EDGAR 10-K Filing

Company CIK: 943861
Filing Year: 2021
Filename: 943861_10-K_2021_0001437749-21-005932.json

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ITEM 1. BUSINESS
Items 1. and 2.
Business and Properties
General
Goodrich Petroleum Corporation, a Delaware corporation (together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the “Subsidiary”),“we,” “our,” or “the Company”) formed in 1995, is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend. We own interests in 189 producing oil and natural gas wells located in 37 fields in six states. At December 31, 2020, we had estimated proved reserves of approximately 543 Bcfe, comprised of 540 Bcf of natural gas and 0.5 MMBbls of oil and condensate.
We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined by accounting standards related to disclosures about segments of an enterprise.
Available Information
Our principal executive offices are located at 801 Louisiana Street, Suite 700, Houston, Texas 77002.
Our website address is http://www.goodrichpetroleum.com. We make available, free of charge through the Investor Relations portion of our website, our annual reports on Form 10-K, proxy statement, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). Reports of beneficial ownership filed pursuant to Section 16(a) of the Exchange Act are also available on our website. Information contained on our website is not part of this report.
We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
As used herein, the following terms have specific meanings as set forth below:
Bbls
Barrels of crude oil or other liquid hydrocarbons
Bcf
Billion cubic feet
Bcfe
Billion cubic feet equivalent
Boe
Barrel of crude oil or other liquid hydrocarbons equivalent
MBbls
Thousand barrels of crude oil or other liquid hydrocarbons
Mboe
Thousand barrels of crude oil equivalent
Mcf
Thousand cubic feet of natural gas
Mcfe
Thousand cubic feet equivalent
MMBbls
Million barrels of crude oil or other liquid hydrocarbons
MMBtu
Million British thermal units
Mmcf
Million cubic feet of natural gas
Mmcfe
Million cubic feet equivalent
MMBoe
Million barrels of crude oil or other liquid hydrocarbons equivalent
NGL
Natural gas liquids
U.S.
United States
Crude oil and other liquid hydrocarbons are converted into cubic feet of natural gas equivalent based on six Mcf of natural gas to one barrel of crude oil or other liquid hydrocarbons.
Developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well.
Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive.
Dry hole is an exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Economically producible as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil-and-natural gas producing activities.
Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
Exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.
Farm-in or farm-out is an agreement whereby the owner of a working interest in an oil and natural gas lease or license assigns the working interest or a portion thereof to another party who desires to drill on the leased or licensed acreage. Generally, the assignee is required to drill one or more wells to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in,” while the interest transferred by the assignor is a “farm-out.”
Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. The SEC provides a complete definition of field in Rule 4-10 (a) (15) of Regulation S-X.
Gross well or acre is a well or acre in which the registrant owns a working interest. The number of gross wells is the total number of wells in which the registrant owns a working interest.
Net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions of whole numbers.
PV-10 is the pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying the 12-month average price for the year and holding that price constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). PV-10 is not a financial measure that is calculated in accordance with United States Generally Accepted Accounting Principles (“U.S. GAAP”). The SEC methodology for computing the 12-month average price is discussed in the definition of “Proved reserves” below.
Productive well is an exploratory, development or extension well that is not a dry well.
Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. As used in this definition, “existing economic conditions” include prices and costs at which economic producibility from a reservoir is to be determined. The prices shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. The SEC provides a complete definition of proved reserves in Rule 4-10 (a) (22) of Regulation S-X.
Reasonable certainty means a high degree of confidence that the quantities will be recovered, if deterministic methods are used. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease. The deterministic method of estimating reserves or resources uses a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation. The probabilistic method of estimation of reserves or resources uses the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) to generate a full range of possible outcomes and their associated probabilities of occurrence.
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.
Undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover is a series of operations on a producing well to restore or increase production.
Oil and Natural Gas Operations and Properties
As of December 31, 2020, nearly all of our proved oil and natural gas reserves were located in Louisiana, Texas and Mississippi. We spent substantially all of our 2020 capital expenditures of $56.5 million in the Haynesville Shale Trend of Northwest Louisiana. Our total capital expenditures, including accrued costs for services performed during 2020, consisted of $56.2 million for drilling and completion costs, $0.2 million for asset retirement obligations, and $0.1 million for furniture and fixtures.
We are currently focused on developing our Haynesville Shale Trend assets. The Haynesville Shale Trend is one of the top natural gas plays in the U.S., particularly when factoring in its geographic location, pipeline and infrastructure capacity and deliverability of gas to the gulf coast industrial complex and liquified natural gas export facilities. As a result, substantially all of our 2021 capital expenditure budget is planned for Haynesville Shale Trend development.
The table below details our acreage positions, average working interest and producing wells as of December 31, 2020:
Acreage
Average
Producing wells
As of December 31, 2020
Producing Well
at December 31,
Field or Area
Gross
Net
Working Interest
Tuscaloosa Marine Shale Trend
47,669
33,076
%
Haynesville Shale Trend
48,829
26,109
%
Eagle Ford Shale Trend
6,041
4,295
-
-
Other
33,125
7,323
%
Haynesville Shale Trend
As of December 31, 2020, we have acquired or farmed-in leases totaling approximately 49,000 gross (26,000 net) acres in the Haynesville Shale Trend. During 2020, we added 16 gross (5.5 net) wells to production on our acreage. Our Haynesville Shale Trend drilling activities are currently located in leasehold areas in Caddo, DeSoto and Red River parishes, Louisiana. As of December 31, 2020, we had 9 gross (3.1 net) wells in the drilling or completion phase in the Haynesville Shale Trend.
Tuscaloosa Marine Shale Trend
As of December 31, 2020, we own approximately 48,000 gross (33,000 net) lease acres in the TMS, an oil shale play in Southwest Mississippi and Southeast Louisiana, which is predominately held by production. During 2020, we did not conduct any drilling operations and did not add any wells to production. As of December 31, 2020, we had 2 gross (1.7 net) wells waiting on completion operations in the TMS.
Eagle Ford Shale Trend
As of December 31, 2020, we have retained approximately 4,300 net acres of undeveloped leasehold in the Eagle Ford Shale Trend in Frio County, Texas.
Other
As of December 31, 2020, we maintained ownership interests in acreage and/or wells in several additional fields.
See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K for additional information on our recent operations in the Haynesville Shale Trend, TMS and Eagle Ford Shale Trend.
Oil and Natural Gas Reserves
The following tables set forth summary information with respect to our proved reserves as of December 31, 2020 and 2019, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and by Ryder Scott Company (“RSC”) our independent reserve engineers. All of our proved reserves estimates are independently prepared by NSAI and RSC. NSAI prepared the estimates on all our proved reserves as of December 31, 2020 on properties other than those located in the TMS. RSC prepared the estimate of proved reserves as of December 31, 2020 for our TMS properties. Copies of the summary reserve reports of NSAI and RSC as of December 31, 2020 are included as exhibits to this Annual Report on Form 10-K. For additional information see Supplemental Information “Oil and Natural Gas Producing Activities (Unaudited)” to our consolidated financial statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Net proved reserves and the PV-10 estimates at December 31, 2020 below were calculated using flat, twelve month average commodity index prices of $39.57 per barrel and $1.99 per MMBtu.
Proved Reserves at December 31, 2020
Developed
Developed
Producing
Non-Producing
Undeveloped
Total
(dollars in thousands)
Net Proved Reserves:
Oil (MBbls) (1)
-
-
Natural Gas (Mmcf)
151,732
-
388,272
540,004
Mcf Natural Gas Equivalent (Mmcfe) (2)
154,892
-
388,272
543,164
Estimated Future Net Cash Flows
$ 382,641
PV-10 (3)
$ 182,737
Discounted Future Income Taxes
-
Standardized Measure of Discounted Net Cash Flows (3)
$ 182,737
(1)
Includes condensate.
(2)
Based on ratio of six Mcf of natural gas per Bbl of oil and per Bbl of NGLs. NGLs are immaterial and included in Natural Gas.
(3)
PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. PV-10 of our total year-end proved reserves is considered a non-U.S. GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. See the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.
Proved Reserves at December 31, 2019
Developed
Developed
Producing
Non-Producing
Undeveloped
Total
(dollars in thousands)
Net Proved Reserves:
Oil (MBbls) (1)
1,104
-
-
1,104
Natural Gas (Mmcf)
137,683
371,459
510,066
Mcf Natural Gas Equivalent (Mmcfe) (2)
144,308
371,459
516,691
Estimated Future Net Cash Flows
$ 556,536
PV-10 (3)
$ 296,954
Discounted Future Income Taxes
(2,631 )
Standardized Measure of Discounted Net Cash Flows (3)
$ 294,323
(1)
Includes condensate.
(2)
Based on ratio of six Mcf of natural gas per Bbl of oil and per Bbl of NGLs. NGLs are immaterial and included in Natural Gas.
(3)
PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. PV-10 of our total year-end proved reserves is considered a non-U.S. GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. See the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.
The following table presents our reserves by targeted geologic formation in Mmcfe:
As of December 31, 2020
Proved
Proved
Proved
% of
Area
Developed
Undeveloped
Reserves
Total
Tuscaloosa Marine Shale Trend
3,093
-
3,093
%
Haynesville Shale Trend
151,672
388,272
539,944
%
Other
-
%
Total
154,892
388,272
543,164
%
Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the PV-10 amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties.
In accordance with the guidelines of the SEC, our independent reserve engineers’ estimates of future net revenues from our estimated proved reserves, and the PV-10 and standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period of January 2020 through December 2020, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For reserves at December 31, 2020, the average twelve month prices used were $1.99 per MMBtu of natural gas and $39.57 per Bbl of crude. These prices do not include the impact of hedging transactions, nor do they include the adjustments that are made for applicable transportation and quality differentials, and price differentials between natural gas liquids and oil, which are deducted from or added to the index prices on a well by well basis in estimating our proved reserves and related future net revenues.
Our proved reserve information as of December 31, 2020 included in this Annual Report on Form 10-K was estimated by our independent petroleum engineers, NSAI and RSC, in accordance with petroleum engineering and evaluation principles and definitions and guidelines set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserve Information promulgated by the Society of Petroleum Engineers. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Our internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria is provided to them. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves.
We consider providing independent fully engineered third-party estimates of reserves from nationally reputable petroleum engineering firms, such as NSAI and RSC, to be the best control in ensuring compliance with Rule 4-10 of Regulation S-X for reserve estimates.
While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the NSAI and RSC reserve reports are reviewed by our senior management with representatives of NSAI and RSC and our internal technical staff. Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves at least semi-annually.
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI and RSC employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, available downhole and production data, seismic data and well test data.
Our total proved reserves at December 31, 2020, as estimated by NSAI and RSC, were 543 Bcfe, consisting of 540 Bcf of natural gas and 0.5 MMBbls of oil and condensate. In 2020, we added approximately 181 Bcfe related to our drilling activities in the Haynesville Shale Trend. We had negative revisions of approximately 106 Bcfe due primarily to natural gas prices and produced 49 Bcfe in 2020. We continue to employ completion techniques on our Haynesville Shale Trend wells which have been proven successful by the production volume results from the wells we drilled in recent years. These well results in conjunction with our acreage position and our financial ability to develop our Haynesville Shale Trend properties allowed us to add the Haynesville Shale Trend reserves as of December 31, 2020.
Our proved undeveloped (“PUD”) reserves at December 31, 2020, mostly in our Haynesville Shale Trend, were 388 Bcfe, or 71% of our total proved reserves. In 2020, we had new additions of 164 Bcfe reflective of our plans to develop these reserves in and after the year 2021 but before five years have elapsed. We had net negative revisions of previous estimates of 112 Bcfe. We developed approximately 35 Bcfe, or 10% of our total proved undeveloped reserves booked as of December 31, 2019, through the drilling of 16 gross (5.5 net) development wells. Of the proved undeveloped reserves in our December 31, 2020 reserve report, the oldest was initially booked on December 31, 2016. Consequently, none have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves, and none are scheduled for commencement of development on a date more than five years from the date the reserves were initially booked as proved undeveloped.
The net negative PUD revision of previous estimates was primarily attributable to recognizing that reserves under the natural gas pricing utilized for the reserves estimation process representing approximately 117 Bcfe would not be developed within five years since they were originally booked. In addition, we had ownership decreases of 1 Bcfe offset by an increase of 6 Bcfe mostly due to economic parameter adjustments such as improved well performance and lease operating expenses.
Productive Wells
The following table sets forth the number of productive wells in which we maintain ownership interests as of December 31, 2020:
Oil
Natural Gas
Total
Gross (1)
Net (2)
Gross (1)
Net (2)
Gross (1)
Net (2)
Tuscaloosa Marine Shale Trend:
Southeast Louisiana
9.2
-
-
9.2
Southwest Mississippi
14.3
-
-
14.3
Haynesville Shale Trend:
East Texas
-
-
1.8
1.8
Northwest Louisiana
-
-
48.7
48.7
Other
0.2
2.0
2.2
Total Productive Wells
23.7
52.5
76.2
(1)
Royalty and overriding interest wells that have immaterial values are excluded from the above table.
(2)
Net working interest.
Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline connections. A gross well is a well in which we maintain an ownership interest, while a net well is deemed to exist when the sum of the fractional working interests owned by us equals one. Wells that are completed in more than one producing horizon are counted as one well.
Acreage
The following table summarizes our gross and net developed and undeveloped acreage under lease as of December 31, 2020. Acreage in which our interest is limited to a farm-out agreement, royalty or overriding royalty interest is excluded from the table.
Developed
Undeveloped
Total
Gross
Net
Gross
Net
Gross
Net
Tuscaloosa Marine Shale Trend:
Southwest Mississippi
29,191
20,372
29,267
20,373
Southeast Louisiana
18,206
12,535
18,402
12,703
Haynesville Shale Trend:
East Texas
8,274
3,474
8,584
3,497
Northwest Louisiana
30,593
17,870
9,652
4,742
40,245
22,612
Eagle Ford Shale Trend:
South Texas
6,041
4,295
-
-
6,041
4,295
Other
28,488
6,636
4,637
33,125
7,323
Total
120,793
65,182
14,871
5,621
135,664
70,803
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to the extent that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves. As is customary in the oil and natural gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the remaining primary term of such a lease. The oil and natural gas leases in which we have an interest are for varying primary terms; however, most of our developed lease acreage is beyond the primary term and is held so long as oil or natural gas is produced.
Lease Expirations
We have undeveloped lease acreage, excluding optioned acreage, that will expire during the next four years unless the leases are converted into producing units or extended prior to lease expiration. The following table sets forth the lease expirations as of December 31, 2020:
Year
Net Acreage
Operator Activities
We operate a majority of our producing properties by value, and we will generally seek to become the operator of record on properties we drill or acquire. Chesapeake Energy Corporation (“Chesapeake”) continues to operate a portion of our Northwest Louisiana acreage in the Haynesville Shale Trend.
Drilling Activities
The following table sets forth our drilling activities for the last three years. As denoted in the following table, “gross” wells refer to wells in which a working interest is owned, while a “net” well is deemed to exist when the sum of the fractional working interests we own in gross wells equals one.
Year Ended December 31,
Gross
Net
Gross
Net
Gross
Net
Development Wells:
Productive
5.5
7.2
7.5
Non-Productive
-
-
-
-
-
-
Total
5.5
7.2
7.5
Exploratory Wells:
Productive
-
-
-
-
-
-
Non-Productive
-
-
-
-
-
-
Total
-
-
-
-
-
-
Total Wells:
Productive
5.5
7.2
7.5
Non-Productive
-
-
-
-
-
-
Total
5.5
7.2
7.5
At December 31, 2020, we had 11 gross (4.8 net) development wells waiting to be completed.
Net Production, Unit Prices and Costs
The following table presents certain information with respect to oil and natural gas production attributable to our interests in all of our properties (including two fields which have attributed more than 15% of our total proved reserves as of December 31, 2020), the revenue derived from the sale of such production, average sales prices received and average production costs during each of the years in the three-year period ended December 31, 2020.
