 2012. Our net production from Northeast Appalachia was 254 Bcf in 2014, up from 151 Bcf in 2013 and 54 Bcf in 2012.
We are targeting 2015 natural gas and oil production of 940 to 955 Bcfe, an increase of approximately 23% over our 2014 production, using midpoints. Approximately 448 to 453 Bcf of our 2015 targeted natural gas production is projected to come from our activities in the Fayetteville Shale, 356 to 361 Bcf is projected to come from our activities in Northeast Appalachia and 136 to 141 Bcfe is projected to come from our activities in Southwest Appalachia. Although we expect production volumes in 2015 to increase, we cannot guarantee our success in discovering, developing and producing our total reserves. Our ability to discover, develop and produce reserves is dependent upon a number of factors, many of which are beyond our control, including the availability of capital, availability of transportation, weather, the timing and extent of changes in natural gas and oil prices and competition. There are also many risks inherent in the discovery, development and production of natural gas and oil. We refer you to “Risk Factors” in Item 1A of Part I of this Annual Report for a discussion of these risks and the impact they could have on our financial condition and results of operations.
Commodity Prices
The average price realized for our natural gas production, including the effects of hedges, increased 2% to $3.72 per Mcf in 2014 and increased 6% to $3.65 per Mcf in 2013. The increase in the average price realized in 2014 compared to 2013 and the increase in 2013 compared to 2012 primarily reflects the increase in average market prices and to a lesser extent the decreased effect of our natural gas price hedging activities. We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to

ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as credit risk concentrations. We use natural gas fixed price swap agreements, fixed price options, basis swaps and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of interest rate risks is subject to the approval of our Board of Directors. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.
Credit Risk
Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our purchasers and their dispersion across geographic areas. No single purchaser accounted for greater than 10% of revenues as of December 31, 2014. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.
Interest Rate Risk
The following table presents the principal cash payments for our debt obligations and related weighted-average interest rates by expected maturity dates as of December 31, 2014. As of December 31, 2014, we had $1,667 million of outstanding senior notes with a weighted average interest rate of 5.45%, $4.5 billion of short-term debt with a weighted average interest rate of 1.52%, $500 million of term loan facility debt with a weighted average interest rate of 1.55%, and $300 million of borrowings under our revolving credit facility with a weighted average interest rate of 1.52%. We currently have an interest rate swap in effect to mitigate our exposure to volatility in interest rates.
Commodities Risk
We use over-the-counter natural gas and oil fixed price swap agreements and fixed price options to hedge sales of our production against the inherent risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps) and (3) the purchase and sale of index-related puts and calls (collars) that provide a “floor” price, below which the counterparty pays funds equal to the amount by which the price of the commodity is below the contracted floor, and a “ceiling” price above which we pay to the counterparty the amount by which the price of the commodity is above the contracted ceiling.
The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas and oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or
purchase of the natural gas that is hedged. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major commercial banks, investment banks and integrated energy companies that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future.
Exploration and Production
The following table provides information about our financial instruments that are sensitive to changes in commodity prices and that are used to hedge prices for natural gas production. The table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturity dates.
As of December 31, 2014, our basis swaps, certain fixed price swaps, fixed price call options, and interest rate swap were not designated for hedge accounting treatment. Changes in the fair value of derivatives that were not designated as cash flow hedges are recorded in gain (loss) on derivatives. For the year ended December 31, 2014, we recorded a gain on derivatives excluding derivatives, settled of $126 million related to fixed price swaps not designated for hedge accounting, a gain on derivatives excluding derivatives, settled of $18 million related to fixed price call options not designated for hedge accounting, a loss on derivatives excluding derivatives, settled of $7 million related to basis swaps not designated for hedge accounting, and a loss on derivatives excluding derivatives, settled of $7 million related to our interest rate swap not designated for hedge accounting.

ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2014, 2013 and 2012
Consolidated Balance Sheets as of December 31, 2014 and 2013
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012
Consolidated Statements of Equity for the fiscal years ended December 31, 2014, 2013 and 2012
Notes to Consolidated Financial Statements, December 31, 2014, 2013 and 2012
Management’s Report on Internal Control Over Financial Reporting
It is the responsibility of the management of Southwestern Energy Company to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, utilizing the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control-Integrated Framework (2013).
Management has excluded the oil and gas assets acquired from a subsidiary of Chesapeake Energy Corporation in West Virginia and southwest Pennsylvania (“Chesapeake Property Acquisition”) from its assessment of internal control over financial reporting as of December 31, 2014 as the Chesapeake Property Acquisition was acquired in a business combination during 2014. The total assets and total revenues of the Chesapeake Property Acquisition represent approximately 33% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014.
Based on this evaluation, management concluded the Company’s internal control over financial reporting was effective as of December 31, 2014.
The effectiveness of our internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Southwestern Energy Company
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Southwestern Energy Company and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process 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. A 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 could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness 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.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded the oil and gas properties acquired from a subsidiary of Chesapeake Energy Corporation in West Virginia and southwest Pennsylvania (“Chesapeake Property Acquisition”) from its assessment of internal control over financial reporting as of December 31, 2014 because it was acquired by the Company in a purchase business combination during 2014. We have also excluded the Chesapeake Property Acquisition from our audit of internal control over financial reporting. The Chesapeake Property Acquisition’s total assets and total revenues represent 33% and 1% respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014.
/s/PRICEWATERHOUSECOOPERS LLP
Houston, TX
February 26, 2015
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
(1)
Net of $10, $(124), and $(249) million in taxes for the years ended December 31, 2014, 2013 and 2012, respectively.
(2)
Net of $0, $1, and $(1) million in taxes for the years ended December 31, 2014, 2013 and 2012, respectively.
(3)
Net of $49, $16, and $85 million in taxes for the years ended December 31, 2014, 2013 and 2012, respectively.
(4)
Net of $(10), $8, and $(5) million in taxes for the years ended December 31, 2014, 2013 and 2012, respectively.
(5)
Net of $0, $1, and $1 million in taxes for the years ended December 31, 2014, 2013, and 2012, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production (“E&P”). Our current operations are principally focused within the United States on development of two unconventional natural gas reservoirs located in Arkansas and Pennsylvania. The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale, and its operations in northeast Pennsylvania are focused on an unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”). Recently, the Company acquired a significant stake in properties located in West Virginia and southwest Pennsylvania which it also intends to develop. These operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”). Collectively, the Company’s properties located in West Virginia and Pennsylvania are herein referred to as the “Appalachian Basin.” To a lesser extent, the Company has exploration and production activities ongoing in Colorado, Louisiana, Texas and in the Arkoma Basin in Arkansas and Oklahoma. The Company also actively seeks to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which it refers to as “New Ventures,” and through acquisitions. The Company also operates drilling rigs in Arkansas and Pennsylvania, as well as in other operating areas, and provide oilfield products and services, principally serving its exploration and production operations. Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Texas, Louisiana, Pennsylvania, and West Virginia.
Basis of Presentation
The consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued. Certain reclassifications have been made to the prior year financial statements to conform to the 2014 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements.
Principles of Consolidation
The consolidated financial statements include the accounts of Southwestern and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
Revenue Recognition
Natural gas and oil sales. Natural gas and oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, natural gas and oil sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and oil sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. The Company had no significant production imbalances at December 31, 2014 or 2013.
Marketing. The Company generally markets its natural gas and oil, as well as some products produced by third parties, to brokers, local distribution companies and end-users, pursuant to a variety of contracts. Marketing revenues are recognized when delivery has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured.
Gas gathering. In certain areas, the Company gathers its natural gas as well as some natural gas produced by third parties pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.
Cash and Cash Equivalents
Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash. Management considers cash and cash equivalents to have minimal credit and market risk.
Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $17 million and $5 million as of December 31, 2014 and 2013, respectively.
Inventory
Inventory is comprised of natural gas in underground storage and tubular and other equipment. Natural gas in underground storage is carried at the lower of cost or market and accounted for by a weighted average cost method. Tubulars and other equipment are carried at the lower of cost or market and are accounted for by a moving weighted average cost method that is applied within specific classes of inventory items.
The components of inventory as of December 31, 2014 and December 31, 2013 consisted of the following:
Property, Depreciation, Depletion and Amortization
Natural Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10% plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Companies utilizing the full cost method must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.
Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.35 per MMBtu, West Texas Intermediate oil of $91.48 per barrel and NGLs of $23.79 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2014. Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $4 million, net of tax, as of December 31, 2014. At December 31, 2013, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.67 per MMBtu, West Texas Intermediate oil of $93.42 per barrel, and NGLs of $43.45 per barrel. At December 31, 2012, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.76 per MMBtu and for West Texas Intermediate oil of $91.21. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments. During 2012, the net capitalized costs of the Company’s natural gas and oil properties exceeded the ceiling by approximately $1,192 million (net of tax) and resulted in a non-cash ceiling test impairment.
All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program as of December 31, 2014 and as of December 31, 2013 were unproved and did not exceed the ceiling amount. If the exploration program in Canada is unsuccessful on all or a portion of these properties, including the
effects of changes in laws or regulations due to the new government in New Brunswick or otherwise or the Company’s exploration licenses in New Brunswick are not renewed in the first quarter of 2015, a ceiling test impairment may result in the future.
Gathering Systems. The Company’s investment in gathering systems is primarily related to its Fayetteville Shale assets in Arkansas and Northeast Appalachia assets in Pennsylvania. These assets are being depreciated on a straight-line basis over 25 years.
Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and actively being evaluated.
Asset Retirement Obligations. The Company owns natural gas and oil properties, which require expenditures to plug and abandon the wells and reclaim the associated pads when reserves in the wells are depleted. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
Impairment of long-lived assets. The carrying values of long-lived assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying Consolidated Statements of Operations. Additional information regarding uncertain tax positions can be found in Note 10 - Income Taxes.
Derivative Financial Instruments
The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity fixed price swaps and fixed price option contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivatives if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item. In contrast, gains and losses from the ineffective portion of fixed price swaps designated for hedge accounting treatment are recognized currently and have an inconsequential impact in the consolidated statement of operations. Gains and losses from the unsettled portion of fixed price swaps not designated for hedge accounting treatment, interest rate swaps, fixed price call options and basis swaps that were not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 5 and Note 7 for a discussion of the Company’s hedging activities.
Earnings Per Share
Basic earnings per common share is computed by dividing net income (loss) attributable to Southwestern by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding the incremental shares that would have been outstanding assuming the exercise of dilutive stock options and the vesting of unvested restricted shares of common stock. Antidilutive is an increase in earnings per share or reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.
For the year ended December 31, 2014, outstanding options for 241,603 shares with an average exercise price of $34.03 were included in the calculation of diluted shares. Options for 1,446,004 shares were excluded from the calculation because they would have had an antidilutive effect. For the year ended December 31, 2013, outstanding options for 377,626 shares with an exercise price of $28.03 were included in the calculation of diluted shares. Options for 1,634,695 shares were excluded from the calculation because they would have had an antidilutive effect. As the Company recognized a net loss for the year ended December 31, 2012, the unvested stock options were not recognized in diluted earnings per share calculations as they would be antidilutive. Options for 1,716,109 shares were excluded from the calculation of diluted shares because they would have had an antidilutive effect.
For the year ended December 31, 2014, 448,415 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 29,879 shares of restricted stock because they would have had an antidilutive effect. For the year ended December 31, 2013, 258,396 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 114,433 shares of restricted stock because they would have had an antidilutive effect. As the Company recognized a net loss for the year ended December 31, 2012, the unvested share-based payments were not recognized in diluted earnings per share calculations as they would be antidilutive. The calculation of diluted shares excluded 602,429 shares of restricted because they would have had an antidilutive effect.
For the year ended December 31, 2014, 273,918 shares of performance units were included in the calculation of diluted shares. There were no performance units issued in 2013.
Supplemental Disclosures of Cash Flow Information
The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2014, 2013, and 2012.
Stock-Based Compensation
The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
Treasury Stock
The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liability of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and are presented as treasury stock and carried at cost. As of December 31, 2014, 11,055 shares were accounted for as treasury stock, compared to 9,924 shares at December 31, 2013.
Foreign Currency Translation
The Company has designated the Canadian dollar as the functional currency for our operations in Canada. The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.
New Accounting Standards Not Yet Implemented in this Report
In April 2014, the FASB issued Accounting Standards Update No. 2014-08 (“Update 2014-08”), which amends FASB Accounting Standards Codification Topic 205, “Presentation of Financial Statements” and Topic 360, “Property, Plant, and Equipment.” Update 2014-08 alters the definition of a discontinued operation to cover only asset disposals that are a strategic shift with a major effect on an entity’s operations and finances, and calls for more extensive disclosures about a discontinued operation’s assets, liabilities, income and expenses. The guidance is effective for all disposals or classifications as held-for sale of components of an entity that occur within annual periods beginning on or after December 15, 2014. The Company has evaluated the provisions of Update 2014-08 and does not expect it to have an impact on its consolidated results of operations, financial position or cash flows.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue. Topic 606 Revenue from Contracts with Customers will supersede the revenue recognition requirement as in Topic 605 Revenue Recognition. Update 2014-09 requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to those goods or services. Entities may apply the amendments in Update 2014-09 either (a) retrospectively to each reporting period presented, and the entity may elect a practical expedient per the update, or (b) retrospectively with the cumulative effect of initially applying Update 2014-09 recognized at the date of initial application - if an entity elects this transition method it also should provide the additional disclosures in reporting periods. For public entities, Update 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-09 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.
In June 2014, the FASB issued Accounting Standards Update No. 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period (“Update 2014-12”), which clarifies the accounting treatment of such awards in practice. Update 2014-12 requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. Update 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015, and early adoption is permitted. The Company is currently evaluating the provisions of Update 2014-12 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.
(2) ACQUISITIONS
On December 22, 2014, the Company completed the acquisition of certain oil and gas assets from a subsidiary of Chesapeake Energy Corporation covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas, NGLs and crude oil contained in the Upper Devonian, Marcellus and Utica Shales for approximately $5.0 billion, subject to customary closing adjustments (the “Chesapeake Property Acquisition”). The transaction was temporarily financed using a $4.5 billion 364-day senior unsecured bridge term loan credit facility and a $500 million two-year unsecured term loan. The Company repaid all principal and interest outstanding on the $4.5 billion bridge term loan credit facility on January 23, 2015 after permanent financing was finalized. See Note 16 - Subsequent Events for further details.
The following table summarizes the consideration paid for the Chesapeake Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation is preliminary and subject to adjustment. These amounts will be finalized as soon as possible, but no later than one year from the acquisition date.
The Chesapeake Property Acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the December 22, 2014 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 7 - Fair Value.
The Company recorded the assets acquired and liabilities assumed in the Chesapeake Property Acquisition at their estimated fair value of approximately $5.0 billion, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. In addition, the Company included $1 million in general and administrative expenses and $5 million in interest expense for fees related to the Chesapeake Property Acquisition on its Consolidated Statement of Operations for the year ended December 31, 2014. The Company included $47 million in other current assets and $1 million in other assets for unamortized fees related to the bridge facility and term loan facility, respectively, for the Chesapeake Property Acquisition on its Consolidated Balance Sheet as of December 31, 2014. In January 2015, the Company repaid in full amounts outstanding on its bridge facility. Therefore, the Company will expense the $47 million of short-term unamortized debt issuance costs associated with the bridge facility in January 2015.
The results of operations of the Chesapeake Property Acquisition have been included in the Company’s consolidated financial statements since the December 22, 2014 closing date, including approximately $10 million of total revenue and $2 million of operating income. Summarized below are the consolidated results of operations for the years ended December 31, 2014 and 2013, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2013. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Chesapeake Property Acquisition properties. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.
In December 2014, a subsidiary of the Company and a subsidiary of Statoil ASA entered into a purchase and sale agreement in which the Company’s subsidiary will acquire certain oil and gas assets covering approximately 30,000 acres in West Virginia and southwest Pennsylvania comprising approximately 20% of Statoil’s interests in that acreage for approximately $365 million, subject to other customary adjustments (the “Statoil Property Acquisition”). All of these assets are also assets in which the Company has acquired interests under the Chesapeake Property Acquisition. This transaction closed in January 2015 and was funded with the revolving credit facility. See Note 16 - Subsequent Events for details regarding the closing of this transaction.
In December 2014, the Company announced that it had signed an agreement to purchase oil and gas assets including approximately 46,700 net acres in northeast Pennsylvania from WPX Energy, Inc. for approximately $300 million, subject to customary closing conditions (the “WPX Property Acquisition”). This acreage was producing approximately 50 million net cubic feet of gas per day from 63 operated horizontal wells as of December 2014. As part of this transaction, the Company will assume firm transportation capacity of 260 million cubic feet of gas per day predominantly on the Millennium pipeline effective upon closing. This transaction closed in January 2015 and was funded with the revolving credit facility. See Note 16 - Subsequent Events for details regarding the closing of this transaction.
In March 2014 and July 2014, the Company entered into several agreements to purchase approximately 380,000 net acres in northwest Colorado principally in the Niobrara formation for approximately $215 million. The Company utilized its revolving credit facility to finance these acquisitions. The Company closed the acquisitions in the second and third quarters and accounted for them as asset acquisitions.
In April 2013, the Company entered into a definitive purchase agreement to acquire natural gas properties located in Pennsylvania prospective for the Marcellus Shale for approximately $82 million, subject to closing conditions. The Company utilized its revolving credit facility to finance the acquisition. The Company closed the acquisition during the second quarter of 2013 and accounted for it as an asset acquisition.
(3) PREPAID EXPENSES
The components of prepaid expenses included in other current assets as of December 31, 2014 and December 31, 2013 consisted of the following:
(1)
Deposits consist of a $50 million and $15 million pre-payment related to the Statoil Property Acquisition and WPX Property Acquisition, respectively.
(4) NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
The Company’s natural gas and oil properties are located in the United States and Canada.
Net Capitalized Costs
The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2014 and 2013:
(1)
Includes $76 million and $72 million related to the Company’s exploration program in Canada as of December 31, 2014 and 2013, respectively.
(2)
Includes approximately $5.0 billion related to the Chesapeake Property Acquisition.
Natural gas and oil properties not subject to amortization represent investments in unproved properties and major development projects in which the Company owns an interest. These unproved property costs include unevaluated costs associated with leasehold or drilling interests and unevaluated costs associated with wells in progress. The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2014.
(1)
Property acquisition costs include $36 million, exploration costs include $31 million and capitalized interest includes $9 million related to the Company’s exploration program in Canada.