Sales Volumes
Average Sales Prices (1)
Average
Natural
Oil &
Natural
Oil &
% of
Production
Gas
Condensate
Total
Gas
Condensate
Total
Total
Cost (2)
Mmcf
MBbls
Mmcfe
Mmcf
MBbls
Mmcfe
Revenue
Per Mcfe
For Year 2020:
TMS
-
$ -
$ 41.61
$ 6.93
%
$ 5.41
Haynesville Shale Trend
48,032
-
48,032
1.82
-
1.82
%
0.18
Other
1.99
60.44
4.95
%
0.74
Total
48,110
48,968
$ 1.82
$ 42.59
$ 1.92
%
$ 0.27
For Year 2019:
TMS
-
1,011
$ -
$ 60.92
$ 10.15
%
$ 5.30
Haynesville Shale Trend
46,436
-
46,436
2.31
-
2.31
%
0.14
Other
3.12
50.28
3.38
%
1.04
Total
46,711
47,737
$ 2.31
$ 60.77
$ 2.48
%
$ 0.26
For Year 2018:
TMS
-
1,289
$ -
$ 68.03
$ 11.34
%
$ 4.37
Haynesville Shale Trend
24,410
-
24,410
2.99
-
2.99
%
0.19
Other
4.18
58.11
5.72
%
2.38
Total
24,444
25,746
$ 2.99
$ 67.93
$ 3.42
%
$ 0.41
(1)
Excludes the impact of commodity derivatives.
(2)
Excludes ad valorem and severance taxes.
Oil and Natural Gas Marketing and Major Customers
Marketing. Our natural gas production is sold under spot or market-sensitive contracts to various natural gas purchasers on short-term contracts. Our oil production is sold to various purchasers under short-term rollover agreements based on current market prices.
Customers. Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2020 and 2019 are as follows:
Year Ended December 31,
CIMA Energy, LP
%
%
ARM Energy Management LLC
%
%
Shell
%
%
CES
%
%
Genesis Crude Oil LP
%
%
ETC Marketing, Ltd
%
%
Symmetry Energy Solutions, LLC
%
%
Competition
The oil and natural gas industry is highly competitive. Major and independent oil and natural gas companies, drilling and production acquisition programs and individual producers and operators are active bidders for desirable oil and natural gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater than ours, and staffs and facilities substantially larger than us.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
Human Capital Resources
The Company’s approach to human capital is a critical strategy with priorities that include, among others: (i) attracting, developing, and retaining a diverse and talented workforce; (ii) providing opportunities for learning, development, career growth, and movement within the Company; (iii) evaluating compensation and benefits, and rewarding performance; (iv) obtaining Employee feedback; (v) maintaining and enhancing Company culture; and (vi) communicating with the Board of Directors on a routine basis on key topics, including executive succession planning. The Company rewards Employees with competitive compensation and benefits packages, including attractive insurance plans and a 401(k) plan.
At February 28, 2021, we had 39 employees in our Houston administrative office and 4 employees in our field offices, all of whom, with the exception of one part-time employee, were full-time and none of whom was represented by any labor union. We regularly use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection, and well testing.
Regulations
The availability of a ready market for any oil and natural gas production depends upon numerous factors beyond our control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or the lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment.
Environmental and Occupational Health and Safety Matters
General
Our operations are subject to stringent and complex federal, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to the protection of the environment and natural resources. Compliance with these laws and regulations may require the acquisition of permits before drilling or other related activity commences, restrict the type, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling and production activities on certain lands lying within wilderness, wetlands and other protected areas, impose specific health and safety criteria addressing worker protection, and impose substantial liabilities for pollution arising from drilling and production operations. Environmental laws and regulations also impose certain plugging and abandonment and site reclamation requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit some or all of our operations.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and, any changes in environmental laws and regulations that result in more stringent and costly well construction, drilling, waste management or completion activities or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business. Environmental laws and regulations change frequently, and there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future.
The following is a summary of the more significant existing environmental laws to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.
Hazardous Substances and Wastes
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred, and companies that disposed or arranged for the disposal of hazardous substances released at the site. Under CERCLA, these persons may be subject to strict, joint and several liabilities for remediation cost at the site, natural resource damages and for the costs of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We generate materials in the course of our operations that are regulated as hazardous substances.
We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes that impose stringent requirements related to the handling and disposal of non-hazardous and hazardous wastes. Wastes, including drilling fluids and produced water, generated in the exploration or production of oil and natural gas are exempt from classification as hazardous wastes under RCRA. Proposals have been made from time to time to eliminate this exemption, which, if adopted, would cause some of these wastes to be regulated under the more rigorous RCRA hazardous waste standards. A loss of this RCRA exemption could result in increased costs to us and the oil and gas industry in general to manage and dispose of generated wastes. Moreover, some ordinary industrial wastes which we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes if they have hazardous characteristics.
We currently own or lease, and in the past have owned or leased, properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes and petroleum hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties whose treatment and disposal of hazardous substances, wastes and petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to undertake costly site investigations, remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
Water Discharges and Subsurface Injections
The Federal Water Pollution Control Act, as amended (“Clean Water Act,” or “CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In September 2015, the EPA and U.S. Army Corps of Engineers (the “Corps”) finalized new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act (the “WOTUS rule”). Several legal challenges to the rule followed, and the WOTUS rule was rescinded in September 2019. On January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrows jurisdiction under the CWA relative to the WOTUS rule. These rulemakings are currently subject to litigation, and it is possible that the Biden Administration could propose a broader definition of WOTUS. Therefore, the scope of jurisdiction under the CWA is uncertain at this time. To the extent any rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The process for obtaining permits has the potential to delay the development of natural gas and oil projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the Oil Pollution Act of 1990, as amended, imposes a variety of requirements related to the prevention of oil spills into navigable waters as well as liabilities for oil cleanup costs, natural resource damages and a variety of public and private damages that may result from such oil spills.
The disposal of oil and natural gas wastes into underground injection wells are subject to the federal Safe Drinking Water Act, as amended (“SDWA”), and analogous state laws. The SDWA’s Underground Injection Control Program establishes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities as well as a prohibition against the migration of fluid containing any contaminants into underground sources of drinking water. State programs may have analogous permitting and operational requirements. In response to concerns related to increased seismic activity in the vicinity of injection wells, regulators in some states are considering additional requirements related to seismic safety. For example, Texas has imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic activities. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to conduct continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position. In addition, any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injury.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Over the years, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. For example, the EPA has taken the issued guidance under the SDWA for hydraulic fracturing activities involving the use of diesel fuel and published final rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. The EPA has not proposed to take any action in response to the report’s findings. Additionally, the Biden Administration has issued orders temporarily suspending the issuance of certain authorizations, and suspending the issuance of new leases, for oil and gas activities on federal lands, though these orders do not impact existing operations on valid leases.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process, and such legislation may be considered again in the future. At the state level, some states where we operate, including Louisiana and Texas, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Moreover, some states and local governments have enacted laws or regulations limiting hydraulic fracturing within their borders or prohibiting the activity altogether. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
Air Emissions
The CAA and comparable state laws regulate emissions of various air pollutants from many sources in the United States, including crude oil and natural gas production activities through air emissions standards, construction and operating programs and the imposition of other compliance requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards, and the agency completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Compliance with these requirements could increase our costs of development and production significantly.
Climate Change
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas (“GHG”) emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, on January 20, 2021, President Biden signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule, and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored Paris Agreement requires member states to submit non-binding, individually-determined emissions reduction goals every five years after 2020. Although the United States withdrew from the Paris Agreement on November 4, 2020, President Biden has signed executive orders recommitting the United States to the agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction goals under the agreement. However, the impacts of these orders and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement remain unclear at this time.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates now in political office. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil fuel energy companies may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas. Additionally, political, litigation and financial risks may result in us restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Finally, it should be noted that many scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other extreme weather events. Such events could disrupt our operations or result in damage to our assets and have an adverse effect on our financial condition and results of operations.
Endangered Species
The Federal Endangered Species Act, as amended (“ESA”), and analogous state laws restrict activities that could have an adverse effect on threatened or endangered species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our operations may be located in or near areas that are designated as habitat for endangered or threatened species. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, as a result of a court settlement, the U.S. Fish and Wildlife Service (“USFWS”) was required to make a determination on listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2017 fiscal year. The USFWS did not complete the review by the deadline and continues to review species for protected status under the ESA. The presence of protected species or the designation of previously unidentified endangered or threatened species could impair our ability to timely complete well drilling and development and could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Employee Health and Safety
We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended, (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, as amended, and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local governmental authorities and citizens.
Other Laws and Regulations
State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and natural gas properties, establishment of maximum rates of production from oil and natural gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and natural gas could otherwise be produced from our properties and may restrict the number of wells that may be drilled on a particular lease or in a particular field.
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and natural gas properties, marketing and midstream activities, and also include those statements accompanied by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “predicts,” “target,” “goal,” “plans,” “objective,” “potential,” “should,” or similar expressions or variations on such expressions that convey the uncertainty of future events or outcomes. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; the Company undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.
These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:
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public health crises, such as the Coronavirus Disease 2019 ("COVID-19") outbreak in 2020, which has negatively impacted the global economy, and correspondingly, the price of oil and natural gas;
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the market prices of oil and natural gas;
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volatility in the commodity-futures market;
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financial market conditions and availability of capital;
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future cash flows, credit availability and borrowings;
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sources of funding for exploration and development;
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our financial condition;
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our ability to repay our debt;
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the securities, capital or credit markets;
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planned capital expenditures;
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future drilling activity;
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uncertainties about the estimated quantities of our oil and natural gas reserves and production from our wells;
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the creditworthiness of our hedging counterparties and the effect of our hedging arrangements;
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litigation matters;
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pursuit of potential future acquisition opportunities;
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general economic conditions, either nationally or in the jurisdictions in which we are doing business;
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legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations;
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the creditworthiness of our financial counterparties and operating partners; and
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other factors discussed below and elsewhere in this Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

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ITEM 1A. RISK FACTORS
Item 1A.
Risk Factors
The risks described in this Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Business and Operating Risks
Oil and natural gas prices are volatile. A sustained decrease in the price of oil or natural gas, including price decreases caused by the COVID-19 pandemic, would adversely impact our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
Our success depends on the market prices of oil and natural gas. These market prices tend to fluctuate significantly in response to factors beyond our control. The prices we receive for our crude oil production are based on global market conditions. The general pace of global economic growth, the continued instability in the Middle East and other oil and natural gas producing regions and actions of OPEC, as well as other economic, political, and environmental factors will continue to affect world supply and prices of oil. Domestic natural gas prices fluctuate significantly in response to numerous factors including U.S. economic conditions, weather patterns, other factors affecting demand such as substitute fuels, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that limit future drilling activities for the industry.
Market prices of oil and natural gas have been adversely affected by the ongoing outbreak of COVID-19, which has also adversely impacted and is expected to continue to adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas. A significant majority of states as well as local jurisdictions have imposed, and others in the future may impose, “shelter-in-place” orders, quarantines, executive orders and similar government orders and restrictions for their residents to control the spread of COVID-19. Such orders or restrictions, and the perception that such orders or restrictions could occur, have resulted in business closures, work stoppages, slowdowns and delays, work-from-home policies, travel restrictions and cancellation of events, among other effects. Such effects and restrictions have decreased the demand for oil and natural gas, resulting in a sustained decrease in the market prices of such commodities.
During the period from January 1, 2014 to December 31, 2020, average daily prices for NYMEX Henry Hub natural gas ranged from a high of $6.00 per MMBtu to a low of $1.63 per MMBtu and NYMEX WTI oil prices ranged from a high of $107.26 per Bbl to a low of $10.01 per Bbl. The market for these products will likely continue to be volatile in the future. Our revenues, operating results, profitability and future growth are highly dependent on the prices we receive for our production, and the levels of our production depend on numerous factors beyond our control. These factors include the following:
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public health crises, such as the COVID-19 outbreak at the beginning of 2020, which has negatively impacted the global economy, and correspondingly, the price of crude oil;
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worldwide and regional economic conditions impacting the supply and demand for oil and natural gas;
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the level of global oil and natural gas exploration and production;
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the level of global inventories;
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prevailing prices on local price indices in the areas in which we operate and expectations about future commodity prices;
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the extent of natural gas production associated with increased oil production;
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the proximity, capacity, cost and availability of gathering and transportation facilities;
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localized and global supply and demand fundamentals and transportation availability;
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weather conditions across North America and, increasingly due to liquified natural gas, across the globe;
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technological advances affecting energy consumption;
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risks associated with operating drilling rigs;
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speculative trading in commodity markets;
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end user conservation trends;
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petrochemical, fertilizer, ethanol, transportation supply and demand balance;
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the price and availability of alternative fuels;
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domestic, local and foreign governmental regulation and taxes; and
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liquefied petroleum products supply and demand balances.
Changes in commodity prices significantly affect our capital resources, liquidity and expected operating results. The extent to which COVID-19 and depressed crude oil prices impacts our business, financial condition, or results of operations will depend on future developments, such as the availability of effective treatments and vaccines, which are highly uncertain and cannot be predicted.
Lower commodity prices will reduce our cash flows and borrowing ability and may require us to curtail exploration, drilling and production activity. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil and natural gas that we can produce economically. We have historically been able to hedge our natural gas production at prices that are higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may be limited. Additionally, declines in prices could result in non-cash charges to earnings due to impairment write downs. Any such write down could have a material adverse effect on our results of operations in the period taken.
Our future revenues are dependent on the ability to successfully complete drilling activity.
Drilling and exploration are the main methods we utilize to replace our reserves. However, drilling and exploration operations may not be successful or may not result in the levels of production or reserves we have estimated. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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reductions in oil and natural gas prices;
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inadequate capital resources;
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limitations in the market for oil and natural gas;
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lack of acceptable prospective acreage;
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents;
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unavailability or high cost of drilling rigs, equipment or labor;
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title problems;
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compliance with governmental regulations;
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mechanical difficulties; and
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risks associated with horizontal drilling.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain.
In addition, while lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically, higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increased costs for, such drilling equipment, services and personnel. Such shortages could restrict our ability to drill the wells and conduct the operations that we currently have planned, and increased costs could reduce the profitability of our operations. Any delay in the drilling of new wells or significant increases in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues.
Because our operations require significant capital expenditures, we may not have the funds available to replace reserves, maintain production or maintain interests in our properties.
We must make a substantial amount of capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. In recent years, we have paid for these expenditures with cash from operating activities and, to a lesser extent, borrowings under our 2019 Senior Credit Facility (as described below). Our revenues and cash flows are subject to a number of variables, including:
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our proved reserves;
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the volume of hydrocarbons we are able to produce from existing wells;
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the prices at which our production is sold;
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our ability to acquire, locate and produce new reserves;
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the extent and levels of our derivative activities;
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the levels of our operating expenses; and
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our ability to borrow under our 2019 Senior Credit Facility.
If our revenues or cash flows decrease, we may not have the funds available to replace reserves or maintain production at current levels. If this occurs, our production will decline over time. Other sources of financing may not be available to us to the extent required or on acceptable terms if our cash flows from operations are not sufficient to fund our capital expenditure requirements. If funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, where we are not the majority owner or operator of an oil and natural gas property, we may have no control over the timing or amount of capital expenditures associated with the particular property, and expenditures we are required to pay or reimburse may be incurred at times we cannot control. If we cannot fund such capital expenditures, our interests in some properties may be reduced or forfeited.
If we are unable to or do not otherwise replace reserves, we may not be able to sustain production at present levels.
Our future success depends largely upon our ability to find, acquire or develop additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. At December 31, 2020, 71% of our total estimated proved reserves by volume were undeveloped. By their nature, estimates of proved undeveloped reserves and timing of their production are less certain particularly because we may choose not to develop such reserves on anticipated schedules in lower oil or natural gas price environments. In addition, recovery of such reserves will require significant capital expenditures and successful drilling operations. The lack of availability of sufficient capital to fund such future operations could materially hinder or delay our replacement of produced reserves. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.
Our ability to sell natural gas and receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.
We operate primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend and (ii) Southwest Mississippi and Southeast Louisiana, which includes the TMS. A number of companies are currently operating in the Haynesville Shale Trend. If drilling in these areas continues to be successful, the amount of natural gas being produced could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in this region. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for Northwest Louisiana and East Texas may not occur or may be substantially delayed for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our natural gas to interstate pipelines. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gas production at significantly lower prices than those quoted on NYMEX or that we currently project, which would adversely affect our results of operations.
A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, the interruption could temporarily adversely affect our cash flow.
The oil and natural gas exploration and production business involves many uncertainties, economic risks and operating risks that can prevent us from realizing profits and can cause substantial losses.
The nature of the oil and natural gas exploration and production business involves certain operating hazards such as:
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well blowouts;
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cratering;
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explosions;
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uncontrollable flows of oil, natural gas, brine or well fluids;
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fires;
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formations with abnormal pressures;
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shortages of, or delays in, obtaining water for hydraulic fracturing operations;
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environmental hazards such as crude oil spills;
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natural gas leaks;
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pipeline and tank ruptures;
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unauthorized discharges of brine, well stimulation and completion fluids or toxic gases into the environment;
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encountering naturally occurring radioactive materials; and
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other pollution, hazards and risks.
Any of these operating hazards could result in substantial losses to us. As a result, substantial liabilities to third parties or governmental entities may be incurred. The payment of these amounts could reduce or eliminate the funds available for exploration, development or acquisitions. These reductions in funds could result in a loss of our properties. Additionally, some of our oil and natural gas operations are located in areas that are subject to weather disturbances such as hurricanes. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production.
Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve report. These differences may be material.
The proved oil and natural gas reserve information included in this Annual Report on Form 10-K are estimates. These estimates are based on reports prepared by NSAI and RSC, our independent reserve engineers, and were calculated using the unweighted average of first-day-of-the-month oil and natural gas prices in 2020. The prices we receive for our production may be lower than those upon which our reserve estimates are based. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:
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historical production from the area compared with production from other similar producing wells;
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the assumed effects of regulations by governmental agencies;
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assumptions concerning future oil and natural gas prices; and
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assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:
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the quantities of oil and natural gas that are ultimately recovered;
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the production and operating costs incurred;
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the amount and timing of future development expenditures; and
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future oil and natural gas sales prices.
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this Annual Report on Form 10-K should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the standardized measure of discounted future net cash flows from proved reserves are generally based on 12-month average prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
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the amount and timing of actual production;
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supply and demand for oil and natural gas;
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increases or decreases in consumption; and
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changes in governmental regulations or taxation.
In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, and which we use in calculating our PV-10, may not necessarily be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could materially adversely affect our financial condition, results of operations and cash flows.
Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from the largest of these purchasers as a percent of oil and natural gas revenues for the years ended December 31, 2020 and 2019 were 41% and 39%, respectively. Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our financial condition, results of operations and cash flows. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.
A majority of our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
Essentially all of our estimated proved reserves at December 31, 2020 were associated with our Louisiana, Texas and Mississippi properties which include the Haynesville Shale Trend and, to a lesser extent, the TMS. Accordingly, if the level of production from these properties substantially declines or is otherwise subject to a disruption in our operations resulting from operational problems, government intervention (including potential regulation or limitation of the use of high pressure fracture stimulation techniques in these formations) or natural disasters, it could have a material adverse effect on our overall production level and our revenue.
Competition in the oil and natural gas industry is intense, and we are smaller and have more limited operating resources than some of our competitors.
We compete with major and independent oil and natural gas companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources than us. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for oil and natural gas properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing 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.
Our business could be adversely affected by security threats, including cybersecurity threats.
As a producer of crude oil and natural gas, we face various security threats, including cybersecurity threats to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition and results of operations. For example, unauthorized access to our reserves information or other proprietary information could lead to data corruption, communication interruptions, or other disruptions to our operations.
Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position and results of operations.
We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flows and ability to complete development activities as planned.
Historically, our capital and operating costs have risen during periods of increasing oil and natural gas prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flows and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. For example, Chesapeake operates certain of our properties in the Haynesville Shale Trend. As of December 31, 2020, approximately 11% of our reserves and approximately 13% of our sales volumes were attributable to non-operated properties. We have less ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them versus those fields in which we are the operator. Although we have the ability to propose operations to the operator, our dependence on the operator and other working interest owners for these projects, and our reduced influence or ability to control the operation and future development of these properties, could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.
Events of force majeure may limit our ability to operate our business and could adversely affect our operating results.
The weather, unforeseen events, or other events of force majeure in the areas in which we operate could cause disruptions and, in some cases, suspension of our operations. This suspension could result from a direct impact to our properties or result from an indirect impact by a disruption or suspension of the operations of those upon whom we rely for gathering and transportation. If disruption or suspension were to persist for a long period, our results of operations would be materially impacted.
We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them.
The acquisition of properties requires us to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well, facility or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion or subsurface groundwater contamination, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities relating to the acquired assets and indemnities are unlikely to cover liabilities relating to the time periods after closing. We may be required to assume any risk relating to the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. The incurrence of an unexpected liability could have a material adverse effect on our financial position and results of operations.
The ability to attract and retain key personnel is critical to the success of our business.
The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity and business operations could be adversely affected.
Financial Risks
We have incurred losses from operations and may continue to do so in the future.
We had an operating loss of $41.7 million for the year ended December 31, 2020 inclusive of a $36.1 million impairment of oil and natural gas properties and an operating income of $11.1 million for the year ended December 31, 2019. We had accumulated deficit of $41.4 million as of December 31, 2020. Our development of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this Annual Report on Form 10-K may impede our ability to economically acquire and develop oil and natural gas reserves. As a result, we may not be able to sustain profitability or positive cash flows provided by operating activities in the future.
We may be unable to maintain compliance with the financial maintenance or other covenants in the 2019 Senior Credit Facility and 2023 Second Lien Notes, which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.
Our 2023 Second Lien Notes (as defined below) and our 2019 Senior Credit Facility (as defined below), contain various affirmative and negative covenants with which we must comply. For example, under the 2019 Senior Credit Facility, we are required to maintain certain financial covenants including the maintenance of (i) a ratio of Net Funded Debt (as defined in the 2019 Senior Credit Facility) to EBITDAX not to exceed 3.50 to 1.00 as of the last day of any fiscal quarter and (ii) a current ratio (based on the ratio of current assets plus availability under the current borrowing base to current liabilities) not to be less than 1.00 to 1.00 and (iii) until no 2023 Second Lien Notes remain outstanding, a ratio of Total Proved PV-10 attributable to the Company's and Subsidiary's Proved Reserves (as defined in the 2019 Senior Credit Facility) to Total Secured Debt (net of any Unrestricted Cash not to exceed $10.0 million) not to be less than 1.50 to 1.00.
The 2019 Senior Credit Facility also contains certain covenants which, among other things, and subject to certain exceptions, restrict the Company’s and certain of its subsidiaries’ ability to incur additional debt or liens, pay dividends, repurchase equity interests, prepay other indebtedness, sell, transfer, lease or dispose of assets, and make investments in or merge with another company.
If the Company were to violate any of the covenants under the 2019 Senior Credit Facility and were unable to obtain a waiver, it would be considered a default after the expiration of any applicable grace period. If the Company were in default under the 2019 Senior Credit Facility, then we would no longer be permitted to borrow under that facility and the lenders thereunder may exercise remedies in accordance with the terms thereof, including declaring all outstanding borrowings immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due.
Customer credit risks could result in losses.
Our exposure to non-payment or non-performance by our customers and counterparties presents a credit risk. Generally, non-payment or non-performance results from a customer’s or counterparty’s inability to satisfy obligations. We monitor the creditworthiness of our customers and counterparties and establish credit limits according to our credit policies and guidelines, but cannot assure that any losses will be consistent with our expectations. Furthermore, the concentration of our customers in the energy industry may impact our overall exposure to credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2020 and 2019 are as follows:
Year Ended December 31,
CIMA Energy, LP
%
%
ARM Energy Management LLC
%
%
Shell
%
%
CES
%
%
Genesis Crude Oil LP
%
%
ETC Marketing, Ltd
%
%
Symmetry Energy Solutions, LLC
%
%
Our use of oil and natural gas price hedging contracts may limit future revenues from price increases and result in significant fluctuations in our net income.
We have historically used hedging transactions with respect to a portion of our oil and natural gas production in an effort to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases. We had positive net cash settlements of $15.2 million during 2020 and positive net cash settlements of $9.6 million during 2019.
We account for our oil and natural gas derivatives using fair value accounting standards. Each derivative is recorded on the balance sheet as an asset or liability at its fair value. Additionally, changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met at the time the derivative contract is executed. We have elected not to apply hedge accounting treatment to our swap and call derivative contracts and, as such, all changes in the fair value of these instruments are recognized in earnings. Our fixed price physical contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment.
In the future, we will continue to be exposed to volatility in earnings resulting from changes in the fair value of our derivative instruments. See Note 9-Derivative Activities in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
The exercise of all or any number of outstanding warrants or the issuance of share-based awards may dilute your holding of shares of our common stock.
As of March 9, 2021, we have outstanding (i) 910,790 warrants exercisable into approximately 1.3 million shares of the Company's common stock at an exercise price of $15.52 per share, (ii) 2023 Second Lien Notes convertible into approximately 1.4 million shares of the Company's common stock at an exercise price of $21.33, and (iii) approximately 305,442 restricted stock awards at target, collectively representing in total approximately 19% of our shares on a fully diluted basis. The exercise of equity awards, including any stock options that we may grant in the future, and warrants and the sale of shares of our common stock underlying any such options or the warrants, could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares. Investors may experience dilution in the net tangible book value of their investment upon the exercise of the warrants and any stock options that may be granted or issued pursuant to the warrants in the future.
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities, including outstanding options, will dilute the ownership interest of our common stockholders. In addition, a significant amount of our common stock is owned by a limited number of holders, many of which received the shares that they own when we emerged from bankruptcy or in financing transactions following such emergence. We have filed registration statements under which many of these holders may sell shares of our common stock. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.
Derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity prices, interest rates and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the “Dodd-Frank Act”), among other things, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Commodity Futures Trading Commission (“CFTC”) has finalized certain of its regulations under the Dodd-Frank Act, but others remain to be finalized or implemented. It is not possible at this time to predict when this will be accomplished or what the terms of the final rules will be, so the impact of those rules is uncertain at this time.
The CFTC has designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future. To the extent we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply or to take steps to qualify for an exemption to such requirements. Although we are availing ourselves of the end-user exception to the mandatory clearing and exchange trading requirements for swaps designed to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract market or swap executive facility.
In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, we could be required to post initial or variation margin, which would impact liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash flows.
The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing commodity price contracts. If we reduce our use of commodity price contracts as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and make cash distributions to our unitholders. Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.
We may incur substantial impairment writedowns.
If management’s estimates of the recoverable proved reserves on a property are revised downward or if oil and natural gas prices decline, we may be required to record non-cash impairment writedowns, which would result in a negative impact to our earnings and financial position. We account for our oil and natural gas properties under the Full Cost Method of Accounting (the “Full Cost Method”). The Full Cost Method requires a ceiling test be performed each quarter to determine whether an impairment exists. The reserve value basis used in the ceiling test is the SEC calculated reserves. The SEC value of reserves utilizes a look back at the last twelve month commodity prices. We recorded a $36.1 million impairment for the year ended December 31, 2020, while we had no impairment for the year ended December 31, 2019.
We do not currently pay a dividend.
We do not currently pay cash dividends or other distributions with respect to our common stock. In addition, restrictive covenants in certain debt instruments to which we are, or may be, a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.
There is a limited trading market for our securities and the market price of our securities is subject to volatility.
Our common stock is listed on the NYSE American. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our limited trading volume, the concentration of holdings of our common stock, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A of this Annual Report on Form 10-K. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. Due to the concentration of holdings of our common stock, holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.
The ownership position of our larger stockholders may limit other stockholders’ ability to influence corporate matters and could affect the price of our common stock.
As of February 28, 2021, our largest three stockholders collectively beneficially own approximately 42% of our outstanding common stock. As a result, these stockholders will be able to exercise significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of these stockholders with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. Moreover, the concentration of stock ownership may adversely affect the trading price of our common stock as a result of lower public float or if investors perceive a disadvantage in owning stock of a company with a significant concentration of ownership.
Legal or Regulatory Risks
We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.
We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:
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personal injury;
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bodily injury;
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third party property damage;
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medical expenses;
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legal defense costs;
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pollution in some cases;
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well blowouts in some cases; and
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workers compensation.
As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material adverse effect on our financial position and results of operations. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover every claim made against us in the future. A loss in connection with our oil and natural gas properties could have a material adverse effect on our financial position and results of operations to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.
Our operations are subject to governmental risks that may impact our operations.
Our operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, local and other laws and regulations such as restrictions on production, permitting and changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies or price gathering-rate controls. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our oil and natural gas exploration and production operations are subject to stringent and complex federal, regional, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety aspects of our operations, or otherwise relating to the protection of the environment and natural resources. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of permits, including drilling permits, before conducting regulated activities; plugging and abandonment and site reclamation requirements; the restriction of types, quantities and concentration of materials that can be released into the environment; limiting or prohibiting drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liabilities for the removal or remediation of previously released materials or property contamination. Failure to comply with environmental laws and regulations may result in the assessment of civil and criminal fines and penalties, the revocation of permits or the issuance of injunctions restricting or prohibiting our operations in certain areas. Moreover, private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently and the clear trend has been to place increasingly stringent limitations on activities that may affect the environment. Any changes in legal requirements related to the protection of the environment could result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements. Such changes could also require us to make significant expenditures to attain and maintain compliance, and also have the potential to reduce demand for the oil and gas we produce and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as government reviews of such activity could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Over the years, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. For example, the EPA has issued guidance under the SDWA for hydraulic fracturing activities involving the use of diesel fuel and finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. The EPA has not proposed to take any action in response to the report’s findings. Additionally, the Biden Administration has issued orders temporarily suspending the issuance of certain authorizations, and suspending the issuance of new leases, for oil and gas activities on federal lands, though these orders do not impact existing operations on valid leases.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process, and such legislation may be considered again in the future. At the state level, some states where we operate, including Louisiana and Texas, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. There has also been increased public scrutiny of seismic events in areas where hydraulic fracturing of wastewater disposal activities occur. Moreover, some states and local governments have enacted laws or regulations limiting hydraulic fracturing within their borders or prohibiting the activity altogether. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for our products.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, on January 20, 2021, President Biden signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule, and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored Paris Agreement requires member states to submit non-binding, individually-determined reduction goals every five years after 2020. Although the United States withdrew from the Paris Agreement on November 4, 2020, President Biden has signed executive orders recommitting the United States to the agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction goals under the agreement. However, the impacts of these orders and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement remain unclear at this time.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates now in political office. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across agencies and economic sectors. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts to their investors or customers.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil fuel energy companies may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced it had joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas. Additionally, political, litigation and financial risks may result in us restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Finally, it should be noted that many scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other extreme weather events. Such weather events could disrupt our operations or result in damages to our assets and have an adverse effect on our financial condition and results of operations.
Certain provisions of our Charter and our Bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Third Amended and Restated Certificate of Incorporation (“Charter”) and our Second Amended and Restated Bylaws (“Bylaws”) may have the effect of delaying or preventing changes in control if our board of directors (“Board”) determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Charter and Bylaws include, among other things, those that:
•
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
•
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and
•
limit the persons who may call special meetings of stockholders.
While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B.
Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3.
Legal Proceedings
A discussion of our current legal proceedings is set forth in Note 10-Commitments and Contingencies in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4.
Mine Safety Disclosures
Not Applicable.
PART II

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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.
Market Price of Our Common Stock
The Company's common stock trades on the NYSE American under the symbol “GDP”.
At March 9, 2021, the number of holders of record of our common stock was 90 and 13,402,291 shares were outstanding.
Dividends
We do not currently pay any dividends on our common stock.
Issuer Repurchases of Equity Securities
No private or open market repurchases of our common stock were made by or on our behalf or that of any affiliated purchaser for the year ended December 31, 2020.
For information on securities authorized for issuance under our equity compensation plans, see “Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
Unregistered Sales of Equity Securities
None that have not been previously reported by us on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6.
Selected Financial Data
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Annual Report on Form 10-K in “Item 8 - Financial Statements and Supplementary Data,” and the information set forth in “Part I, Item 1A - Risk Factors.”
Overview
We are an independent oil and natural gas company engaged in the exploration, development and production of properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.
We seek to increase shareholder value by growing our oil and natural gas reserves, production, revenues and cash flow from operating activities (“operating cash flow”). In our opinion, on a long term basis, growth in oil and natural gas reserves, cash flow and production on a cost-effective basis are the most important indicators of performance success for an independent oil and natural gas company.