Of the total net unevaluated costs excluded from amortization as of December 31, 2014, approximately $3.6 billion is related to the Chesapeake Property Acquistion, approximately $12 million is related to unevaluated seismic costs in the Fayetteville Shale, approximately $34 million is related to the acquisition of undeveloped properties in the Company’s Fayetteville Shale, approximately $138 million is related to the acquisition of undeveloped properties in the Company’s Marcellus Shale and approximately $367 million is related to the acquisition of undeveloped properties in the Company’s New Ventures, excluding its exploration program in Canada. The Company has $76 million of unevaluated costs related to
its exploration program in Canada. Additionally, the Company has approximately $267 million of unevaluated costs related to costs of wells in progress. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling, and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.
Costs Incurred in Natural Gas and Oil Exploration and Development
The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities:
(1)
Includes $1 million, $17 million and $4 million, in 2014, 2013 and 2012, respectively, related to the Company’s exploration program in Canada.
(2)
Includes $3 million, $12 million and $3 million in 2014, 2013 and 2012, respectively, related to the Company’s exploration program in Canada.
Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $55 million, $62 million and $62 million during 2014, 2013 and 2012, respectively, based on the Company’s weighted average cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $320 million, $264 million and $237 million during 2014, 2013 and 2012, respectively, that were directly related to the acquisition, exploration and development of the Company’s natural gas and oil properties. Included in these amounts are internal costs from the Company’s subsidiaries involved with vertical integration of the Company’s exploration and development activities and totaled $123 million, $103 million and $82 million during 2014, 2013 and 2012, respectively. All internal costs are included in the Company’s cost of natural gas and oil properties.
Results of Operations from Natural Gas and Oil Producing Activities
The table below sets forth the results of operations from natural gas and oil producing activities:
(1)
Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments. See Note 5 Derivatives and Risk Management.
The results of operations shown above exclude general and administrative expenses and interest expense and are not necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.
Natural Gas and Oil Reserve Quantities
The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties and accounted for approximately 97%, 95% and 93% of the present worth of the Company’s total proved reserves as of December 31, 2014, 2013 and 2012, respectively. A reserve audit is not the same as a financial audit and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. Reserve estimates are inherently imprecise and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, historical prices of natural gas and crude oil and analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available. For more information over reserves, refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business - Exploration and Production” in Item 1 of this Annual Report.
The following table summarizes the changes in the Company’s proved natural gas, NGLs and oil reserves for 2014, 2013 and 2012 all of which were located in the United States:
The Company’s estimated proved natural gas and oil reserves were 10,747 Bcfe at year-end 2014, compared to 6,976 Bcfe at year-end 2013. The significant increase in the Company’s reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia. In 2014, the Company’s production was 768 Bcfe, up from 657 Bcfe in 2013. The increase in production in 2014 resulted primarily from a 103 Bcf increase in net production from the Company’s Northeast Appalachia properties, a 3 Bcfe increase in net production from its Southwest Appalachia properties, and an 8 Bcf increase in net production from its Fayetteville Shale properties, which more than offset a combined 3 Bcfe decrease in net production from its East Texas and Arkoma Basin properties. The Company replaced 591% of its production volumes with 1,693 Bcfe of proved reserve additions, net upward revisions of 543 Bcfe, and 2,304 Bcfe of proved reserve additions as a result of acquisitions primarily associated with acreage in Southwest Appalachia. Of the reserve additions, 283 Bcfe, 246 Bcfe and 2 Bcfe from the Company’s Fayetteville Shale, Northeast Appalachia, and Brown Dense divisions, respectively, were proved developed and 573 Bcfe and 589 Bcfe from its Fayetteville Shale and Northeast Appalachia divisions, respectively, were proved undeveloped. In 2014, upward reserve revisions resulting from higher gas prices totaled 38 Bcf, 10 Bcf and 6 Bcf in the Company’s Fayetteville Shale, Northeast Appalachia and Ark-La-Tex divisions, respectively. The Company also had performance revisions in 2014 of (126) Bcf, 636 Bcf and (21) Bcf in its Fayetteville Shale, Northeast Appalachia and Ark-La-Tex divisions, respectively. The Company’s December 31, 2014 proved reserves include 181 Bcfe of proved undeveloped reserves from 60 locations that
have a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties have a negative present value of $28 million when discounted at 10%. The Company has made a final investment decision and is committed to developing these reserves.
The Company’s estimated proved natural gas and oil reserves were 6,976 Bcfe at year-end 2013, compared to 4,018 Bcfe at year-end 2012. The significant increase in the Company’s reserves in 2013 was primarily due to its successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and the higher natural gas price environment compared to 2012. In 2013, the Company’s production was 657 Bcfe, up from 565 Bcfe in 2012. The increase in production in 2013 resulted primarily from a 97 Bcf increase in net production from the Company’s Northeast Appalachia properties, a 1 Bcfe increase in net production from its New Ventures properties, and a 1 Bcf increase in net production from its Fayetteville Shale properties, which more than offset a combined 7 Bcfe decrease in net production from its East Texas and Arkoma Basin properties. The Company replaced 550% of its production volumes with 3,285 Bcfe of proved reserve additions, net upward revisions of 326 Bcfe, and 4 Bcfe of proved reserve additions as a result of acquisitions. Of the reserve additions, 557 Bcfe, 386 Bcfe and 2 Bcfe from the Company’s Fayetteville Shale, Northeast Appalachia and Brown Dense divisions, respectively, were proved developed and 1,530 Bcfe and 810 Bcfe from its Fayetteville Shale and Northeast Appalachia divisions, respectively, were proved undeveloped. In 2013, upward reserve revisions resulting from higher gas prices totaled 191 Bcf, 35 Bcf and 21 Bcf in the Fayetteville Shale, Northeast Appalachia, and the Company’s Ark-La-Tex division, respectively. The Company also had upward performance revisions in 2013 of 16 Bcf, 62 Bcf and 1 Bcf in the Fayetteville Shale, Northeast Appalachia, and the Company’s New Ventures division, respectively. Additionally, the Company’s reserves increased by 4 Bcf in 2013 as a result of the acquisition of natural gas leases and wells in Northeast Appalachia. The Company’s December 31, 2013 proved reserves include 662 Bcfe of proved undeveloped reserves from 268 locations that have a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties have a negative present value of $97 million when discounted when at 10%.
The Company’s estimated proved natural gas and oil reserves were 4,018 Bcfe at year-end 2012, compared to 5,893 Bcfe at year-end 2011. The overall decrease in total estimated proved reserves in 2012 was primarily due to the low natural gas price environment. In 2012, the Company’s production was 565 Bcfe, up from 500 Bcfe in 2011. The increase in production in 2012 resulted primarily from a 49 Bcf increase in production from the Fayetteville Shale and a 30 Bcf increase in the Company’s Northeast Appalachia production, which more than offset a combined 14 Bcfe decrease in net production from the Company’s East Texas and Arkoma Basin properties. The Company replaced its production volumes with 920 Bcfe of proved reserve additions as a result of its drilling and acquisition program but also incurred net downward revisions of 2,088 Bcfe principally due to a decrease in the price of natural gas and to a lesser extent due to downward performance revisions of 336 Bcfe. Of the reserve additions, 383 Bcfe, 195 Bcfe, 3 Bcfe and 2 Bcfe from the Company’s Fayetteville Shale, Northeast Appalachia, Ark-La-Tex, and New Ventures divisions, respectively, were proved developed and 32 Bcfe and 305 Bcfe from its Fayetteville Shale and Northeast Appalachia divisions, respectively, were proved undeveloped. The total downward reserve revisions were primarily impacted by the low commodity price environment in 2012 and to a lesser extent by downward performance revisions. In 2012, downward reserve revisions resulting from lower gas prices totaled 1,684 Bcf, 9 Bcf and 59 Bcf in the Fayetteville Shale, Northeast Appalachia, and the Company’s Ark-La-Tex division, respectively. The Company also had a net downward performance revision in 2012 of 362 Bcf and 10 Bcf in the Fayetteville Shale and its Ark-La-Tex division, respectively. The Company had a net positive performance revision in 2012 of 36 Bcf in Northeast Appalachia. Additionally, the Company’s reserves decreased by 141 Bcf in 2012 as a result of its disposition of natural gas leases and wells in the Overton Field in East Texas. The Company’s December 31, 2012 proved reserves include 355 Bcfe of proved undeveloped reserves from 198 locations that have a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties have a negative present value of $71 million when discounted when at 10%.
The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. The Company used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.
Standardized Measure of Discounted Future Net Cash Flows
The following standardized measures of discounted future net cash flows relating to proved natural gas and oil reserves as of December 31, 2014, 2013 and 2012 are calculated after income taxes and discounted using a 10% annual discount rate and do not purport to present the fair market value the Company’s proved gas and oil reserves:
Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure above were $4.35 per MMBtu for natural gas, $91.48 per barrel for oil and $23.79 per barrel for NGLs in 2014, $3.67 per MMBtu for natural gas, $93.42 per barrel for oil and $43.45 per barrel for NGLs in 2013, and $2.76 per MMBtu for natural gas and $91.21 per barrel for oil in 2012. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.
Following is an analysis of changes in the standardized measure during 2014, 2013 and 2012:
(5) DERIVATIVES AND RISK MANAGEMENT
The Company is exposed to volatility in market prices and basis differentials for natural gas and oil which impacts the predictability of its cash flows related to the sale of natural gas, NGLs and oil. These risks are managed by the Company’s use of certain derivative financial instruments. As of December 31, 2014 and 2013, the Company’s derivative financial instruments consisted of fixed price swaps, basis swaps, fixed price call options, and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:
Fixed price swaps
The Company receives a fixed price for the contract and pays a floating market price to the counterparty.
Basis swaps
Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.
Fixed price call options
The Company sells fixed price call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty such excess on sold fixed price call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Interest rate swaps
Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes.
All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value other than transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative financial instruments to be classified and accounted for as either a cash flow or a fair value hedge. Accounting for qualifying hedges requires a derivative’s gains and losses to be recorded either in earnings or as a component of other comprehensive income. Gains and losses on derivatives that are not designated for hedge accounting treatment or that do not meet hedge accounting requirements are recorded in earnings as a component of gain (loss) on derivatives. Within the gain (loss) on derivatives component of the statement of operations are gains (losses) on derivatives excluding derivatives, settled and gains (losses) on derivatives, settled. The Company calculates gains (losses) on derivatives, settled, as the summation of gains and losses on positions which have settled within the period.
The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy at the time the transactions are entered into and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.
The balance sheet classification of the assets related to derivative financial instruments are summarized below as of December 31, 2014 and 2013:
As of December 31, 2014, the Company had fixed price swap derivatives designated for hedge accounting and not designated for hedge accounting on the following volumes of natural gas production (in Bcf):
Cash Flow Hedges
The reporting of gains and losses on cash flow derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gains and losses on the derivative hedging instruments are recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gains and losses from the derivative hedging instrument are recognized in earnings immediately and had an inconsequential impact to the consolidated statement of operations as of December 31, 2014 and 2013.
As of December 31, 2014, the Company recorded a net gain in accumulated other comprehensive income related to its hedging activities of $98 million net of a deferred income tax liability of $65 million. The amount recorded in accumulated other comprehensive income will be relieved over time and recognized in the statement of operations as the physical transactions being hedged occur. Assuming the market prices of natural gas futures as of December 31, 2014 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of approximately $98 million from accumulated other comprehensive income to earnings during the next 12 months. Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to natural gas sales in the consolidated statements of operations. Volatility in net income, comprehensive income and accumulated other comprehensive income may occur in the future as a result of the Company’s derivative activities.
The following tables summarize the before tax effect of all cash flow hedges on the consolidated financial statements for the years ended December 31, 2014 and 2013.
Other Derivative Contracts
For other derivative contracts, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately through gain (loss) on derivatives. Although the Company’s basis swaps meet the objective of managing commodity price exposure, these trades are typically not entered into concurrent with the Company’s derivative instruments that qualify as cash flow hedges and therefore do not generally qualify for hedge accounting. Basis swap derivative instruments that are not designated for hedge accounting are recorded on the balance sheet at their fair values under derivative assets, other long-term assets, other current liabilities, and other long-term liabilities, as applicable and all gains and losses related to these contracts are recognized immediately in the consolidated statements of operations as a component of gain (loss) on derivatives. As of December 31, 2014, the Company had basis swaps on natural gas production that were not designated for hedge accounting of 22 Bcf for 2015 and 4 Bcf for 2016.
As of December 31, 2014, the Company had fixed price call options on 200 Bcf and 120 Bcf of natural gas production in 2015 and 2016, respectively, not designated for hedge accounting and fixed price swaps of 120 Bcf of natural gas production in 2015 not designated for hedge accounting.
The Company is a party to interest rate swaps that were entered into in order to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps build to a notional amount of $170 million and expire on June 20, 2020. The Company did not designate the interest rate swaps for hedge accounting. Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives in the consolidated statements of operations.
The following tables summarize the before tax effect of fixed price swaps, basis swaps, fixed price call options and interest rate swaps not designated for hedge accounting on the condensed consolidated statements of operations for the years ended December 31, 2014 and 2013.
(1)
The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.
(6) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME
The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects for the year ended December 31, 2014:
(1)
All amounts are net of tax.
(2)
See separate table below for details about these reclassifications.
(1)
See Note 12 for additional details regarding the Company’s retirement and employee benefit plans.
(2)
Net actuarial loss had no impact on the consolidated statement of operations.
(7) FAIR VALUE MEASUREMENTS
The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2014 and 2013 were as follows:
The carrying values of cash and cash equivalents, accounts receivable, accounts payable, other current assets and current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:
Debt: The fair values of the Company’s senior notes were based on the market for the Company’s publicly-traded debt as determined based on yield of the Company’s 7.5% Senior Notes due 2018, which was 3.2% as of December 31, 2014 and 2.6% at December 31, 2013, and its 4.10% Senior Notes due 2022, which was 4.3% as of December 31, 2014 and 4.2% at December 31, 2013. The carrying values of the borrowings under the Company’s unsecured revolving credit facility, bridge facility, and term loan facility approximate fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy.
Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.
The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:
Level 1 valuations -
Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.
Level 2 valuations -
Consist of quoted market information for the calculation of fair market value.
Level 3 valuations -
Consist of internal estimates and have the lowest priority.
The Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s Level 2 fair value measurements include fixed price swaps and are estimated using internal discounted cash flow calculations using the NYMEX futures index. The Company utilized discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2014 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset and liability measurement represent Level 2 inputs in the hierarchy. The Company’s Level 3 fair value measurements include fixed price call options and basis swaps. The Company’s fixed price call options are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves.
Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively. However, such changes would not have a significant impact.
Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2014 and 2013. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a marketplace participant would have used as of December 31, 2014 and December 31, 2013.
(8) DEBT
The components of debt as of December 31, 2014 and 2013 consisted of the following:
The following is a summary of scheduled long-term debt maturities by year as of December 31, 2014 (in millions):
Chesapeake Property Acquisition Financing
On December 19, 2014, the Company entered into a $4.5 billion unsecured 364-day bridge term loan credit agreement with various lenders. The bridge facility requires prepayments under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business or for specified uses. The Company repaid the $4.5 billion outstanding and terminated the bridge facility in January 2015 with net proceeds of $669 million and $1.7 billion from common stock and depositary share offerings, respectively, and $2.2 billion from senior note offerings with the difference utilized to pay down amounts under the revolving credit facility.
On December 19, 2014, the Company also entered into a $500 million unsecured two-year term loan credit agreement with various lenders. The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business.
Credit, Bridge and Term Facilities
The Company’s revolving credit facility provides a borrowing capacity of up to $2.0 billion and matures on December 2018, with options for two one-year extensions with participating lender approval. The amount available under the revolving credit facility may be increased by $500 million upon the Company’s agreement with its participating lenders. The interest rates on the revolving credit facility, bridge facility and term loan facility are calculated based upon the Company’s credit rating and were 137.5 basis points over the current London Interbank Offered Rate, or LIBOR as of December 31, 2014, and is currently at 150 basis points over the current LIBOR. The interest rate on the revolving credit facility at December 31, 2013 was 150 basis points over LIBOR. The revolving credit facility, bridge facility and term
loan facility are unsecured and are not guaranteed by any subsidiaries of the Company. The revolving credit facility, bridge facility and term loan facility contain covenants which impose certain restrictions on us, including a financial covenant under which the Company may not issue total debt in excess of 60% of its total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments (after December 31, 2011), certain hedging activities and the Company’s pension and other postretirement liabilities. As of December 31, 2014, the Company was in compliance with the covenants of its revolving credit facility, bridge facility, term loan facility and other debt agreements.
(9) COMMITMENTS AND CONTINGENCIES
Operating Commitments and Contingencies
The Company has commitments to third parties for demand transportation charges. As of December 31, 2014, future payments under non-cancelable firm transportation charges are approximately $478 million in 2015, $515 million in 2016, $543 million in 2017, $549 million in 2018, $502 million in 2019 and $2,802 million thereafter.
The Company has 11 leases for pressure pumping equipment for its E&P operations under leases that expire between December 2017 and January 2018. The Company’s current aggregate annual payment under the leases is approximately $8 million. The Company has 7 leases for drilling rigs for its E&P operations that expire in 2020. The Company’s current aggregate payment under the leases is approximately $13 million. The lease payments for the pressure pumping equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to third-party working interest owners for their share of fracture stage charges.
The Company leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases expiring through 2027. As of December 31, 2014, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $73 million in 2015, $62 million in 2016, $45 million in 2017, $25 million in 2018, $21 million in 2019 and $45 million thereafter. The Company also has commitments for compression services related to its Midstream Services and E&P segments. As of December 31, 2014, future minimum payments under these non-cancelable agreements are approximately $41 million in 2015, $28 million in 2016, $19 million in 2017, $10 million in 2018, and $4 million in 2019.
In response to its well performance, the Company entered into new and amended natural gas transportation and gathering arrangements with third party pipelines during the second quarter of 2013 in support of its production in Northeast Appalachia. As of December 31, 2014, the Company’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $5.4 billion and it has guarantee obligations of up to $173 million of that amount.
In 2013, the Company started construction on a corporate office complex located in Spring, Texas on 26 acres of commercial land that it purchased in 2012. The Company financed the construction of this complex through a construction agreement and lease arrangement. As of December 31, 2014, the Company was obligated for the construction costs incurred, which approximated $137 million. In January 2015, construction on the corporate campus was completed and the Company commenced a lease with a term of approximately five years.