Management strives to increase our oil and natural gas reserves, production and cash flow through exploration and development activities. We develop an annual capital expenditure budget, which is reviewed and approved by our Board of Directors (the “Board”) on a quarterly basis and revised throughout the year as circumstances warrant. When establishing our capital expenditure budget, we take into consideration our projected operating cash flow, commodity prices for oil and natural gas and externally available sources of financing, such as bank debt, asset divestitures, issuance of debt and equity securities and strategic joint-ventures.
We place primary emphasis on our operating cash flow in managing our business. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of hedging gains (losses) that have not yet been settled, non-cash general and administrative expenses and impairments.
Our revenues and operating cash flow depend on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and natural gas. The prices we receive for our production are largely beyond our control, and in the first half of 2020, the NYMEX Henry Hub price for natural gas hit a five-year low. We have historically been able to hedge our natural gas production at prices that are higher than current strip prices. However, depending on volatility in the commodity price environment, our ability to enter into comparable derivative arrangements may be more limited. See “Item 1A - Risk Factors” for a discussion of the risks to our business as a result of lower commodity prices.
The Coronavirus Disease 2019 (“COVID-19”) pandemic and related economic repercussions have created significant volatility, uncertainty and turmoil in the oil and gas industry. Throughout 2020, the effect of COVID-19 lowered the demand for oil and natural gas which resulted in an oversupply of crude oil with significant downward pressure on oil and natural gas prices for much of the year. West Texas Intermediate crude oil closed at $21 per barrel on March 31, 2020 and generally remained at that level or lower through May 2020. In the third and fourth quarters of 2020, we experienced gradual increases in oil and natural gas prices although not enough to alleviate the oversupply caused by lack of demand caused by COVID-19. The ultimate magnitude and duration of the COVID-19 pandemic, resulting governmental restrictions placing limitations on the mobility and ability to work of the worldwide population and the related impact on crude oil prices, and the U.S. and global economy and capital markets remains uncertain. Because we predominately produce natural gas, and natural gas has not been impacted by the same market forces as crude oil, we have experienced less of an impact from COVID-19 than many of our peers. However, the scope and length of the COVID-19 pandemic and the ultimate effect on the price of natural gas cannot be determined, and we could be adversely affected in future periods.
To mitigate the effects of the downturn in commodity prices due to the effects of COVID-19, we reduced our capital expenditures for 2020 thereby conserving capital. We also initiated a company-wide cost reduction program eliminating outside services that are not core to our business. Additionally, we have substantial volumes of our production favorably hedged through the first quarter of 2022.
As a result of the steps we have taken to enhance our liquidity, we anticipate our cash on hand, cash from operations, 2023 Second Lien Notes and our available borrowing capacity under our 2019 Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements into 2021.
We remain committed to the following priorities while navigating the COVID-19 pandemic:
•
Ensuring the health and safety of our employees and the contractors that provide services to us;
•
Continuing to monitor the impact the COVID-19 pandemic has on demand for our products in addition to related commodity price impacts in order to adjust our business accordingly; and
•
Ensuring we emerge from the COVID-19 pandemic and current oil and natural gas price environment in as strong of a position as possible as we continue to move forward with our long-term strategies.
While the COVID-19 pandemic may potentially adversely affect our operations or employees’ health in the future, as of the date of this filing, we have not experienced a significant disruption to our operations and we have implemented a contingency plan, with employees working remotely where possible and in compliance with governmental orders and CDC recommendations.
Business Strategy
Our business strategy is to provide long-term growth in reserves and cash flow on a cost-effective basis. We focus on maximizing our return on capital employed and adding reserve value through the timely development of our Haynesville Shale Trend acreage. We regularly evaluate possible acquisitions of prospective acreage and oil and natural gas drilling opportunities.
Several of the key elements of our business strategy are the following:
Develop existing property base. We seek to maximize the value of our existing assets by developing and exploiting our properties that we have identified as having the lowest risk and the highest potential rates of return. To accomplish this strategy, we currently intend to develop our multi-year inventory of drilling locations and natural gas reserves on our Haynesville Shale Trend acreage.
Increase our natural gas production. We have concentrated on increasing our natural gas production and reserves by investing and drilling in the Haynesville Shale Trend. We intend to continue to take advantage of improved completion technology to increase production volumes and reduce our per unit operating expenses.
Expand acreage position in the Haynesville Shale Trend. As of December 31, 2020, we held approximately 26,000 net acres in the Haynesville Shale Trend. In addition to having significant experience in the play, we intend to have significant operational control of our Haynesville Shale Trend assets. To leverage our extensive regional knowledge base, we seek to acquire leasehold acreage with significant drilling potential in areas that exhibit characteristics similar to our existing properties. We also continually strive to rationalize our portfolio of properties by selling marginal non-core properties in an effort to redeploy capital to exploitation, development and exploration projects that offer potentially higher overall returns.
Focus on maximizing cash flow margins. We intend to maximize operating cash flow by focusing on higher-margin natural gas development in the Haynesville Shale Trend. In the current commodity price environment, our Haynesville Shale Trend assets offer more attractive rates of return on capital invested and cash flow margins than our oil assets.
Maintain financial flexibility. As of December 31, 2020, we had $1.4 million in cash and $96.4 million of outstanding borrowings with $23.6 million of availability under the 2019 Senior Credit Facility borrowing base of $120 million. We plan on funding growth primarily through operating cash flow. We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, including fixed price swaps, costless collars and basis swaps. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating results.
Overview of 2020 Results
•
We grew production by 3% in 2020 as we conducted drilling or completion operations on 25 wells, adding 16 gross (5.5 net) wells to production in the Haynesville Shale Trend;
•
We grew reserves by 5% to 543 Bcfe of proved oil and natural gas reserves with a PV-10 of $183 million; and
•
We delivered $58.9 million of net cash provided by operating activities.
Haynesville Shale Trend
Our relatively low risk development acreage in this trend is primarily centered in Caddo, DeSoto and Red River parishes, Louisiana and Angelina and Nacogdoches counties, Texas. We held approximately 49,000 gross (26,000 net) acres as of December 31, 2020 producing from or prospective for the Haynesville Shale Trend. We incurred drilling or completion costs on 25 wells in 2020, spending $56.5 million of which $0.1 million was leasehold cost. We added 16 gross (5.5 net) wells to production in 2020. Our net production volumes from our Haynesville Shale Trend wells represented approximately 98% of our total equivalent production on a Mcfe basis and substantially all of our total natural gas production for the year ended December 31, 2020.
Tuscaloosa Marine Shale Trend
We held approximately 48,000 gross (33,000 net) acres in the TMS as of December 31, 2020 all held by production. During 2020, we did not conduct any drilling operations in the TMS; however, we had 2 gross (1.7 net) wells drilled in 2015, which are still waiting on completion. Our net production volumes from our TMS wells represented approximately 2% of our total equivalent production on a Mcfe basis and approximately 95% of our total oil production for the year ended December 31, 2020. During 2020, we did not spend any capital in the TMS; however, we did spend $0.6 million on workover expense activities to maintain volumes on producing wells.
Eagle Ford Shale Trend
As of December 31, 2020, we retained approximately 4,000 net acres of undeveloped leasehold in the Eagle Ford Shale Trend in Frio County, Texas.
Results of Operations
For the year ended December 31, 2020, we reported a net loss of $44.1 million, or ($3.50) per share (basic and diluted), on oil and gas revenues of $93.8 million. This compares to net income of $13.3 million, or $1.09 per share (basic) and $0.96 per share (diluted) for the year ended December 31, 2019. The items that had the most material financial effect on our net loss for the year ended December 31, 2020 were decreased oil and gas revenues in the year as well as a non-cash impairment charge of $36.1 million. These were offset by gains on derivatives not designated as hedges for the year ended December 31, 2020 of $4.4 million. These items can be primarily attributed to a decrease in market prices during 2020 offset by increased production volumes from new wells brought online.
The recurring items that had the most material financial effect on our net income for the year ended December 31, 2019 were increased oil and gas revenues offset by increased transportation and processing cost and increased depreciation, depletion and amortization cost. Additionally, we incurred gains on derivatives not designated as hedges for the year ended December 31, 2019 of $15.0 million. All of these items could be primarily attributed to our increased production volumes and our derivative contracts entered into to manage commodity price risk.
The following table reflects our summary operating information for the periods presented in thousands except for price and volume data. Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results.
Year Ended December 31,
Year Ended December 31,
Summary Operating Information:
Variance
Revenues:
Natural gas
$ 87,704
$ 107,966
$ (20,262 )
(19 %)
Oil and condensate
$ 6,089
$ 10,387
$ (4,298 )
(41 %)
Natural gas, oil and condensate
$ 93,793
$ 118,353
$ (24,560 )
(21 %)
Net Production:
Natural gas (Mmcf)
48,110
46,712
1,398
%
Oil and condensate (MBbls)
(28 )
(16 %)
Total (Mmcfe)
48,968
47,737
1,231
%
Average daily production (Mcfe/d)
133,792
130,787
3,005
%
Average Realized Sales Price Per Unit:
Natural gas (per Mcf)
$ 1.82
$ 2.31
$ (0.49 )
(21 %)
Natural gas (per Mcf) including the effect of realized gains/losses on derivatives
$ 2.11
$ 2.53
$ (0.42 )
(17 %)
Oil and condensate (per Bbl)
$ 42.59
$ 60.77
$ (18.18 )
(30 %)
Oil and condensate (per Bbl) including the effect of realized gains/losses on derivatives
$ 53.66
$ 56.78
$ (3.12 )
(5 %)
Average realized price (per Mcfe)
$ 1.92
$ 2.48
$ (0.56 )
(23 %)
Oil and Natural Gas Revenue
Natural gas, oil and condensate revenues decreased $24.6 million during the year ended December 31, 2020 compared to the prior year period in 2019 reflecting a decrease in realized sales prices for natural gas, oil and condensate and decreased oil production, offset by an increase in natural gas production from new wells brought online during 2020. Decreased realized prices and decreased oil and condensate production reduced revenues by $25.9 million and $1.2 million, respectively, compared to 2019, while increased natural gas production contributed approximately $2.5 million of additional revenues. The increase in natural gas production volumes was attributed to 16 gross (5.5 net) Haynesville Shale Trend wells put on production during 2020. We continue to concentrate our operational activities and resources on increasing natural gas production in the Haynesville Shale Trend. For the years ended December 31, 2020 and 2019, 94% and 91%, respectively, of our oil and natural gas revenue was attributable to natural gas sales.
In 2020, we received a net $13.6 million on natural gas derivative settlements on a daily average of approximately 70,000 MMBtu with a weighted average fixed price of $2.60 per MMBtu and received a net $1.6 million on oil derivative settlements on a daily average of 220 barrels at a weighted average price of $58.84 per barrel. In 2019, we received a net $10.3 million on natural gas derivative settlements on a daily average of approximately 95,000 MMBtu with a weighted average fixed price of $2.90 per MMBtu and paid a net $0.7 million on oil derivative settlements on a daily average of 312 barrels at a weighted average price of $51.08 per barrel.
Operating Expenses
(in thousands)
Year Ended December 31,
Year Ended December 31,
Variance
Lease operating expenses
$ 13,001
$ 12,371
$
%
Production and other taxes
2,751
2,573
%
Transportation and processing
19,055
20,703
(1,648 )
(8 %)
Per Mcfe
Year Ended December 31,
Year Ended December 31,
Variance
Lease operating expenses
$ 0.27
$ 0.26
$ 0.01
%
Production and other taxes
$ 0.06
$ 0.05
$ 0.01
%
Transportation and processing
$ 0.40
$ 0.43
$ (0.03 )
(7 %)
Lease Operating Expense
Lease operating expense (“LOE”) increased $0.6 million to $13.0 million during the year ended December 31, 2020 compared to the prior year period. On a per unit basis, the cost of production increased by 4% to $0.27 per Mcfe for the year ended December 31, 2020. The increase in LOE between years was attributable primarily to increased workover expense and higher variable lease operating costs due to increased natural gas production in 2020, while fixed expenses remained relatively flat between years. We incurred $2.2 million in workover expense in 2020 and $1.3 million in 2019. The majority of the workover expense incurred in 2020 was in our Thornlake area, and both years incurred workover expense attributed to our TMS wells, in an effort to maintain our natural gas and oil production on producing wells in these areas. Lease operating expense exclusive of workover expense on a per unit basis decreased to $0.22 per Mcfe for 2020 from $0.23 per Mcfe for 2019. Per unit LOE is expected to continue to decrease as we increase production in the Haynesville Shale Trend, which carries a lower per unit LOE than the Company’s current per unit rate.
Production and Other Taxes
Production and other taxes includes severance and ad valorem taxes. Severance taxes were $1.9 million for the year ended December 31, 2020, which increased by $0.3 million compared to the prior year period. The State of Louisiana has enacted an exemption from the existing 12.5% severance tax on oil and from the $0.122 per Mcf (from July 1, 2018 through June 30, 2019), $0.125 per Mcf (from July 1, 2019 through June 30, 2020) and $0.0934 per Mcf (from July 1, 2020 to June 30, 2021) severance tax on natural gas for horizontal wells with production commencing after July 31, 1994. The exemption is applicable until the earlier of (i) 24 months from the date of first sale of production or (ii) payout of the well. Our recently drilled Haynesville Shale Trend wells in Northwest Louisiana are benefiting from this exemption. Severance taxes in 2020 were higher due to taxes incurred on certain wells as they reach payout or 24 months from the date of first production. Ad valorem taxes were $0.9 million for the year ended December 31, 2020, which was a decrease of $0.1 million compared to the prior year period due to more favorable tax calculation methodologies on certain of our properties with respective taxing agencies.
Transportation and Processing
Our natural gas production incurs substantially all of our transportation and processing cost. Transportation and processing expenses for the year ended December 31, 2020 decreased $1.6 million despite an increase in production volumes for the year. Our natural gas volumes from operated wells generally carry less transportation cost than those from wells we do not operate, and the decrease in transportation and processing expenses resulted from increases in operated production. For the same reason, our per unit transportation cost per Mcfe cost also decreased for 2020 when compared to the prior year period. Our per unit transportation cost will continue to decrease as we increase our operated natural gas production under more favorable transportation contracts and from areas with more favorable lease terms.
(in thousands)
Year Ended December 31,
Year Ended December 31,
Variance
Depreciation, depletion & amortization
$ 46,603
$ 50,722
$ (4,119 )
(8 %)
Impairment of oil and natural gas properties
36,059
-
36,059
%
General & administrative
17,989
20,775
(2,786 )
(13 %)
Other
(85 )
%
Per Mcfe
Year Ended December 31,
Year Ended December 31,
Variance
Depreciation, depletion & amortization
$ 0.95
$ 1.06
$ (0.11 )
(10 %)
Impairment of oil and natural gas properties
$ 0.74
$ -
$ 0.74
%
General & administrative
$ 0.37
$ 0.44
$ (0.07 )
(16 %)
Other
$ -
$ -
$ -
%
Depreciation, Depletion & Amortization (“DD&A”)
DD&A expense for the year ended December 31, 2020 and 2019 was calculated on the Full Cost Method of Accounting. We adjust our DD&A rates at least twice a year in conjunction with issuance of our year-end (for the fourth and first quarters) and mid-year (for the second and third quarters) reserve reports. We make additional adjustments to our DD&A rates on a quarterly basis if deemed material based on interim period reserve reports. DD&A decreased for the year ended December 31, 2020 versus the prior year period as a result of a decrease in the DD&A rate based on the 2020 reserve reports and lower capitalized asset base offset by additional production volumes to which the DD&A rate was applied. Included in DD&A for the year ended December 31, 2020 was the depletion of our oil and gas properties of $46.0 million, accretion of our asset retirement obligation of $0.3 million, and depreciation of our furniture and fixtures of $0.3 million.
Impairment
The Full Cost Method requires that we perform a quarterly ceiling test. The ceiling test performed as of December 31, 2020 indicated that the net book value of our proved oil and natural gas properties exceeded the estimated discounted future net cash flows resulting in a $36.1 million impairment of oil and natural gas properties for the year ended December 31, 2020, due to the low commodity price environment experienced during 2020 that brought the trailing 12-month average price to $1.99 per mcf of natural gas. Commodity prices have the greatest effect on the determination of an impairment, among other factors. Recently, natural gas future prices are trending upward; however, any commodity price deterioration from current levels may indicate an impairment of our oil and natural gas properties in the future. Please refer to Note 1-“Description of Business and Significant Accounting Policies-Full Cost Ceiling Test” in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Annual Report on Form 10-K for additional details.