In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brunswick of approximately $47 million Canadian dollars in the aggregate over the license periods. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of $45 million Canadian dollars. The promissory notes secure the Company's capital expenditure obligations under the licenses and are returnable to the Company to the extent the Company performs such obligations. If the Company fails to fully perform, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Company commenced its Canada exploration program in 2010 and, as of December 31, 2014 has invested $45 million Canadian dollars, or $44 million USD, in New Brunswick towards the Company’s commitment, fully covering the promissory notes held by the Province of New Brunswick. No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of December 31, 2014 and its future investment plans. Our licenses are scheduled to expire in March 2015. The newly elected provincial government in New Brunswick has announced an intent to impose a moratorium on hydraulic fracturing until a list of conditions is met and has introduced authorizing legislation in the provincial legislature. The Company has applied for an extension of its licenses past the end of the moratorium, but as of this time that extension has not been granted. The list of conditions that the provincial government has announced is subjective, and the Company cannot predict the duration of the moratorium or whether it will be granted the extension requested or any other extension. Unless and until the moratorium is lifted and the Company’s licenses are extended, it will not be able to continue with its program in New Brunswick. If this extension is not granted, the Company may be required to write off its investment.
Environmental Risk
The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or results of operations of the Company.
Litigation
Tovah Energy
In February 2009, one of the Company’s subsidiaries was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et al., pending in the 273rd District Court in Shelby County, Texas. By the time of trial in December 2010, Ms. Berry-Helfand (the only remaining plaintiff) alleged that, in 2005, she provided the Company’s subsidiary with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that the Company’s subsidiary refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom. Among other things, she alleged various statutory and common law claims, including, but not limited to, claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by the Company’s subsidiary between February 2005 and February 2006. She also sought disgorgement of the Company’s subsidiary’s profits. A former associate of the plaintiff intervened in the matter claiming to have helped develop the prospect years earlier.
The jury found in favor of the plaintiff and the intervenor with respect to all of the statutory and common law claims and awarded $11 million in compensatory damages but no special, punitive or other damages. Separately, the jury determined that the Company’s subsidiary’s profits for purposes of disgorgement, if ordered as a remedy, were $382 million. (Disgorgement of profits is an equitable remedy determined by the judge, and it is within the judge’s discretion to award none, some or all of unlawfully obtained profits.) In August 2011, a judgment was entered pursuant to which the plaintiff and the intervenor were entitled to recover approximately $11 million in actual damages and approximately $24 million in disgorgement as well as prejudgment interest and attorneys’ fees, which currently are estimated to be up to $9 million, and all costs of court of the plaintiff and intervenor.
Both sides appealed and in July 2013, the Tyler Court of Appeals ordered that (1) the judgment awarding the plaintiff and the intervenor $24 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11 million for actual damages, insofar as it is based on the jury’s findings of breach of fiduciary duty, fraud, breach of contract, and theft of trade secret is reversed and judgment rendered that the plaintiff and the intervenor take nothing under those theories of recovery, (3) the award of $11 million to the plaintiff and the intervenor as damages for misappropriation of trade secret is affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for the Company’s subsidiary as the prevailing party under the Texas Theft Liability Act, and (5) in all other respects, the judgment is affirmed. All parties petitioned for rehearing. The Tyler Court of Appeals denied rehearing in November 2013.
The Company’s subsidiary filed a petition for review in the Supreme Court of Texas in February 2014. The plaintiff and the intervenor filed cross petition for review in April 2014, but conditioned their filing on the courts granting the Company’s subsidiary petition for review; i.e., if the court denies the Company’s subsidiary’s petition for review, then the plantiff and the intervenor are not seeking further review of the court of appeals’ judgment. On October 24, 2014, the Supreme Court requested full briefing on the merits of the case. Based on the Company’s understanding and judgment of the facts and merits of this case, including appellate matters, and after considering the advice of counsel, the Company has determined that, although reasonably possible, a materially adverse final outcome to this action is not probable. As such, the Company has not accrued any amounts with respect to this action. If the Supreme Court declines to rule on the case or affirms all aspects of the court of appeals’ judgment then the Company’s subsidiary would owe the $11 million in damages, plus interest and attorneys fees, offset by any award of attorneys’ fees for its prevailing on the theft count. The Company’s assessment may change in the future due to occurrence of certain events, such as the result of the petitions for review at the Supreme Court of Texas, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows.
Arkansas Royalty Litigation
The Company is a defendant in three cases, two filed in Arkansas state court in 2010 and 2013 and one in federal court in 2014, on behalf of putative classes of royalty owners on some of its leases located in Arkansas. The chief complaint in all three cases is that the Company underpaid the royalty owners by, among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in excess of what is permitted by the relevant leases. The Company removed the two cases filed in state court to federal court, but both were remanded to state court during the third quarter of 2014; the appeal of those remand orders is ongoing. Despite the ongoing appeal of the remand, in September and October 2014 the judges in the two Arkansas state actions entered orders certifying classes of royalty owners who are citizens of Arkansas. The Company is appealing those orders. Discovery regarding the plantiffs’ theories of liability and amount of claimed damages is in the very early stages. Management believes that the deductions from royalty payments as calculated are permitted and intends to defend the cases vigorously. The Company’s assessment may change in the future due to the occurrence of certain events, such as adverse judgments, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows.
Other
The Company is subject to various litigation, claims and proceedings that have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on the Company’s financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated.
Indemnifications
The Company provides certain indemnifications in relation to dispositions of assets. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. No liability has been recognized in connection with these indemnifications.
(10) INCOME TAXES
The provision (benefit) for income taxes included the following components:
The provision for income taxes was an effective rate of 36% in 2014, 41% in 2013 and 39% in 2012. The following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the statutory federal tax rate to pre-tax financial income:
The components of the Company’s net deferred tax liability as of December 31, 2014 and 2013 were as follows:
The net deferred tax liability as of December 31, 2014 was comprised of net long-term deferred income tax liabilities of $1,951 million, in addition to a net current deferred income tax liability of $109 million. The net deferred tax liability at December 31, 2013 was comprised of net long-term deferred income tax liabilities of $1,527 million, in addition to a net current deferred income tax liability of $24 million. In 2014, the Company paid $14 million in state income taxes and paid $14 million in federal income taxes. In 2013, the Company paid $3 million in state income taxes and paid $16 million in federal income taxes. The Company’s net operating loss carryforward as of December 31, 2014 was $988 million and $556 million for federal and state reporting purposes, respectively, the majority of which will expire between 2028 and 2034. As of December 31, 2014, the Company has recorded a $5 million valuation allowance against its deferred tax asset for various state net operating losses. The Company also had an alternative minimum tax credit carryforward of $131 million and a statutory depletion carryforward of $13 million as of December 31, 2014.
Our effective tax rate decreased in 2014 as compared with 2013. This was primarily due to a redetermination of the deferred state tax liability to reflect updated state apportionment factors in certain states.
Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises in 2014. Some exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the grant (“windfalls”). Although these additional tax benefits or “windfalls” are reflected in net operating loss
carryforwards, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable. Accordingly, since the tax benefit does not reduce the Company’s current taxes payable in 2014 due to net operating loss carryforwards, these “windfall” tax benefits are not reflected in its net operating losses in deferred tax assets for 2014. Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2014 were $152 million.
The Company has an income tax net operating loss carryforward related to its Canadian operations of $26 million, and has expiration dates of 2030 through 2034. The Company assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to utilize the existing deferred tax asset associated with the Canadian net operating loss. Based on this assessment, the Company did not record a valuation allowance as of December 31, 2014.
A tax position must meet certain thresholds for any of the benefit of the uncertain tax position to be recognized in the financial statements. As of December 31, 2014, the amount of unrecognized tax benefits related to alternative minimum tax was $44 million. The uncertain tax position identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax position are expected within the next 12 months. As of December 31, 2014, the Company had accrued a liability of $1 million of interest related to this uncertain tax position. The Company recognizes penalties and interest related to uncertain tax positions in income tax expense.
A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
The income tax years 2011 to 2014 remain open to examination by the major taxing jurisdictions to which the Company is subject.
(11) ASSET RETIREMENT OBLIGATIONS
The following table summarizes the Company’s 2014 and 2013 activity related to asset retirement obligations:
(1)
Obligations incurred include $42 million related to the Chesapeake Property Acquisition.
(12) RETIREMENT AND EMPLOYEE BENEFIT PLANS
401(k) Defined Contribution Plan
The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $3 million, $3 million and $2 million of contribution expense in 2014, 2013 and 2012, respectively. Additionally, the Company capitalized $3 million, $3 million and $3 million of contributions in 2014, 2013 and 2012, respectively, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
Defined Benefit Pension and Other Postretirement Plans
Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.
The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.
Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.
The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets, and funded status as of December 31, 2014 and 2013:
The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded status for each period as presented above.
The change in accumulated other comprehensive income related to the pension plans was a loss of $23 million ($14 million after tax) for the year ended December 31, 2014 and a gain of $19 million ($12 million after tax) for the year ended December 31, 2013. The change in accumulated other comprehensive income related to the other postretirement benefit
plan was a loss of $2 million ($1 million after tax) for the year ended December 31, 2014 and was a gain of $2 million ($1 million after tax) for the year ended December 31, 2013. Included in accumulated other comprehensive income as of December 31, 2014 and 2013 was a $41 million loss ($24 million net of tax) and a $16 million loss ($10 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2014, $25 million was classified to accumulated other comprehensive income primarily driven by actuarial loss adjustments. Amortization of prior period service cost reclassified from accumulated other comprehensive income to general and administrative expenses for the year was immaterial.
The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2015 is a $2 million net loss.
The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2014 and 2013 are as follows:
Pension and other postretirement benefit costs include the following components for 2014, 2013 and 2012:
Amounts recognized in other comprehensive income for the year ended December 31, 2014 were as follows:
The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2014 and 2013 are as follows:
The assumptions used in the measurement of the Company’s net periodic benefit cost for 2014, 2013 and 2012 are as follows:
The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee Retirement Income Security Act and with a prudent level of diversification.
For measurement purposes, the following trend rates were assumed for 2014 and 2013:
Assumed health care cost trend rates have a significant effect on the amounts for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
Pension Payments and Asset Management
In 2014, the Company contributed $12 million to its pension plans and $0.1 million to its other postretirement benefit plan. The Company expects to contribute $12 million to its pension plans and $1 million to its other postretirement benefit plan in 2015. No plan assets are expected to be returned to the Company during the next twelve months.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth of plan assets and to ensure adequate liquidity exists for the near-term benefit payment of obligations to participants, retirees and beneficiaries. The Benefits Administration Committee of the Company administers the Company’s pension plan assets. The Benefits Administration Committee believes long-term investment performance is a function of asset-class mix and restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets, international equity markets or investment grade fixed income assets.
The table below presents the allocations targeted by the Benefits Administration Committee and the actual weighted-average asset allocation of the Company’s pension plan as of December 31, 2014, by asset category. The asset allocation targets are subject to change and the Benefits Administration Committee allows for its actual allocations to deviate from target as a result of current and anticipated market conditions. Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range.
(1)
Asset category above includes the following equity securities in the table below: U.S. large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and U.S. small cap equity.
(2)
Asset category above includes Non-U.S. equity securities in the table below.
(3)
Asset category above includes Emerging markets equity securities below.
(4)
Asset category above includes none of the securities in the table below.
(5)
Asset category above includes Fixed income pension plan assets in the table below.
(6)
Asset category above includes Cash and cash equivalents pension plan assets in the table below.
Utilizing the fair value hierarchy described in Note 7 - Fair Value Measurements, the Company’s fair value measurement of pension plan assets as of December 31, 2014 are as follows:
(1)
Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2)
Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3)
An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
(4)
Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(5)
Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(6)
An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(7)
Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.
Utilizing the fair value hierarchy described in Note 7 - Fair Value Measurements, the Company’s fair value measurement of pension plan assets at December 31, 2013 are as follows:
(1)
Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2)
Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3)
An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
(4)
Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(5)
Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(6)
An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(7)
An institutional fund that seeks to replicate the performance of the Barclays Capital Long-Term Corporate Bond Index before fees through a sampling process.
The Company’s pension plan assets that are classified as Level 1 are due to the pension plan’s investments comprising either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fair value measurement as Level 1. The Company’s Level 2 pension plan assets represent investments in institutional funds. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers. No concentration of risk arising within or across categories of plan assets exists due to any significant investments in a single entity, industry, country or investment fund.
(13) STOCK-BASED COMPENSATION
The Southwestern Energy Company 2013 Incentive Plan (2013 Plan) was adopted in February 2013 and approved by stockholders in May 2013. The 2013 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2013 Plan replaced the Southwestern Energy Company 2004 Stock Incentive Plan, the Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan), and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (2002 Plan) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The awards under the prior plans have been adjusted for stock splits as permitted under such plans.
The 2013 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units to employees, officers, and directors that in the aggregate do not exceed 20,500,000 shares. The types of incentives that may be awarded are comprehensive and are intended to enable the Company’s board of directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2013 Plan.
As initially adopted, the 2004 Plan, the 2000 Plan, and the 2002 Plan provided for grants of options, stock appreciation rights, shares of phantom stock, and shares of restricted stock that in the aggregate did not exceed 16,800,000, 1,250,000, and 300,000 shares, respectively, to employees who are not officers or directors of the Company under provisions of Section 16 of the Securities Exchange Act of 1934, as amended. The Company may utilize treasury shares, if available, or authorized but unissued shares when a stock option is exercised or when restricted stock is granted.
The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. All options are issued at fair market value at the date of grant and expire seven years from the date of grant for awards under both the 2013 Plan and the 2004 Plan and ten years from the date of grant for awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three years from the grant date. The Company issues shares of restricted stock to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards granted to participants who have reached retirement age or will reach retirement age during the vesting period. Restricted stock and stock options granted to participants on or after December 6, 2013 immediately vest upon death, disability, or retirement (subject to a minimum of three years of service).
Stock Options
The Company recorded the following compensation costs related to stock options for the years ended December 31, 2014, 2013 and 2012:
The Company also recorded a deferred tax asset of $3 million related to stock options in 2014, compared to deferred tax benefits of $4 million in 2013 and $2 million in 2012. A total of $13 million of unrecognized compensation cost related to the Company’s unvested stock option and restricted stock grants. This cost is expected to be recognized over a weighted-average period of 2 years.
The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on exercise of stock options, post vesting
forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant.
The following tables summarize stock option activity for the years 2014, 2013 and 2012 and provide information for options outstanding at December 31 of each year:
The weighted-average grant-date fair value of options granted during the years 2014, 2013 and 2012 was $10.16, $13.39, and $16.91, respectively. The total intrinsic value of options exercised during 2014, 2013 and 2012 was $4 million, $22 million and $44 million, respectively.
Restricted Stock
The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2014, 2013 and 2012:
The Company also recorded a deferred tax liability of $10 million related to restricted stock for the year ended December 31, 2014, compared to deferred tax liabilities of $15 million for 2013 and $1 million for 2012. As of December 31, 2014, there was $75 million of total unrecognized compensation cost related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of 3.1 years.
The following table summarizes the restricted stock activity for the years 2014, 2013 and 2012 and provides information for restricted stock outstanding at December 31 of each year:
The fair values of the grants were $40 million for 2014, $43 million for 2013 and $19 million for 2012. The total fair value of shares vested were $20 million for 2014, $14 million for 2013 and $13 million for 2012.
Equity-Classified Performance Units
The Company recorded the following compensation costs related to equity-classified performance units for the years ended December 31, 2014. The performance units include a market condition based on Relative Total Shareholder Return (“TSR”) and a performance condition based on the Company’s Present Value Index (“PVI”). The fair value of the TSR market condition of the performance units is based on a Monte Carlo model and is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the PVI performance condition of the performance units is based on the closing price of the Company’s common stock at the grant date and amortized to compensation expense on a straight line basis over the vesting period of the award.
The Company also recorded a deferred tax asset of $2 million related to equity-based performance units for the year ended December 31, 2014, compared to no deferred tax recorded in 2013 and 2012. As of December 31, 2014, there was $24 million of total unrecognized compensation cost related to unvested equity-based performance units that is expected to be recognized over a weighted-average period of 3 years.
The following table summarizes performance unit activity to be paid out in Company stock for the twelve months ended December 31, 2014 and provides information for unvested units as of December 31, 2014:
Liability-Classified Performance Units
Certain employees were provided performance units vesting equally over three years. The payout of these units is based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goal. At the end of each performance period, the value of the vested performance units, if any, is paid in cash. The Company paid $25 million related to the vested performance units in 2014, $3 million in 2013, and $19 million in 2012. As of December 31, 2014 and 2013, the Company’s liability under the performance unit agreements was $51 million and $45 million, respectively.
(14) SEGMENT INFORMATION
The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and crude oil. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas volumes and through gathering fees associated with the transportation of natural gas to market.
Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, and other income (loss). The “Other” column includes items not related to the Company’s reportable segments including real estate and corporate items.
(1)
Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.
(2)
Includes a $1,940 million non-cash ceiling test impairment of the Company’s natural gas and oil properties.
(3)
Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.
(4)
Capital investments include an increase of $155 million for 2014 and a decrease of $25 million and $37 million for 2013 and 2012, respectively, related to the change in accrued expenditures between years.
Included in intersegment revenues of the Midstream Services segment are approximately $2.8 billion, $2.0 billion and $1.3 billion for 2014, 2013 and 2012, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures, prepaid debt and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments. For 2014, 2013, and 2012, capital investments within the E&P segment include $11 million, $35 million, and $12 respectively, related to the Company’s activities in Canada. As of December 31, 2014, 2013, and 2012, E&P assets include $77 million, $79 million, $44 million related to the Company’s activities in Canada.
(15) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the years ended December 31, 2014 and 2013:
(16) SUBSEQUENT EVENTS
On January 21, 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares). Net proceeds from the offerings totaled approximately $2.3 billion after underwriting discounts and offering expenses. The common stock offering was priced at $23.00 per share. Net proceeds, after underwriting discount and expenses, from the common stock offering were approximately $669 million. Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1.7 billion. Each depositary share represents a 1/20th interest in a share of the Company's 6.25% Series B Mandatory Convertible Preferred Stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share). The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364-day bridge term loan facility.