The Full Cost Method ceiling test performed as of December 31, 2019 resulted in no impairment of oil and natural gas properties.
General and Administrative Expense (“G&A”)
General and Administrative Expense for the year ended December 31, 2020 was $18.0 million, which included $4.7 million of share based compensation. The $2.8 million decrease in G&A expense for the year ended December 31, 2020 compared to the prior year period was substantially attributed to a decrease in employee related expenses due to decreased headcount in 2020 as well as a decrease in share based compensation. We capitalized $3.5 million and $3.7 million of G&A directly attributed to our capital development to the full cost pool for the year ended December 31, 2020 and December 31, 2019, respectively. Our G&A expense per unit of production decreased by 16% in 2020.
Other Income (Expense)
Year Ended December 31,
Year Ended December 31,
Variance
Other Income (Expense):
Interest expense
$ (7,049 )
$ (11,001 )
$ (3,952 )
(36 %)
Interest income and other
%
Gain on derivatives not designated as hedges
4,408
15,010
(10,602 )
%
Loss on early extinguishment of debt
-
(1,846 )
1,846
(100 %)
Average funded borrowings adjusted for debt discount
$ 105,489
$ 86,493
Average funded borrowings
$ 108,778
$ 89,909
Interest Expense
Interest expense for the year ended December 31, 2020 included $4.5 million incurred on the 2019 Senior Credit Facility and $2.5 million incurred on the 2021/2022 Second Lien Notes, as defined below. The interest on the 2021/2022 Second Lien Notes was all non-cash consisting of paid-in-kind interest of $1.8 million, amortized debt discount of $0.5 million and amortization of debt issuance costs of $0.2 million.
Interest expense for the year ended December 31, 2019 included $0.9 million incurred on the 2017 Senior Credit Facility, $3.4 million incurred on the 2019 Senior Credit Facility, $5.3 million incurred on the 2019 Second Lien Notes and $1.4 million incurred on the 2021/2022 Second Lien Notes. The interest on the 2019 Second Lien Notes and 2021/2022 Second Lien Notes was all non-cash consisting of paid-in-kind interest of $4.0 million, amortized debt discount of $2.6 million and amortization of debt issuance costs of $0.1 million.
Interest expense decreased for the year ended December 31, 2020 compared to the prior year period as a result of the repayment in 2019 of the higher interest rate 2019 Second Lien Notes with borrowings from the 2019 Senior Credit Facility that carries a lower interest rate, offset by additional net borrowings on our 2019 Senior Credit Facility in 2020. On May 29, 2019, we redeemed our 2019 Second Lien Notes using borrowings from our 2019 Senior Credit Facility and recorded a $1.8 million loss on early extinguishment of debt. On May 31, 2019, we issued $12.0 million of new convertible second lien notes. These transactions resulted in, and will continue to result in, the Company incurring less interest expense overall because a large portion of our debt was moved to the 2019 Senior Credit Facility, which has a lower interest rate, but an increase in interest payable in cash.
Interest Income and Other
Interest income and other for the years ended December 31, 2020 and 2019 were $0.2 million and less than $0.1 million, respectively.
Gain/Loss on Derivatives Not Designated as Hedges
We produce and sell oil and natural gas into a market where prices are historically volatile. We enter into swap contracts, collars or other derivative agreements from time to time to manage our exposure to commodity price risk for a portion of our production. We do not designate our derivative contracts as hedges for accounting purposes. Consequently, the changes in our mark-to-market valuations are recorded directly to income or loss on our financial statements.
Gain on commodity derivatives not designated as hedges of $4.4 million for the year ended December 31, 2020 was comprised of a gain of $15.2 million from net cash settlements offset by a mark-to-market loss of $10.8 million, representing the change in fair value of our unsettled derivative contracts. The mark-to-market loss represented an $11.4 million loss in the fair value of our natural gas derivative contracts, offset by a $0.5 million gain in the fair value of our basis swaps and a $0.1 million gain in the fair value of our oil derivative contracts. The gain on cash settlements reflected a net $13.6 million received from our counter-parties on settlement of our natural gas derivatives and $1.6 million received to our counter-parties on settlement of oil derivatives.
Gain on commodity derivatives not designated as hedges of $15.0 million for the year ended December 31, 2019 was comprised of a mark-to-market gain of $5.4 million, representing the change in fair value of our unsettled derivative contracts, and a gain of $9.6 million from net cash settlements. The mark-to-market gain represented an $8.2 million gain in the fair value of our natural gas derivative contracts, offset by a $2.4 million loss in the fair value of our basis swaps and a $0.4 million loss in the fair value of our oil derivative contracts. The gain on cash settlements reflected a net $10.3 million received from our counter-parties on settlement of our natural gas derivatives offset by a net $0.7 million paid to our counter-parties on settlement of oil derivatives.
Income Tax Benefit
We recorded no income tax benefit or expense for the years ended December 31, 2020 or 2019. We maintained a valuation allowance at December 31, 2020, which resulted in no net deferred tax asset or liability appearing on our statement of financial position. As of December 31, 2019, we had recorded a deferred tax asset related to alternative minimum tax (“AMT”) credits which were subsequently received as tax refunds during 2020. We recorded this valuation allowance after an evaluation of all available evidence (including commodity prices and our history of tax net operating losses in 2020 and prior years) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature our deferred tax assets were unrecoverable.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-United States Generally Accepted Accounting Principle (“U.S. GAAP”) financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as earnings before interest expense, income and similar tax, DD&A, share-based compensation expense and impairment of oil and natural gas properties (if any). In calculating Adjusted EBITDA, gains/losses on reorganization and mark-to-market gains/losses on commodity derivatives not designated as hedges are also excluded. Other excluded items include adjustments resulting from the accounting for operating leases under Accounting Standards Codification (“ASC”) 842 in accordance with our 2019 Senior Credit Facility, interest income and any extraordinary non-cash gains or losses. Adjusted EBITDA is not a measure of net income (loss) as determined by U.S. GAAP. Adjusted EBITDA should not be considered an alternative to net income (loss), as defined by U.S. GAAP.
The following table presents a reconciliation of the non-U.S. GAAP measure of Adjusted EBITDA to the U.S. GAAP measure of net income (loss), its most directly comparable measure presented in accordance with U.S. GAAP:
Year Ended December 31, 2020
Year Ended December 31, 2019
(In thousands)
Net income (loss) (U.S. GAAP)
$ (44,141 )
$ 13,288
Depreciation, depletion and amortization
46,603
50,722
Impairment of oil and natural gas properties
36,059
-
Share based compensation expense (non-cash)
4,827
6,400
Interest expense
7,049
11,001
Gain on commodity derivatives not designated as hedges
(4,408 )
(15,010 )
Net cash received in settlement of derivative instruments
15,192
9,560
Loss on early extinguishment of debt
-
1,846
Other items (1)
1,146
Adjusted EBITDA
$ 62,023
$ 78,953
(1)
Other items include $1.0 million and $1.2 million, respectively, from the impact of accounting for operating leases under ASC 842, as well as interest income, reorganization items and other non-recurring income and expense.
Management believes that this non-U.S. GAAP financial measure provides useful information to investors because it is monitored and used by our management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry. Our computations of Adjusted EBITDA may not be comparable to other similarly totaled measures of other companies.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Our primary sources of cash during 2020 were cash on hand, cash flow from operating activities of $58.9 million and $3.5 million net proceeds from borrowings on our 2019 Senior Credit Facility. We used $58.3 million in cash to fund our drilling and development capital program and $4.2 million for purchases of treasury stock for tax withholding purposes related to stock compensation. We currently plan to fund our operations and capital expenditures for 2021 through a combination of cash on hand, cash from operating activities, 2023 Second Lien Notes (as defined below) and borrowings under the 2019 Senior Credit Facility, although we may from time to time consider other funding alternatives.
On May 14, 2019, the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the “2019 Credit Agreement”) among the Company, the Subsidiary, as borrower (in such capacity, the “Borrower”), Truist Bank (formerly SunTrust Bank), as administrative agent (the “Administrative Agent”), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “2019 Senior Credit Facility”). The 2019 Senior Credit Facility amended, restated and refinanced the obligations under our 2017 Credit Agreement.
The 2019 Senior Credit Facility matures (a) May 14, 2024 or (b) December 2, 2022, if the 2023 Second Lien Notes have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by December 2, 2022, which is the date that is 180 days prior to the May 31, 2023 “Maturity Date” of the 2023 Second Lien Notes. The 2019 Senior Credit Facility provides for a maximum credit amount of $500 million subject to a borrowing base limitation, which was originally $115 million. The borrowing base was increased to $125 million in August 2019 and was decreased to $120 million in May 2020, which was reaffirmed in the fall 2020 redetermination. The borrowing base is scheduled to be redetermined in March and September of each calendar year, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and the Administrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders at their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Borrower may also request the issuance of letters of credit under the 2019 Credit Agreement in an aggregate amount up to $10 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.
On May 14, 2019, the Company and the Subsidiary issued $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “2021/2022 Second Lien Notes”). Proceeds from the sale of the 2021/2022 Second Lien Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility. In May 2020, the maturity date of the 2021/2022 Second Lien Notes was extended to May 31, 2022.
On March 9, 2021, the Company and the Subsidiary entered into a purchase and exchange agreement with certain purchasers (each such purchaser, together with its successors and assigns, a “2023 Second Lien Notes Purchaser”) pursuant to which the Company issued to the 2023 Second Lien Notes Purchasers (the “2023 Second Lien Notes Offering”) (A) $15.2 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2023 (the “2023 Second Lien Notes”) in exchange for an equal amount of 2021/2022 Second Lien Notes and (B) $15.0 million of the 2023 Second Lien Notes in exchange for cash. Proceeds from the sale of the 2023 Second Lien Notes were used to pay down outstanding borrowings under the 2019 Senior Credit Facility.
The 2023 Second Lien Notes, as set forth in the indenture governing the 2023 Second Lien Notes, are scheduled to mature on May 31, 2023. The 2023 Second Lien Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the 2023 Second Lien Notes by increasing the principal amount of the outstanding 2023 Second Lien Notes.
We exited 2020 with $1.4 million of cash on hand and $96.4 million of outstanding borrowings with $23.6 million of availability under the current borrowing base of $120.0 million on the 2019 Senior Credit Facility. Due to the timing of the payment of our capital expenditures, we reflected a working capital deficit of $27.9 million as of December 31, 2020. Subsequently, our working capital deficit was not covered by availability under the 2019 Senior Credit Facility, and we were therefore not in compliance with our current ratio financial covenant under the 2019 Senior Credit Facility. On March 9, 2021, we entered into a Fourth Amendment to Credit Agreement with the Subsidiary, Truist Bank, as administrative agent, and the lenders party thereto, pursuant to which, among other things, the lenders permitted the issuance of the 2023 Second Lien Notes and agreed to waive the default caused by our failure to comply with the current ratio financial covenant under the 2019 Senior Credit Facility as of the last day of the fiscal quarter ended December 31, 2020. To the extent we continue to operate with a working capital deficit, we expect such deficit to be offset by liquidity available under our 2019 Senior Credit Facility. Compliance with our covenants under the 2019 Senior Credit Facility and 2023 Second Lien Notes is primarily dependent upon our capital spending program. Our financial forecast indicates we will be in compliance with all our bank covenants through 2021. See Note 5-Debt in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K for more information on the 2019 Senior Credit Facility and the 2021/2022 Second Lien Notes.
Outlook
Our total capital expenditures for 2021 are expected to be approximately $75 to $85 million with flexibility to increase or decrease this amount based on the movement of commodity prices. We have the flexibility to move forward with or delay capital projects based on the upward or downward movement of commodity prices. We plan to focus all of our capital on drilling and development of our Haynesville Shale Trend natural gas properties in North Louisiana.
To mitigate the effects of the downturn in commodity prices due to the effects of COVID-19, we reduced our capital expenditures for 2020 thereby conserving capital and will continue to monitor our capital expenditures in 2021.
We believe the results of the capital investments we made in 2020 will allow us to generate sufficient cash flows, and coupled with the availability under our 2019 Senior Credit Facility and the 2023 Second Lien Notes, will allow us to execute our operational plans and meet our investing, financing and working capital requirements through 2021. We also believe that the value that is created by our plan will allow us to generate cash flow and raise capital to continue our capital development in the future.
We continuously monitor our balance sheet and coordinate our capital program with our expected cash flows and scheduled debt repayments. We will continue to evaluate funding alternatives as needed.
Alternatives available to us include:
•
availability under the 2019 Senior Credit Facility;
•
issuance of debt securities;
•
joint ventures in our TMS and/or Haynesville Shale Trend acreage;
•
sale of non-core assets; and
•
issuance of equity securities if favorable conditions exist.
In addition, to support future cash flows, we entered into strategic derivative positions as of December 31, 2020 covering approximately 55% of our forecasted natural gas production hedged through the first quarter of 2022 at a weighted average price of $2.53 per Mcf. We have approximately 55% of our forecasted oil production hedged through the first quarter of 2021 at a weighted average price of $56.58 per barrel. See Note 9-Derivative Activities in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of the Annual Report on Form 10-K.
The table below summarizes our cash flows for the periods indicated (in thousands):
Cash flow statement information:
Year Ended December 31, 2020
Year Ended December 31, 2019
Net Cash:
Provided by operating activities
$ 58,891
$ 79,071
Used in investing activities
(58,262 )
(97,967 )
Provided by (used in) financing activities
(721 )
16,280
Decrease in cash and cash equivalents
$ (92 )
$ (2,616 )
Cash Flows
For the Year Ended December 31, 2020
Operating activities: Production from our wells, the price of oil and natural gas and operating costs represent the main drivers of our cash flow from operations. Changes in working capital and net cash settlements related to our derivative contracts also impacted operating cash flows. Net cash provided by operating activities for the year ended December 31, 2020 was $58.9 million including operating cash flows before working capital changes of $58.4 million that included $15.2 million for settlements of derivative contracts. The decrease in cash provided by operating activities in 2020 compared to 2019 was primarily attributable to a 21% decrease in oil and natural gas revenues driven by an 23% decrease in average realized prices.
Investing activities: Net cash used in investing activities was $58.3 million for the year ended December 31, 2020, which reflected cash expended on capital projects. We recorded $56.5 million in capital expenditures in this period, which reflected the capitalization of $0.2 million in asset retirement obligation and $0.6 million of non-cash internal cost reduced by a net $2.6 million in the change of the capital expenditure accrual and cash calls received. We conducted drilling and completion operations on 25 gross wells bringing 16 gross (5.5 net) wells on production in the Haynesville Shale Trend during the year ended December 31, 2020, and we capitalized $3.5 million in internal costs. We had 11 gross (4.8 net) wells in the drilling and completion phases at December 31, 2020.
Financing activities: Net cash used in financing activities for the year ended December 31, 2020 was $0.7 million, which consisted of payments of $4.2 million for the purchase of shares withheld from employee stock awards for the payments of taxes upon vesting offset by net draws of $3.5 million on the Company's 2019 Senior Credit Facility.
For the Year Ended December 31, 2019
Operating activities: Production from our wells, the price of oil and natural gas and operating costs represent the main drivers of our cash flow from operations. Changes in working capital and net cash settlements related to our derivative contracts also impacted operating cash flows. Net cash provided by operating activities for the year ended December 31, 2019 was $79.1 million including operating cash flows before working capital changes of $75.5 million that included $9.6 million for settlements of derivative contracts. The substantial increase in cash provided by operating activities in 2019 compared to 2018 was attributable to a 35% increase in oil and natural gas revenues driven by an 85% increase in equivalent production volumes.
Investing activities: Net cash used in investing activities was $98.0 million for the year ended December 31, 2019, which reflected cash expended on capital projects of $99.3 million reduced by $1.3 million cash proceeds received from sales of oil and gas properties. We recorded $98.4 million in capital expenditures in 2019, which reflected the capitalization of $0.3 million in asset retirement obligation and $0.7 million of non-cash internal cost reduced by a net $1.9 million in the change of the capital expenditure accrual. We conducted drilling and completion operations on 16 gross wells bringing 9 gross (7.2 net) wells on production in the Haynesville Shale Trend during the year ended December 31, 2019, and we capitalized $5.0 million in internal costs. We had 9 gross (4.9 net) wells waiting completion at December 31, 2019.