On January 23, 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.300% senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of its 4.050% senior notes due 2020 (the “2020 Notes”) and $1 billion aggregate principal amount of its 4.950% senior notes due 2025 (the “2025 Notes” and together with the 2018 Notes and the 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses. The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 Notes. The proceeds from the offering were used to repay all principal and interest remaining outstanding under the Company’s $4.5 billion 364-day bridge term loan facility and were used to repay a portion of amounts outstanding under the Company’s revolving credit facility.
On January 27, 2015, the Company closed the Statoil Property Acquisition to purchase certain oil and natural gas assets covering approximately 30,000 acres in West Virginia and southwest Pennsylvania comprising approximately 20% of Statoil’s interests in that acreage for $365 million, after environmental and title adjustments, and subject to customary post-closing adjustments.
On January 30, 2015, the Company closed the WPX Property Acquisition to purchase approximately 46,700 net acres in northeast Pennsylvania for an adjusted purchase price of $288 million, subject to customary post-closing adjustments.

ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

ITEM 9A - CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We have performed an evaluation under the supervision and with the participation of its management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act). Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2014 at a reasonable assurance level. There were no changes in our internal control over financial reporting during the three months ended December 31, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management has excluded the oil and gas assets from a subsidiary of Chesapeake Energy Corporation in West Virginia and southwest Pennsylvania (“Chesapeake Property Acquisition”) from its assessment of internal control over financial reporting as of December 31, 2014 as the Chesapeake Property Acquisition was acquired during 2014. The total assets and total revenues of the Chesapeake Property Acquisition represent approximately 33% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014.
Management’s Report on Internal Control Over Financial Reporting is included on page 70 of this Annual Report.
PricewaterhouseCoopers LLP’s report on Southwestern Energy’s internal control over financial reporting is included in its Report of Independent Registered Public Accounting Firm on page 71 of this Annual Report.

ITEM 9B - OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
There was no information required to be disclosed in a current report on Form 8-K during the fourth quarter of the fiscal year ended December 31, 2014, that was not reported on such form.
PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE OFFICERS OF THE REGISTRANT4
Name
Officer Position
Age
Years Served as Officer
Steven L. Mueller
Chairman of the Board and Chief Executive Officer
William J. Way
President and Chief Operating Officer
Mark K. Boling
Executive Vice President and President
V+ Development Solutions
Jeffrey B. Sherrick
Executive Vice President - Corporate Development
R. Craig Owen
Senior Vice President and Chief Financial Officer
John C. Ale
Senior Vice President, General Counsel and Secretary
Mr. Mueller was appointed to his present position as Chairman of the Board in May 2014. Mr. Mueller was appointed Chief Executive Officer in May 2009 and was elected to the Board of Directors in July 2009. Mr. Mueller joined us as President and Chief Operating Officer in June 2008. He joined us from CDX Gas, LLC, where he was employed as Executive Vice President from September 2007 to May 2008. From 2001 until 2007, Mr. Mueller served first as the Senior Vice President and General Manager Onshore and later as the Executive Vice President and Chief Operating Officer of The Houston Exploration Company. A graduate of the Colorado School of Mines, Mr. Mueller has over 30 years of experience in the oil and natural gas industry and has served in multiple operational and managerial roles at Tenneco Oil Company, Fina Oil Company, American Exploration Company and Belco Oil & Gas Company.
Mr. Way was appointed to his present position as President in December 2014. Mr. Way joined the Company in 2011 as Executive Vice President and Chief Operating Officer of Southwestern Energy. Prior to joining the Company, he was Senior Vice President, Americas of BG Group plc with responsibility for E&P, Midstream and LNG operations in the United States, Trinidad and Tobago, Chile, Bolivia, Canada and Argentina. He is a graduate of Texas A&M University with a degree in Industrial Engineering and has an MBA from The Massachusetts Institute of Technology.
Mr. Boling was appointed to his present position as in December 2012. He joined us as Senior Vice President, General Counsel and Secretary in January 2002, positions in which he served until November 2013. He became Executive Vice President, General Counsel and Secretary of the Company later in 2002. Prior to joining the company, Mr. Boling had a private law practice in Houston specializing in the natural gas and oil industry from 1993 to 2002. Previously, Mr. Boling was a partner with Fulbright and Jaworski L.L.P., where he was employed from 1982 to 1993.
Mr. Sherrick was appointed to his present position in December 2013. He joined the Company in October 2008 as Senior Vice President, U.S. Exploitation of Southwestern Energy’s subsidiaries SEECO, Inc. and Southwestern Energy Production Company. From 2005 to 2007, Mr. Sherrick served as the Senior Vice President, Corporate Development of The Houston Exploration Company. In 2004, he served as the Senior Vice President, Production and Nonregulated Services of El Paso Production Company. From 1999 through 2002, he served as the Chairman, CEO and President of Enron Global Exploration and Production Inc., and prior to that he served in multiple operational and managerial roles at Enron Oil & Gas Company, and Tenneco Oil Company. Mr. Sherrick is a graduate of Marietta College with a Bachelor of Science degree in Petroleum Engineering.
Mr. Owen was appointed to his present position in October 2012. He joined the Company as Controller in July 2008 and was promoted to Senior Vice President in May 2012. Immediately prior to joining the Company, he was Controller, Operations Accounting of Anadarko Petroleum Corporation, where he had held various managerial positions since 2001. Prior to Anadarko Petroleum, Mr. Owen was a business assurance manager at PricewaterhouseCoopers LLP in Houston, Texas, serving clients in the energy, insurance, banking and investment industries, and held various financial reporting roles with ARCO Pipe Line Company and Hilcorp Energy Company. Mr. Owen holds a bachelor of business administration degree in accounting from Texas A&M University and is a Certified Public Accountant.
Mr. Ale joined the Company in November 2013 as Senior Vice President, General Counsel and Secretary. Prior to Southwestern Energy, Mr. Ale was Vice President and General Counsel of Occidental Petroleum Corporation. Previously, he was a partner with Skadden, Arps, Slate, Meagher & Flom LLP and Vinson & Elkins LLP. Mr. Ale served as a law clerk to Chief Justice Warren E. Burger of the U.S. Supreme Court and to Judge Edward Tamm of the U.S. Court of Appeals for the D.C. Circuit. He holds a Juris Doctorate degree from the University of Virginia School of Law and a Bachelor of Arts degree in economics from the University of Virginia College of Arts and Sciences.
All executive officers are elected at the Annual Meeting of the Board of Directors for one-year terms or until their successors are duly elected. There are no arrangements between any officer and any other person pursuant to which he was selected as an officer. There is no family relationship between any of the Company’s executive officers or between any of them and the Company’s directors.
The definitive proxy statement to holders of the Company’s common stock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Stockholders to be held on or about May 19, 2015 (the “Proxy Statement”), is hereby incorporated by reference for the purpose of providing information about the Company’s directors, and for discussion of its audit committee and its audit committee financial expert. Refer to the sections “Proposal No. 1: Election of Directors” and “Share Ownership of Management, Directors and Nominees” in the Proxy Statement for information concerning our directors. Refer to the section “Corporate Governance - Committees of the Board of Directors” in the 2015 Proxy Statement for discussion of its audit committee and its audit committee financial expert. Information concerning the Company’s executive officers is presented in Part I of this Annual Report. The Company refers you to the section “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement for information relating to compliance with Section 16(a) of the Exchange Act.
Southwestern Energy has adopted a code of ethics that applies to its Chief Executive Officer, Chief Financial Officer and Controller as well as other officers and employees. The full text of such code of ethics has been posted on the Company’s website at www.swn.com, and is available free of charge in print to any stockholder who requests it. Requests for copies should be addressed to the Secretary at 10000 Energy Drive, Spring, Texas 77389.

ITEM 11 - EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The Proxy Statement is hereby incorporated by reference for the purpose of providing information about executive compensation, compensation committee interlocks and insider participation as well as the Compensation Committee Report. Refer to the sections “Compensation Discussion & Analysis,” “Executive Compensation,” “Outside Director Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the Proxy Statement.

ITEM 12 - SECURITY OWNERSHIP
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The Proxy Statement is hereby incorporated by reference for the purpose of providing information about securities authorized for issuance under our equity compensation plans and security ownership of certain beneficial owners and its management. For information about our equity compensation plans, refer to “Equity Compensation Plans” in its Proxy Statement. Refer to the sections “Security Ownership of Certain Beneficial Owners” and “Share Ownership of Management, Directors and Nominees” in the Company’s Proxy Statement for information about security ownership of certain beneficial owners and its management and directors.

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The Proxy Statement is hereby incorporated by reference for the purpose of providing information about certain relationships, related transactions and board independence. Refer to the sections “Transactions with Related Persons,” “Share Ownership of Management, Directors and Nominees,” and “Compensation Discussion and Analysis” for information about transactions with our executive officers, directors or management and to “Corporate Governance - Director Independence” and “ - Committees of the Board of Directors” for information about director independence.

ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The Proxy Statement is hereby incorporated by reference for the purpose of providing information about fees paid to the principal accountant and the audit committee’s pre-approval policies and procedures. Refer to the section “Relationship with Independent Registered Public Accounting Firm” in the Proxy Statement and to Exhibit A thereto for information concerning fees paid to our principal accountant and the audit committee’s pre-approval policies and procedures and other required information.
PART IV

ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) (1) The consolidated financial statements of Southwestern Energy and its subsidiaries and the report of independent registered public accounting firm are included in Item 8 of this Annual Report.
(2) The consolidated financial statement schedules have been omitted because they are not required under the related instructions, or are not applicable.
(3)
The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Annual Report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused the report to be signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHWESTERN ENERGY COMPANY
Dated: February 26, 2015BY:/s/ R. CRAIG OWEN
R. Craig Owen
Senior Vice President
and Chief Financial Officer
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 indicated on February 26, 2015.
. CRAIG OWEN
/s/ STEVEN L. MUELLER
Director, Chairman of the Board, and Chief Executive Officer
Steven L. Mueller
/s/ R. CRAIG OWEN
Senior Vice President and Chief Financial Officer
R. Craig Owen
/s/ JOSH C. ANDERS
Vice President, Controller
Josh C. Anders
/s/ JOHN D. GASS
Director
John D. Gass
/s/ CATHERINE A. KEHR
Director
Catherine A. Kehr
/s/ GREG D. KERLEY
Director
Greg D. Kerley
/s/ VELLO A. KUUSKRAA
Director
Vello A. Kuuskraa
/s/ KENNETH R. MOURTON
Director
Kenneth R. Mourton
/s/ ELLIOTT PEW
Director
Elliott Pew
/s/ TERRY W. RATHERT
Director
Terry W. Rathert
/s/ ALAN H. STEVENS
Director
Alan H. Stevens
EXHIBIT INDEX
Exhibit Number
Description
1.1
Common Stock Underwriting Agreement, dated January 14, 2015, between Southwestern Energy Company and, Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the underwriters named therein. (Incorporated by reference to Exhibit 1.1 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
1.2
Depositary Shares Underwriting Agreement, dated January 14, 2015, between Southwestern Energy Company and, Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the underwriters named therein. (Incorporated by reference to Exhibit 1.2 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
1.3
Underwriting Agreement, dated January 20, 2015, between Southwestern Energy Company and, Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the underwriters named therein (Incorporated by reference to Exhibit 1.1 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
2.1
Purchase Agreement dated as of October 14, 2014 between Southwestern Energy Production Company and Chesapeake Appalachia, L.L.C. (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on October 17, 2014)
3.1
Amended and Restated Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010)
3.2
Amended and Restated Bylaws of Southwestern Energy Company, as amended on February 25, 2014. (Incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K filed February 27, 2014)
3.3
Certificate of Designations of 6.25% Series B Mandatory Convertible Preferred Stock (including form of stock certificate). (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
3.4
Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock, dated April 9, 2009. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 9, 2009)
4.1
Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.2
Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First National Bank of Chicago, as trustee. (Incorporated by reference to Exhibit 4 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (File No. 33-63895) filed on November 17, 1995)
4.3
First Supplemental Indenture between Southwestern Energy Company and J.P. Morgan Trust Company, N.A. (as successor to the First National Bank of Chicago) dated June 30, 2006. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.4
Second Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee (as successor to J.P. Morgan Trust Company, N.A.), dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
4.5
Indenture dated June 1, 1998 by and among NOARK Pipeline Finance, L.L.C. and The Bank of New York. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)
4.6
First Supplemental Indenture dated May 2, 2006 by and among Southwestern Energy Company, NOARK Pipeline Finance, L.L.C., and UMB Bank, N.A., as trustee (as successor to the Bank of New York). (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)
4.7
Second Supplemental Indenture between Southwestern Energy Company and UMB Bank, N.A., as trustee, dated June 30, 2006. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.8
Third Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and UMB Bank, N.A., as trustee, dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
4.9
Guaranty dated June 1, 1998 by Southwestern Energy Company in favor of The Bank of New York, as trustee, under the Indenture dated as of June 1, 1998 between NOARK Pipeline Finance L.L.C. and such trustee. (Incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2005)
4.10
Indenture dated January 16, 2008 among Southwestern Energy Company, the Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 16, 2008)
4.11
Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee, dated as of March 5, 2012. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012)
4.12
Policy on Confidential Voting of Southwestern Energy Company. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2006 Annual Meeting of Stockholders)
4.13
Credit Agreement dated December 16, 2013 among Southwestern Energy Company, JPMorgan Chase Bank, NA, Bank of America, N.A., Wells Fargo N.A., The Royal Bank of Scotland PLC, Citibank, N.A. and the other lenders named therein, JPMorgan Chase Bank, NA, as administrative agent. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed December 17, 2013)
4.14
Commitment Letter dated October 14, 2014 between Southwestern Energy Company, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Bank of America, N.A. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on October 17, 2014)
4.15
Bridge Term Loan Credit Agreement, dated December 19, 2014, among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association and The Royal Bank of Scotland plc, as Co-Syndication Agents, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Sole Lead Arranger and Sole Bookrunner, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
4.16
Term Loan Credit Agreement, dated December 19, 2014, among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Sole Lead Arranger and Sole Bookrunner, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
4.17
Form of certificate for the 6.25% Series B Mandatory Convertible Preferred Stock. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
4.18
Deposit Agreement, dated as of January 21, 2015, between Southwestern Energy Company and Computershare Trust Company, N.A., as depositary, on behalf of all holders from time to time of the receipts issued thereunder (including form of Depositary Receipt). (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
4.19
Form of Depositary Receipt for the Depositary Shares. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
4.20
Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.21
First Supplemental Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.22
Form of 3.300% Notes due 2018. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.23
Form of 4.050% Notes due 2020. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.24
Form of 4.095% Notes due 2025. (Incorporated by reference to Exhibit 4.5 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
10.1
Form of Second Amended and Restated Indemnity Agreement between Southwestern Energy Company and each Executive Officer and Director of the Registrant. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
10.2
Form of Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company, effective February 17, 1999. (Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.3
Form of Amendment to Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company prior to 2011. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.4
Form of Executive Severance Agreement between Southwestern Energy Company and Executive Officers Post 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No.1-08426) for the year ended December 31, 2012)
10.5
Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.2(b) to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.6
Amendment to Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.7
Second Amendment to Southwestern Energy Company Incentive Compensation Plan (Incorporated by reference to Exhibit 10.6 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2009)
10.8
Southwestern Energy Company Supplemental Retirement Plan as amended. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.9
Southwestern Energy Company Non-Qualified Retirement Plan as amended. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.10
Amendment One to the Southwestern Energy Company Non-Qualified Retirement Plan (Incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2009)
10.11
Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2000 Annual Meeting of Stockholders)
10.12
Southwestern Energy Company 2002 Employee Stock Incentive Plan, effective October 23, 2002. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.13
Southwestern Energy Company 2002 Performance Unit Plan, as amended, effective December 8, 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2012)
10.14
Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)
10.15
Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Annex A of the Registrant’s Proxy Statement filed April 8, 2013)
10.16
Southwestern Energy Company 2013 Incentive Plan Guidelines for Performance Unit Awards. (Incorporated by reference to Exhibit 10.16 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013)
10.17
Southwestern Energy Company 2013 Incentive Plan Guidelines for Annual Incentive Awards. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.18
Southwestern Energy Company 2013 Incentive Plan Form of Incentive Stock Option Award Agreement. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.19
Southwestern Energy Company 2013 Incentive Plan Form of Non-Qualified Stock Option Award Agreement. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.20
Southwestern Energy Company 2013 Incentive Plan Form of Non-Qualified Stock Option Award Agreement for Directors. (Incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.21
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Award Agreement. (Incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.22
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Award Agreement for Directors. (Incorporated by reference to Exhibit 10.8 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.23
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.24
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award Agreement for Directors. (Incorporated by reference to Exhibit 10.10 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.25
Form of Incentive Stock Option Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.26
Form of Non-Qualified Stock Option Agreement for non-employee directors for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.27
Form of Incentive Stock Option for awards granted on or after December 8, 2005. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.28
Form of Restricted Stock Agreement for awards granted on or after December 8, 2005. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.29
Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8, 2005 and through December 8, 2011 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.30
Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8, 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08426) for the year ended December 31, 2012)
10.31
Master Lease Agreement by and between Southwestern Energy Company and SunTrust Leasing Corporation dated December 29, 2006. (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2006)
10.32
Guaranty by and between Southwestern Energy Company and Texas Gas Transmission, LLC, dated as of October 27, 2008. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2008)
10.33
Guaranty by and between Southwestern Energy Company and Fayetteville Express Pipeline, LLC dated September 30, 2008 (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.34
Retirement Letter Agreement dated February 24, 2012 between Southwestern Energy Company and Gene A. Hammons. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed February 27, 2012)
10.35
Retirement Agreement dated August 11, 2009 between Southwestern Energy Company and Harold M. Korell. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 14, 2009)
10.36
Settlement Agreement, dated December 22, 2014, between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
21.1*
List of Subsidiaries.
23.1*
Consent of PricewaterhouseCoopers LLP.
23.2*
Consent of Netherland, Sewell & Associates, Inc.
31.1*
Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*
Certification of CEO and CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95.1*
Mine Safety Disclosure.
99.1*
Reserve Audit Report of Netherland, Sewell & Associates, Inc., dated January 16, 2015.
101.INS*
Interactive Data File Instance Document
101.SCH*
Interactive Data File Schema Document
101.CAL*
Interactive Data File Calculation Linkbase Document
101.LAB*
Interactive Data File Label Linkbase Document
101.PRE*
Interactive Data File Presentation Linkbase Document
101.DEF*
Interactive Data File Definition Linkbase Document
____________
*Filed herewith

Market Capitalization: 10028177.745178223
1-Year Return: -0.05791916325688362
252-Day Return: $252_day_return