Financing activities: Net cash provided by financing activities for the year ended December 31, 2019 was $16.3 million, which consisted of net draws of $65.9 million on the Company's senior credit facilities reduced by $44.7 million net payments on our convertible second lien notes, $2.1 million for the purchase of shares withheld from employee stock awards for the payments of taxes and $2.8 million of debt issuance cost paid upon the amendment of the 2019 Senior Credit Facility and issuance of the 2021/2022 Second Lien Notes.
Debt consisted of the following balances as of the dates indicated (in thousands):
December 31, 2020
December 31, 2019
Principal
Carrying Amount
Fair Value
Principal
Carrying Amount
Fair Value
2019 Senior Credit Facility (1)
$ 96,400
$ 96,400
$ 96,400
$ 92,900
$ 92,900
$ 92,900
2021/2022 Second Lien Notes (2)
14,811
13,759
15,107
12,969
11,535
12,952
Total debt
$ 111,211
$ 110,159
$ 111,507
$ 105,869
$ 104,435
$ 105,852
(1)
The carrying amount for the 2019 Senior Credit Facility represents fair value as it was fully secured.
(2) The debt discount was amortized using the effective interest rate method based upon a maturity date of May 31, 2022. The principal includes paid-in-kind interest of $2.8 million as of December 31, 2020 and $1.0 million as of December 31, 2019. The carrying value includes $0.9 million of unamortized debt discount and $0.2 million of unamortized issuance cost at December 31, 2020. The carrying value includes $1.1 million of unamortized debt discount and $0.3 million of unamortized issuance cost at December 31, 2019. The fair value of the 2021/2022 Second Lien Notes, a Level 2 fair value estimate, was obtained by using the last known sale price for the value on December 31, 2020.
The following table summarizes the total interest expense (contractual interest expense, amortization of debt discount, accretion and financing costs) and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates) for the periods ended:
Year Ended December 31, 2020
Year Ended December 31, 2019
Effective
Effective
Interest
Interest
Interest
Interest
Expense
Rate
Expense
Rate
2017 Senior Credit Facility
$ -
0.0 %
$
7.2 %
2019 Senior Credit Facility
4,543
4.7 %
3,409
6.0 %
2019 Second Lien Notes (1)
-
0.0 %
5,304
24.1 %
2021/2022 Second Lien Notes (2)
2,506
19.7 %
1,416
21.6 %
Total
$ 7,049
$ 11,001
(1) The 2019 Second Lien Notes had a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 24.1% for the year ended December 31, 2019 (until payoff on May 29, 2019). Interest expense for the year ended December 31, 2019 included $2.3 million of debt discount amortization and $3.0 million of paid-in-kind interest.
(2) The 2021/2022 Second Lien Notes have a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 19.7% and 21.6% for the years ended December 31, 2020 and 2019, respectively. Interest expense for the year ended December 31, 2020 included $1.8 million of accrued interest to be paid in-kind, $0.5 million of debt discount amortization and $0.2 million issuance cost amortization. Interest expense for the year ended December 31, 2019 included $1.0 million of accrued interest to be paid in-kind, $0.3 million of debt discount amortization and $0.1 million of issuance cost amortization.
Future Commitments
The table below (in thousands) provides estimates of the timing of future payments that we are obligated to make based on agreements in place as of December 31, 2020. In addition to the contractual obligations presented in the table below, our Consolidated Balance Sheet at December 31, 2020 reflects accrued interest on our bank debt of $0.2 million payable in the first quarter of 2021. For additional information see Note 5-Debt, Note 10-Commitments and Contingencies and Note 11-Leases in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Payment due by Period
Note
Total
and After
Debt
$ 111,211
$ -
$ 14,811
$ -
$ 96,400
$ -
Office space leases
4,781
1,238
1,592
Operations contracts
1,469
1,406
-
-
Total contractual obligations (1)
$ 117,461
$ 2,644
$ 15,479
$
$ 97,061
$ 1,592
(1)
This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $4.7 million as of December 31, 2020. We record a separate liability for the asset retirement obligations. See Note 4-Asset Retirement Obligation in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Summary of Critical Accounting Policies and Estimates
The following summarizes several of our critical accounting policies. See a complete list in Note 1-Description of Business and Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Proved Oil and Natural Gas Reserves
Proved reserves are defined by the SEC as those quantities of oil and natural gas which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well. Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.
While the estimates of our proved reserves at December 31, 2020 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could differ materially from our actual results.
Full Cost Accounting Method
Under U.S. GAAP, two acceptable methods of accounting for oil and gas properties are allowed. These are the Successful Efforts Method and the Full Cost Method. Entities engaged in the production of oil and gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the two methods are in the treatment of exploration costs, the computation of DD&A expense and the assessment of impairment of oil and gas properties. We follow the Full Cost Method of Accounting. We believe that the true cost of developing a “portfolio” of reserves should reflect both successful and unsuccessful attempts at exploration and production. Application of the Full Cost Method of Accounting will better reflect the true economics of exploring for and developing our oil and gas reserves. Therefore, we use the Full Cost Method to account for our investment in oil and gas properties in the reorganized company.
Under the Full Cost Method, we capitalize all costs associated with acquisitions, exploration, development and estimated abandonment costs. We capitalize internal costs that can be directly identified with the acquisition of leaseholds, as well as drilling and completion activities, but we do not include any costs related to production, general corporate overhead or similar activities. Unevaluated property costs are excluded from the amortization base until we make a determination as to the existence of proved reserves on the respective property. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to proved oil and gas properties and therefore subject to DD&A. Our sales of oil and gas properties are accounted for as adjustments to net proved oil and gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Additionally, we capitalize a portion of the costs of interest incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate.
All exploratory costs are capitalized, and DD&A expense is computed on cost centers represented by entire countries. Our oil and gas properties are subject to a ceiling test to assess for impairment, as discussed below, under the Full Cost Method.
We amortize our investment in oil and gas properties through DD&A expense using the units of production method. An amortization rate is calculated based on total proved reserves converted to equivalent thousand cubic feet of natural gas (“Mcfe”) as the denominator and the net book value of evaluated oil and gas asset together with the estimated future development cost of the proved undeveloped reserves as the numerator. The rate calculated per Mcfe is applied against the periods' production also converted to Mcfe to arrive at the periods' DD&A expense.
Full Cost Ceiling Test
The Full Cost Method requires that at the conclusion of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs), be compared to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. This comparison is referred to as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are calculated based on a 12-month average pricing assumption.
Fair Value Measurement
Fair value is defined by Accounting Standards Codification (“ASC”) 820 as 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. We carry our derivative instruments at fair value and measure their fair value by applying the income approach provided for ASC 820, using Level 2 inputs based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our credit worthiness or that of our counterparties. We carry our oil and natural gas properties held for use at historical cost or their estimated fair value if an impairment has been identified. We use Level 3 inputs, which are unobservable data such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices to determine the fair value of our oil and natural gas properties in determining impairment. We carry cash and cash equivalents, account receivables and payables at carrying value that represent fair value because of the short-term nature of these instruments. For definitions of Level 1, Level 2 and Level 3 inputs see Note 1-Description of Business and Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Asset Retirement Obligations
We make estimates of the future costs of the retirement obligations of our producing oil and natural gas properties in order to record the liability as required by the applicable accounting standard. This requirement necessitates us to make estimates of our property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that may be difficult to predict.
Income Taxes
We are subject to income and other related taxes in areas in which we operate. When recording income tax expense, certain estimates are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate our tax operating loss and other carry-forwards to determine whether a gross deferred tax asset, as well as a related valuation allowance, should be recognized in our financial statements.
Accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See Note 1-Description of Business and Summary of Significant Accounting Policies-Income Taxes and Note 7-Income Taxes in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Share-based Compensation Plans
For all new, modified and unvested share-based payment transactions with employees, we measure the fair value on the grant date and recognize it as compensation expense over the requisite period. Our common stock does not pay dividends; therefore, the dividend yield is zero.
New Accounting Pronouncements
See Note 1-Description of Business and Summary of Significant Accounting Policies-New Accounting Pronouncements in the Notes to Consolidated Financial Statements in “Item 8 - Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
We do not currently have any off-balance sheet arrangements for any purpose.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
As a smaller reporting company, we are not required to provide the information required by this Item 7A.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8.
Financial Statements and Supplementary Data
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting Firm-Consolidated Financial Statements for the years ended December 31, 2020 and 2019
Consolidated Balance Sheets as of December 31, 2020 and 2019
Consolidated Statements of Operations for the years ended December 31, 2020 and 2019
Consolidated Statements of Cash Flows for the years ended December 31, 2020 and 2019
Consolidated Statements of Stockholders' Equity for the years ended December 31, 2020 and 2019
Notes to the Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Goodrich Petroleum Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and subsidiary (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Natural Gas Reserves on Depletion Expense and Ceiling Test Calculation
As described in Note 1, the Company follows the full cost method of accounting, under which capitalized costs, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method based on proved oil and natural gas reserves. On a quarterly basis, management performs a full cost ceiling impairment test on proved oil and natural gas properties. Under the ceiling test, the net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling which is equal to the sum of: (1) the present value discounted at 10% of estimated future net cash flows from proved reserves, (2) the cost of properties not being amortized, and (3) the lower of cost or estimated fair value of unproven properties included in the costs being amortized. For the year ended December 31, 2020, the Company recorded depletion expense related to proved oil and gas properties of approximately 46 million. The Company recorded a ceiling test impairment of approximately 36 million for the year ended December 31, 2020 due to the net capitalized cost of the oil and gas properties exceeding the ceiling limitation. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and the ceiling impairment test.
We identified the impact of proved oil and natural gas reserves on depletion expense and the ceiling test as a critical audit matter due to use of significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the significant assumptions used in developing those estimates of proved oil and natural gas reserves. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.
The primary procedures we performed to address this critical audit matter included:
•
Gaining an understanding of the design and implementation of controls relating to management’s estimates of proved oil and natural gas reserves, the full cost ceiling impairment test, and depletion, depreciation and amortization expense.
•
Evaluating the significant assumptions used by management in developing the estimates of proved oil and natural gas reserves, including pricing differentials, future operations costs, future production rates and capital expenditures. The procedures performed included tests of the data used by specialists and an evaluation of the specialist’s findings. Evaluating the significant assumptions relating to the estimates of proved oil and natural gas reserves also involved obtaining evidence to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the past performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit.
•
Evaluating the working and net revenue interests used in the reserve report by testing a sample of land and division order records.
• Evaluating the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the operator’s intent to develop the proved undeveloped properties.
• Using the work of management’s specialists to evaluate the reasonableness of the estimates of proved oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were assessed, as well as the reasonableness of methods and assumptions used by the specialists.
• Analyzing the ceiling test impairment calculation for compliance with industry and regulatory standards and performing a mathematical recalculation of the ceiling test impairment calculation.
• Analyzing the depletion expense calculation for compliance with industry and regulatory standards, and performing an independent calculation and comparing the Company’s results with our results.
/s/ Moss Adams LLP
Houston, Texas
March 12, 2021
We have served as the Company’s auditor since 2017.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(In Thousands)
December 31, 2020
December 31, 2019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$ 1,360
$ 1,452
Accounts receivable, trade and other, net of allowance
1,131
Accrued oil and natural gas revenue
10,179
11,345
Fair value of oil and natural gas derivatives
8,537
Inventory
Prepaid expenses and other
1,292
Total current assets
14,024
23,248
PROPERTY AND EQUIPMENT:
Unevaluated properties
Oil and gas properties (Full Cost Method)
359,112
302,859
Furniture, fixtures and equipment
7,535
4,450
366,887
307,432
Less: Accumulated depletion, depreciation and amortization
(177,669 )
(94,124 )
Net property and equipment
189,218
213,308
Fair value of oil and natural gas derivatives
-
Deferred tax asset
-
Other
1,835
2,338
TOTAL ASSETS
$ 205,077
$ 239,318
LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT)
CURRENT LIABILITIES:
Accounts payable
$ 27,811
$ 26,348
Fair value of oil and natural gas derivatives
1,274
-
Accrued liabilities
12,866
16,615
Total current liabilities
41,951
42,963
Long term debt, net
110,159
104,435
Accrued abandonment costs
4,716
4,169
Fair value of oil and natural gas derivatives
3,871
2,786
Non-current operating lease liability
2,810
Total liabilities
163,507
155,153
Commitments and contingencies (See Note 10)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares $1.00 par value authorized, and none issued and outstanding
-
-
Common stock: $0.01 par value, 75,000,000 shares authorized, and 13,392,625 shares issued and outstanding at December 31, 2020 and $0.01 par value, 75,000,000 shares authorized, and 12,532,550 shares issued and outstanding at December 31, 2019
Additional paid-in capital
82,842
81,305
Retained earnings (deficit)
(41,406 )
2,735
Total stockholders’ equity
41,570
84,165
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$ 205,077
$ 239,318
See accompanying notes to consolidated financial statements.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Amounts)
Year Ended December 31, 2020
Year Ended December 31, 2019
REVENUES:
Oil and natural gas revenues
$ 93,793
$ 118,353
Other
(3 )
93,826
118,350
OPERATING EXPENSES:
Lease operating expense
13,001
12,371
Production and other taxes
2,751
2,573
Transportation and processing
19,055
20,703
Depreciation, depletion, and amortization
46,603
50,722
Impairment of oil and natural gas properties
36,059
-
General and administrative
17,989
20,775
Other
135,479
107,250
Operating income (loss)
(41,653 )
11,100
OTHER INCOME (EXPENSE):
Interest expense
(7,049 )
(11,001 )
Interest income and other
Gain on derivatives not designated as hedges
4,408
15,010
Loss on early extinguishment of debt
-
(1,846 )
(2,488 )
2,188
Income (loss) before income taxes
(44,141 )
13,288
Income tax benefit
-
-
Net income (loss)
$ (44,141 )
$ 13,288
PER COMMON SHARE:
Net income (loss) per common share-basic
$ (3.50 )
$ 1.09
Net income (loss) per common share-diluted
$ (3.50 )
$ 0.96
Weighted average shares of common stock outstanding-basic
12,617
12,233
Weighted average shares of common stock outstanding-diluted
12,617
13,895
See accompanying notes to consolidated financial statements.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Year Ended December 31, 2020
Year Ended December 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
$ (44,141 )
$ 13,288
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization
46,603
50,722
Impairment of oil and gas properties
36,059
-
Right of use asset depreciation
1,193
1,252
Gain on derivatives not designated as hedges
(4,408 )
(15,010 )
Net cash received in settlement of derivative instruments
15,192
9,560
Share-based compensation (non-cash)
4,827
6,400
Loss on early extinguishment of debt
-
1,846
Amortization of finance cost, debt discount, paid-in-kind interest and accretion
3,019
7,097
Loss from material transfers & inventory sales & write-downs
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance
Accrued oil and natural gas revenue
1,166
3,119
Inventory
-
Prepaid expenses and other
(116 )
(45 )
Accounts payable
1,463
Accrued liabilities
(2,674 )
(140 )
Net cash provided by operating activities
58,891
79,071
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(58,262 )
(99,301 )
Proceeds from sale of assets
-
1,334
Net cash used in investing activities
(58,262 )
(97,967 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings
(6,000 )
(49,500 )
Proceeds from bank borrowings
9,500
115,400
Repayment of 2019 Second Lien Notes
-
(56,728 )
Proceeds from 2021/2022 Second Lien Notes
-
12,000
Issuance cost, net
-
(2,795 )
Other, including purchase of treasury stock
(4,221 )
(2,097 )
Net cash provided by (used in) financing activities
(721 )
16,280
Decrease in cash and cash equivalents
(92 )
(2,616 )
Cash and cash equivalents, beginning of period
1,452
4,068
Cash and cash equivalents, end of period
$ 1,360
$ 1,452
Supplemental disclosures of cash flow information:
Cash paid during the year for interest
$ 4,030
$ 4,137
Decrease in non-cash capital expenditures
$ (2,037 )
$ (1,911 )
See accompanying notes to consolidated financial statements.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)
(In Thousands)
Preferred Stock
Common Stock
Additional Paid-in
Treasury Stock
Retained Earnings/
Total Stockholders’
Shares
Value
Shares
Value
Capital
Shares
Value
(Deficit)
Equity/(Deficit)
Balance at December 31, 2018
-
$ -
12,151
$
$ 74,861
-
$ -
$ (10,553 )
$ 64,430
Net income
-
-
-
-
-
-
-
13,288
13,288
Share-based compensation
-
-
-
-
7,221
-
-
-
7,221
Restricted stock vesting & other
-
-
(90 )
(208 )
(2,098 )
-
(2,184 )
2019 Second Lien Notes warrants and conversions
-
-
(20 )
-
-
-
(19 )
Issuance cost
-
-
-
-
1,429
-
-
-
1,429
Treasury stock activity
-
-
-
(2 )
(2,096 )
2,098
-
-
Balance at December 31, 2019
-
-
12,533
81,305
-
-
2,735
84,165
Net loss
-
-
-
-
-
-
-
(44,141 )
(44,141 )
Share-based compensation
-
-
-
-
5,483
-
-
-
5,483
Restricted stock vesting & other
-
-
1,269
(11 )
(409 )
(4,221 )
-
(4,219 )
Discount from 2021/2022 Second Lien Notes Modification (See Note 4)
-
-
-
-
-
-
-
Treasury stock activity
-
-
(409 )
(4 )
(4,217 )
4,221
-
-
Balance at December 31, 2020
-
$ -
13,393
$
$ 82,842
-
$ -
$ (41,406 )
$ 41,570
See accompanying notes to consolidated financial statements.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1-Description of Business and Summary of Significant Accounting Policies
Goodrich Petroleum Corporation (“Goodrich” and, together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the “Subsidiary”), “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.
Basis of Presentation
Principles of Consolidation-The consolidated financial statements of the Company included in this Annual Report on Form 10-K have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) and in accordance with United States Generally Accepted Accounting Principle (“U.S. GAAP”). The consolidated financial statements include the financial statements of Goodrich Petroleum Corporation and its wholly-owned subsidiary. Intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Certain data in prior period financial statements have been adjusted to conform to the presentation of the current period. We have evaluated subsequent events through the date of this filing.
Use of Estimates-Our Management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with U.S. GAAP.
Cash and Cash Equivalents-Cash and cash equivalents included cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase.
Accounts Payable-Accounts payable consisted of the following items as of December 31, 2020 and 2019 (in thousands):
December 31,
Trade payables
$ 12,190
$ 11,461
Revenue payables
14,413
14,483
Prepayments from partners
-
Other
Total Accounts payable
$ 27,811
$ 26,348
Accrued Liabilities-Accrued liabilities consisted of the following items as of December 31, 2020 and 2019 (in thousands):
December 31,
Accrued capital expenditures
$ 4,138
$ 6,175
Accrued lease operating expense
Accrued production and other taxes
Accrued transportation and gathering
1,722
2,258
Accrued performance bonus
3,947
4,642
Accrued interest
Accrued office lease
1,414
Accrued general and administrative expense and other
Total Accrued liabilities
$ 12,866
$ 16,615
Inventory-Inventory consisted of equipment, casing and tubulars that are expected to be used in our capital drilling program. Inventory is carried on the Consolidated Balance Sheets at the lower of cost or market.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Property and Equipment-Under U.S. GAAP, two acceptable methods of accounting for oil and gas properties are allowed. These are the Successful Efforts Method and the Full Cost Method. Entities engaged in the production of oil and gas have the option of selecting either method for application in the accounting for their properties. The principal differences between the two methods are in the treatment of exploration costs, the computation of depreciation, depletion and amortization (“DD&A”) expense and the assessment of impairment of oil and gas properties. We have elected to adopt the Full Cost Method. We believe that the true cost of developing a “portfolio” of reserves should reflect both successful and unsuccessful attempts at exploration and production. Application of the Full Cost Method better reflects the true economics of exploring for and developing our oil and gas reserves.
Under the Full Cost Method, we capitalize all costs associated with acquisitions, exploration, development and estimated abandonment costs. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, but do not include any costs related to production, general corporate overhead or similar activities. Unevaluated property costs are excluded from the amortization base until we make a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to proved oil and natural gas properties and therefore subject to DD&A and the full cost ceiling test. For the years ended December 31, 2020 and December 31, 2019, we transferred $0.1 million and $0.3 million, respectively, from unevaluated properties to proved oil and natural gas properties. Our sales of oil and natural gas properties are accounted for as adjustments to net proved oil and natural gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Under the Full Cost Method, we amortize our investment in oil and natural gas properties through DD&A expense using the units of production method. An amortization rate is calculated based on total proved reserves converted to equivalent thousand cubic feet of natural gas (“Mcfe”) as the denominator and the net book value of evaluated oil and gas asset together with the estimated future development cost of the proved undeveloped reserves as the numerator. The rate calculated per Mcfe is applied against the periods' production also converted to Mcfe to arrive at the periods' DD&A expense.
Depreciation of furniture, fixtures and equipment, consisting of office furniture, computer hardware and software and leasehold improvements, is computed using the straight-line method over their estimated useful lives, which vary from three to five years.
Full Cost Ceiling Test-The Full Cost Method requires that at the conclusion of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs), be compared to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. This comparison is referred to as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are calculated based on a 12-month average pricing assumption.
The Full Cost Method ceiling test resulted in a total of $36.1 million in impairments of oil and gas properties for the year ended December 31, 2020, and no impairment for the year ended December 31, 2019.
Fair Value Measurement-Fair value is defined as 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. The fair value of an asset should reflect its highest and best use by market participants, whether in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, our credit risk.
We use various methods, including the income approach and market approach, to determine the fair values of our financial instruments that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value may be calculated based on these inputs as well as other assumptions related to estimates of future settlements of these instruments. We separate our financial instruments into three levels (levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Each of these levels and our corresponding instruments classified by level are further described below:
•
Level 1 Inputs- unadjusted quoted market prices in active markets for identical assets or liabilities. We have no Level 1 instruments;
•
Level 2 Inputs- quotes that are derived principally from or corroborated by observable market data. Included in this Level are our senior credit facilities and commodity derivatives whose fair values are based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counterparties; and
•
Level 3 Inputs- unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices. Our initial measurement of asset retirement obligations are included in this Level.
As of December 31, 2020 and December 31, 2019, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.
Asset Retirement Obligations-Asset retirement obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense is included in “Depreciation, depletion and amortization” on our Consolidated Statements of Operations. See Note 4.
The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.
Revenue Recognition-Oil and natural gas revenues are generally recognized upon delivery of our produced oil and natural gas volumes to our customers. We record revenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales may not be received for up to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record a liability or an asset for natural gas balancing when we have sold more or less than our working interest share of natural gas production, respectively. As of December 31, 2020 and 2019, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.
Derivative Instruments-We use derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. Accounting standards related to derivative instruments and hedging activities require that all derivative instruments subject to the requirements of those standards be measured at fair value and recognized as assets or liabilities in the balance sheet. We offset the fair value of our asset and liability positions with the same counterparty for each commodity type. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. All of our realized gain or losses on our derivative contracts are the result of cash settlements. We have not designated any of our derivative contracts as hedges; accordingly, changes in fair value are reflected in earnings. See Note 9.
Income Taxes-We account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
We recognize, as required, the financial statement benefit of an uncertain tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See Note 7.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Income or Net Loss Per Common Share-Basic net income (loss) per common share is computed by dividing net income (loss) applicable to common stock for each reporting period by the weighted-average shares of common stock outstanding during the period. Diluted net income (loss) per common share is computed by dividing net income (loss) applicable to common stock for each reporting period by the weighted-average shares of common stock outstanding during the period, plus the effects of potentially dilutive restricted stock calculated using the treasury stock method and the potential dilutive effect of the conversion of convertible securities, such as warrants and convertible notes, into shares of our common stock. See Note 6.
Commitments and Contingencies-Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, when probable of realization, are separately recorded and are not offset against the related environmental liability. See Note 10.
Concentration of Credit Risk-Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2020 and 2019 are as follows:
Year Ended December 31,
CIMA Energy, LP
%
%
ARM Energy Management LLC
%
%
Shell
%
%
CES
%
%
Genesis Crude Oil LP
%
%
ETC Marketing, Ltd
%
%
Symmetry Energy Solutions, LLC
%
%
Share-based Compensation-We account for our share-based transactions using the fair value as of the grant date and recognize compensation expense over the requisite service period. See Note 3.
Guarantee-As of December 31, 2020 Goodrich Petroleum Company LLC, the wholly owned subsidiary of Goodrich Petroleum Corporation, was the Subsidiary Guarantor of our 2021/2022 Second Lien Notes (as defined below). The parent company has no independent assets or operations, the guarantee is full and unconditional, and the parent has no subsidiaries other than Goodrich Petroleum Company LLC.
Debt Issuance Cost-The Company records debt issuance costs associated with its 2021/2022 Second Lien Notes (and previously with its 2019 Second Lien Notes, both as defined below) as a contra balance to long term debt, net in our Consolidated Balance Sheets, which is amortized straight-line over the life of the respective notes. Debt issuance costs associated with our revolving credit facility debt are recorded in other assets in our Consolidated Balance Sheets, which is amortized straight-line over the life of such debt.
New Accounting Pronouncements
In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. The amendments in this ASU adds new guidance to simplify accounting for income taxes, changes the accounting for certain income tax transactions and makes minor improvements to the codification. For public entities, the amendments in this ASU are effective for fiscal periods beginning after December 15, 2020, including interim periods therein. We do not expect a material impact from the adoption of this ASU.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The amendments is this ASU provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in this ASU provide optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The expedients and exceptions provided by this ASU do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, that an entity has elected certain optional expedients for and that are retained through the end of the hedging relationship. We are evaluating the expected impact these amendments and reference rate reform will have on our consolidated financial statements and various contracts.
In August 2020, the FASB issued ASU 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The amendments in this ASU affect entities that issue convertible instruments and/or contracts in an entity’s own equity. The amendments in this ASU primarily affect convertible instruments issued with beneficial conversion features or cash conversion features because the accounting models for those specific features are removed. However, all entities that issue convertible instruments are affected by the amendments to the disclosure requirements of this ASU. For contracts in an entity’s own equity, the contracts primarily affected are freestanding instruments and embedded features that are accounted for as derivatives under the current guidance because of failure to meet the settlement conditions of the derivatives scope exception related to certain requirements of the settlement assessment. Also affected is the assessment of whether an embedded conversion feature in a convertible instrument qualifies for the derivatives scope exception. Additionally, the amendments in this ASU affect the diluted EPS calculation for instruments that may be settled in cash or shares and for convertible instruments. The amendments in this ASU are effective for public business entities, excluding entities eligible to be smaller reporting companies, for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. For all other entities, the amendments are effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. The Board specified that an entity should adopt the guidance as of the beginning of its annual fiscal year. The Board decided to allow entities to adopt the guidance through either a modified retrospective method of transition or a fully retrospective method of transition. The Company is currently evaluating the impact of these amendments on our accounting for and disclosure of our convertible notes.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2-Revenue Recognition
In accordance with Accounting Standards Codification Topic 606, revenue is generally recognized upon delivery of our produced oil and natural gas volumes to our customers. Our customer sales contracts include oil and natural gas sales. Under Topic 606, each unit (Mcf or barrel) of commodity product represents a separate performance obligation which is sold at variable prices, determinable on a monthly basis. The pricing provisions of our contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, product quality and prevailing supply and demand conditions in the geographic areas in which we operate. We allocate the transaction price to each performance obligation and recognize revenue upon delivery of the commodity product when the customer obtains control. Control of our produced natural gas volumes passes to our customers at specific metered points indicated in our natural gas contracts. Similarly, control of our produced oil volumes passes to our customers when the oil is measured either by a trucking oil ticket or by a meter when entering an oil pipeline. The Company has no control over the commodities after those points and the measurement at those points dictates the amount on which the customer's payment is based. Our oil and natural gas revenue streams include volumes burdened by royalty and non-operated working interests. Our revenues are recorded and presented on our financial statements net of the royalty and non-operated working interests. Our revenue stream does not include any payments for services or ancillary items other than sale of oil and natural gas.
We record revenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales may not be received for up to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. As of December 31, 2020 and December 31, 2019, receivables from contracts with customers were $10.2 million and $11.3 million, respectively.
The following tables present our oil and natural gas revenues disaggregated by revenue source and by operated and non-operated properties for the years ended December 31, 2020 and 2019:
Year Ended December 31, 2020
(In thousands)
Oil Revenue
Gas Revenue
NGL Revenue
Total Oil and Natural Gas Revenues
Operated
$ 5,488
$ 75,998
$ -
$ 81,486
Non-operated
11,695
12,307
Total oil and natural gas revenues
$ 6,089
$ 87,693
$
$ 93,793
Year Ended December 31, 2019
(In thousands)
Oil Revenue
Gas Revenue
NGL Revenue
Total Oil and Natural Gas Revenues
Operated
$ 9,961
$ 91,811
$ -
$ 101,772
Non-operated
16,142
16,581
Total oil and natural gas revenues
$ 10,387
$ 107,953
$
$ 118,353
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3-Share-based Compensation Plans
Overview
The Company had one effective share-based compensation plan as of December 31, 2020 and December 31, 2019, which is the 2016 Long Term Incentive Plan, discussed further below. We measure the cost of share-based compensation based on the fair value of the award as of the grant date, net of estimated forfeitures. Awards granted are valued at fair value and recognized on a straight-line basis over the service periods (or the vesting periods) of each award. We estimate forfeiture rates for all unvested awards based on our historical experience.
2016 Long Term Incentive Plan
Our 2016 Long Term Incentive Plan (the “LTIP”), formerly referred to as the Management Incentive Plan, provides for awards of restricted stock, options, performance awards, phantom shares and stock appreciation rights to directors, officers, employees, and consultants. The LTIP is intended to promote the interests of the Company by providing a means by which employees, consultants and directors may acquire or increase their equity interest in the Company and may develop a sense of proprietorship and personal involvement in the development and financial success of the Company, and to encourage them to remain with and devote their best efforts to the business of the Company, thereby advancing the interests of the Company and its stockholders. The LTIP is also intended to enhance the ability of the Company and its Subsidiary to attract and retain the services of individuals who are essential for the growth and profitability of the Company. The LTIP provides that the Compensation Committee shall have the authority to determine the participants to whom stock options, restricted stock, performance awards, phantom shares and stock appreciation rights may be granted.
In 2020, the Company granted approximately 151,300 restricted stock units (“RSUs”) to employees which vested immediately upon retirement or exit from the Company upon which all further outstanding awards were forfeited and granted 66,300 RSU's to non-employee directors which will generally cliff vest in 12 months following the date of grant, subject to continued service. In 2019, the Company granted approximately (i) 205,000 restricted stock units (“RSUs”) to employees which will generally vest over three years from the date of grant, subject to continued employment, (ii) 205,000 performance share units (“PSUs”), which will generally cliff vest after a three-year performance period from the date of grant, subject to continued employment and the level of achievement with respect to applicable performance metrics and (iii) 81,000 RSU's to non-employee directors which vested in 12 months following the date of grant. As of December 31, 2020, the Company had approximately 389,000 further shares available for future issuance under the LTIP, assuming that the PSUs 2019 will vest at the maximum payout of 200%.
Share-based Compensation
The following tables summarizes the pre-tax components of our share-based compensation program under the LTIP, recognized as a component of general and administrative expenses in the Consolidated Statements of Operations (in thousands), for the years ended December 31, 2020 and 2019:
Year Ended December 31,
2016 Long Term Incentive Plan
RSU expense - employees
$ 2,796
$ 4,521
PSU expense
1,938
1,952
RSU expense - directors
Total share-based compensation
$ 5,484
$ 7,137
Capitalized and lease operating expense share-based compensation
(658 )
(835 )
Net share-based compensation - general and administrative expense
$ 4,826
$ 6,302
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RSUs and PSUs awarded under the LTIP generally have a vesting period between one to three years. During the vesting period, ownership of RSUs and PSUs subject to the vesting period cannot be transferred and the shares are subject to forfeiture if the employment or service relationship, as applicable, ends before the end of the vesting period. Certain RSUs and PSUs provide for accelerated vesting in certain limited circumstances. RSUs and PSUs are not considered to be currently issued and outstanding until the restrictions lapse and/or they vest.
RSU and PSU activity and changes under the LTIP for the years ended December 31, 2020 and 2019 are as follows:
2016 Long Term Incentive Plan
Number of Units
Weighted Average Grant-Date Fair Value
Total Value (thousands)
RSU
PSU
Total
RSU
PSU
Total
RSU
PSU
Total
Unvested at December 31, 2018
661,137
399,388
1,060,525
$ 10.16
$ 15.29
$ 12.09
$ 4,653
$ 6,107
$ 10,760
Granted
294,871
204,755
499,626
9.96
10.43
10.16
2,938
2,136
5,074
Vested
(530,446 )
-
(530,446 )
10.18
-
10.18
(5,138 )
-
(5,138 )
Forfeited
(9,032 )
-
(9,032 )
13.84
-
13.84
(125 )
-
(125 )
Unvested at December 31, 2019
416,530
604,143
1,020,673
9.92
13.64
12.12
2,328
8,243
10,571
Granted
217,586
-
217,586
8.80
-
8.80
1,916
-
1,916
Vested
(400,285 )
(353,100 )
(753,385 )
9.08
15.29
13.35
(1,830 )
(5,399 )
(7,229 )
Forfeited
(71,496 )
(107,536 )
(179,032 )
9.92
12.52
11.48
(709 )
(1,347 )
(2,056 )
Unvested at December 31, 2020
162,335
143,507
305,842
$ 10.51
$ 10.43
$ 10.47
$ 1,705
$ 1,497
$ 3,202
As of December 31, 2020 and 2019, total unrecognized compensation cost and weighted average years to recognition related to RSUs and PSUs under the LTIP are as follows:
2016 Long Term Incentive Plan
Unrecognized compensation costs
Weighted Average years to recognition
(thousands)
(years)
RSU
PSU
Total
RSU
PSU
Total
December 31, 2020
$ 1,630
$
$ 2,628
1.51
1.94
1.67
December 31, 2019
$ 3,969
$ 4,283
$ 8,252
1.95
1.93
1.94
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4-Asset Retirement Obligations
The table below is the reconciliation of the beginning and ending asset retirement obligation for the periods as noted (in thousands):
December 31, 2020
December 31, 2019
Beginning balance
$ 4,169
$ 3,791
Liabilities incurred
Revisions in estimated liabilities (1)
Liabilities settled
-
(4 )
Accretion expense
Dispositions (2)
(11 )
(202 )
Ending balance
$ 4,716
$ 4,169
Current liability
$ -
$ -
Long term liability
$ 4,716
$ 4,169
(1) Changes in estimated costs and timing of plugging and abandoning gave rise to the revision in estimated liabilities.
(2) Dispositions during the year ended December 31, 2020 included a swap of producing properties, and dispositions for the year ended December 31, 2019 included sales producing properties.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5-Debt
Debt consisted of the following balances as of the dates indicated (in thousands):
December 31, 2020
December 31, 2019
Principal
Carrying Amount
Fair Value
Principal
Carrying Amount
Fair Value
2019 Senior Credit Facility (1)
96,400
96,400
96,400
92,900
92,900
92,900
2021/2022 Second Lien Notes (2)
14,811
13,759
15,107
12,969
11,535
12,952
Total debt
$ 111,211
$ 110,159
$ 111,507
$ 105,869
$ 104,435
$ 105,852
(1)
The carrying amount for the 2019 Senior Credit Facility represents fair value as it was fully secured.
(2) The debt discount is being amortized using the effective interest rate method based upon a maturity date of May 31, 2022. The principal includes paid-in-kind interest of $2.8 million as of December 31, 2020 and $1.0 million as of December 31, 2019. The carrying value includes $0.9 million of unamortized debt discount and $0.2 million of unamortized issuance cost at December 31, 2020. The carrying value includes $1.1 million of unamortized debt discount and $0.3 million of unamortized issuance cost at December 31, 2019. The fair value of the 2021/2022 Second Lien Notes, a Level 2 fair value estimate, was obtained by using the last known sale price for the value on December 31, 2020.
The following table summarizes the total interest expense (contractual interest expense, amortization of debt discount, accretion and financing costs) and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates) for the periods as noted below:
Year Ended December 31, 2020
Year Ended December 31, 2019
Interest Expense
Effective Interest Rate
Interest Expense
Effective Interest Rate
2017 Senior Credit Facility
$ -
0.0 %
$
7.2 %
2019 Senior Credit Facility
4,543
4.7 %
3,409
6.0 %
2019 Second Lien Notes (1)
-
0.0 %
5,304
24.1 %
2021/2022 Second Lien Notes (2)
2,506
19.7 %
1,416
21.6 %
Total
$ 7,049
$ 11,001
(1) The 2019 Second Lien Notes had a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 24.1% for the year ended December 31, 2019 (until payoff on May 29, 2019). Interest expense for the year ended December 31, 2019 included $2.3 million of debt discount amortization and $3.0 million of paid-in-kind interest.
(2) The 2021/2022 Second Lien Notes have a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 19.7% and 21.6% for the years ended December 31, 2020 and 2019, respectively. Interest expense for the year ended December 31, 2020 included $1.8 million of accrued interest to be paid in-kind, $0.5 million of debt discount amortization and $0.2 million issuance cost amortization. Interest expense for the year ended December 31, 2019 included $1.0 million of accrued interest to be paid in-kind, $0.3 million of debt discount amortization and $0.1 million of issuance cost amortization.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2017 Senior Credit Facility
On October 17, 2017, the Company entered into the Amended and Restated Senior Secured Revolving Credit Agreement (as amended, the “2017 Credit Agreement”) with the Subsidiary, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders that are party thereto, which provided for revolving loans of up to the borrowing base then in effect (as amended, the “2017 Senior Credit Facility”). The 2017 Senior Credit Facility was set to mature on (a) October 17, 2021 or (b) December 30, 2019, if the 2019 Second Lien Notes had not been voluntarily redeemed, repurchased, refinanced or otherwise retired by December 30, 2019. The maximum credit amount under the 2017 Senior Credit Facility when it was paid off in full on May 14, 2019 was $250.0 million with a borrowing base of $75.0 million.
All amounts outstanding under the 2017 Senior Credit Facility bore interest at a rate per annum equal to, at the Company's option, either (i) the alternative base rate plus an applicable margin ranging from 1.75% to 2.75%, depending on the percentage of the borrowing base that was utilized, or (ii) adjusted LIBOR plus an applicable margin ranging from 2.75% to 3.75%, depending on the percentage of the borrowing base that was utilized. Undrawn amounts under the 2017 Senior Credit Facility were subject to a 0.50% commitment fee.
The obligations under the 2017 Credit Agreement were secured by a first lien security interest in substantially all of the assets of the Company and the Subsidiary.
On May 14, 2019, the 2017 Senior Credit Facility was paid off in full and amended, restated and refinanced into the 2019 Senior Credit Facility. In connection with the refinancing, we recorded a $0.2 million loss on early extinguishment of debt related to the remaining unamortized debt issuance costs.
2019 Senior Credit Facility
On May 14, 2019, the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the “2019 Credit Agreement”) among the Company, the Subsidiary, as borrower (in such capacity, the “Borrower”), SunTrust Bank, as administrative agent (the “Administrative Agent”), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “2019 Senior Credit Facility”).
The 2019 Senior Credit Facility matures on (a) May 14, 2024 or (b) December 2, 2022, if the 2023 Second Lien Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by December 2, 2022, which is the date that is 180 days prior to the May 31, 2023 “Maturity Date” of the 2023 Second Lien Notes. The 2019 Senior Credit Facility provides for a maximum credit amount of $500 million subject to a borrowing base limitation, which was $120.0 million as of December 31, 2020. The borrowing base is scheduled to be redetermined in March and September of each calendar year, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and the Administrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders at their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Borrower may also request the issuance of letters of credit under the 2019 Credit Agreement in an aggregate amount up to $10 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.
All amounts outstanding under the 2019 Senior Credit Facility bear interest at a rate per annum equal to, at the Company’s option, either (i) the alternative base rate plus an applicable margin ranging from 1.50% to 2.50%, depending on the percentage of the borrowing base that is utilized, or (ii) adjusted LIBOR plus an applicable margin from 2.50% to 3.50%, depending on the percentage of the borrowing base that is utilized. Undrawn amounts under the 2019 Senior Credit Facility are subject to a commitment fee ranging from 0.375% to 0.50%, depending on the percentage of the borrowing base that is utilized. To the extent that a payment default exists and is continuing, all amounts outstanding under the 2019 Senior Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of December 31, 2020, the weighted average interest rate on the borrowings from the 2019 Senior Credit Facility was 3.49%. The obligations under the 2019 Credit Agreement are guaranteed by the Company and secured by a first lien security interest in substantially all of the assets of the Company and the Borrower.
The 2019 Credit Agreement contains certain customary representations and warranties, affirmative and negative covenants and events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the 2019 Senior Credit Facility to be immediately due and payable.
The 2019 Credit Agreement also contains certain financial covenants, including the maintenance of (i) a ratio of Net Funded Debt to EBITDAX not to exceed 3.50 to 1.00 as of the last day of any fiscal quarter, (ii) a current ratio (based on the ratio of current assets to current liabilities as defined in the 2019 Credit Agreement) not to be less than 1.00 to 1.00 and (iii) until no 2023 Second Lien Notes remain outstanding, a ratio of Total Proved PV-10 attributable to the Company’s and Borrower’s Proved Reserves to Total Secured Debt (net of any Unrestricted Cash not to exceed $10 million) not to be less than 1.50 to 1.00 and minimum liquidity requirements. On May 14, 2019, the Company utilized borrowings under the 2019 Senior Credit Facility to refinance its obligations under the 2017 Senior Credit Facility and to fund the redemption of the 2019 Second Lien Notes. On October 30, 2020, the Company entered into a Third Amendment to Credit Agreement (the “Third Amendment”) with the Subsidiary, Truist Bank, as administrative agent, and the lenders party thereto, which, among other things, added an anti-cash hoarding covenant, which requires mandatory prepayments of the loans then outstanding with the amount of certain cash on the balance sheet in excess of $10 million, as set forth in greater detail in the Third Amendment. Additionally, the Third Amendment included updated language surrounding a benchmark replacement rate in anticipation of the phase out of LIBOR.
As of December 31, 2020, the Company had a borrowing base of $120.0 million with $96.4 million of borrowings outstanding. The Company also had $1.7 million of unamortized debt issuance costs recorded as of December 31, 2020 related to the 2019 Senior Credit Facility.
As of December 31, 2020, the Company was in compliance with all covenants within the 2019 Senior Credit Facility with the exception of the current ratio. On March 9, 2021, the Company entered into a Fourth Amendment to Credit Agreement (the “Fourth Amendment”) with the Subsidiary, Truist Bank, as administrative agent, and the lenders party thereto, pursuant to which, among other things, the lenders agreed to waive the default caused by our failure to comply with the current ratio financial covenant under the 2019 Senior Credit Facility as of the last day of the fiscal quarter ended December 31, 2020.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Convertible Second Lien Notes
In October 2016, the Company issued $40.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2019 (the “2019 Second Lien Notes”) along with 10-year costless warrants to acquire 2.5 million shares of common stock. Holders of the 2019 Second Lien Notes had a second priority lien on all assets of the Company, and holders of such warrants had a right to appoint two members to our Board of Directors (the “Board”) as long as such warrants were outstanding.
The 2019 Second Lien Notes were scheduled to mature on August 30, 2019 or six months after the maturity of our current revolving credit facility but in no event later than March 30, 2020. The 2019 Second Lien Notes bore interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company also had the option under certain circumstances to pay all or any portion of interest in-kind on the then outstanding principal amount of the 2019 Second Lien Notes by increasing the principal amount of the outstanding 2019 Second Lien Notes or by issuing additional second lien notes.
Upon issuance of the 2019 Second Lien Notes in October 2016, in accordance with accounting standards related to convertible debt instruments that may be settled in cash upon conversion as well as warrants on the debt instrument, we recorded a debt discount of $11.0 million, thereby reducing the $40.0 million carrying value upon issuance to $29.0 million and recorded an equity component of $11.0 million. The debt discount was amortized using the effective interest rate method based upon an original term through August 30, 2019. The 2019 Second Lien Notes were redeemed in full on May 29, 2019 for $56.7 million, using borrowings under the 2019 Senior Credit Facility. In connection with the redemption of the 2019 Second Lien Notes, we recorded a $1.6 million loss on early extinguishment of debt related to the remaining unamortized debt discount and debt issuance costs.
On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement with certain purchasers pursuant to which the Company issued to such purchasers $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “2021/2022 Second Lien Notes”). Proceeds from the sale of the 2021/2022 Second Lien Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility. In May 2020, the maturity date of the 2021/2022 Second Lien Notes was extended to May 31, 2022.
Upon issuance of the 2021/2022 Second Lien Notes on May 31, 2019, in accordance with accounting standards related to convertible debt instruments that may be settled in cash upon conversion, we recorded a debt discount of $1.4 million, thereby reducing the $12.0 million carrying value upon issuance to $10.6 million and recorded an equity component of $1.4 million. The equity component was valued using a binomial model. The debt discount is amortized using the effective interest rate method based upon an original term through May 31, 2021. Upon the maturity extension in May 2020, an additional $0.3 million of debt discount was recorded, and the debt discount began to be amortized using the effective interest rate method based upon the maturity date of May 31, 2022.
As of December 31, 2020, $0.9 million of debt discount and $0.2 million of debt issuance costs remained to be amortized on the 2021/2022 Second Lien Notes.
As of December 31, 2020, the Company was in compliance with all covenants within the 2021/2022 Second Lien Notes Indenture.
On March 9, 2021, the Company and the Subsidiary entered into a purchase and exchange agreement with certain purchasers (each such purchaser, together with its successors and assigns, a “2023 Second Lien Notes Purchaser”) pursuant to which the Company issued to the 2023 Second Lien Notes Purchasers (the “2023 Second Lien Notes Offering”) (A) $15.2 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2023 (the “2023 Second Lien Notes”) in exchange for an equal amount of 2021/2022 Second Lien Notes and (B) $15.0 million of the 2023 Second Lien Notes in exchange for cash. Proceeds from the sale of the 2023 Second Lien Notes were used to pay down outstanding borrowings under the 2019 Senior Credit Facility.
The 2023 Second Lien Notes, as set forth in the indenture governing the 2023 Second Lien Notes (the “2023 Second Lien Notes Indenture”), are scheduled to mature on May 31, 2023. The 2023 Second Lien Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the 2023 Second Lien Notes by increasing the principal amount of the outstanding 2023 Second Lien Notes.
The 2023 Second Lien Notes Indenture contains certain covenants pertaining to us and our Subsidiary, including delivery of financial reports; environmental matters; conduct of business; use of proceeds; operation and maintenance of properties; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; limits on sales of assets and stock; business activities; transactions with affiliates; and changes of control. The 2023 Second Lien Notes Indenture also contains a financial covenant which requires the maintenance of a ratio of Total Proved PV-10 attributable to the Company's and Subsidiary's Proved Reserves (as defined in the 2023 Second Lien Notes Indenture) to Total Secured Debt (net of any Unrestricted Cash not to exceed $10.0 million) not to be less than 1.50 to 1.00.
The 2023 Second Lien Notes are convertible into the Company’s common stock at the conversion rate, which is the sum of the outstanding principal amount of 2023 Second Lien Notes to be converted, including any accrued and unpaid interest, divided by the conversion price, which shall initially be $21.33, subject to certain adjustments as described in the 2023 Second Lien Notes Indenture. Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the 2023 Second Lien Notes Indenture, (2) cash or (3) a combination of shares of its common stock and cash; however, the Company’s ability to redeem the 2023 Second Lien Notes with cash is subject to the terms of the 2019 Senior Credit Agreement.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6-Net Income (Loss) Per Common Share
Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted net income (loss) per common share for the periods as noted below. The Company used the treasury stock method in determining the effects of potentially dilutive restricted stock. The following table sets forth information related to the computations of basic and diluted net income (loss) per common share:
Year Ended December 31, 2020
Year Ended December 31, 2019
Basic net income (loss) per common share:
Net income (loss) applicable to common stock
$ (44,141 )
$ 13,288
Weighted-average shares of common stock outstanding
12,617
12,233
Basic net income (loss) per common share
$ (3.50 )
$ 1.09
Diluted net income (loss) per common share:
Net income (loss) applicable to common stock
$ (44,141 )
$ 13,288
Weighted-average shares of common stock outstanding
12,617
12,233
Common shares issuable upon conversion of warrants of unsecured claim holders
-
1,314
Common shares issuable on assumed conversion of restricted stock *
-
Diluted weighted average shares of common stock outstanding
12,617
13,895
Diluted net income (loss) per common share (1) (2) (3)
$ (3.50 )
$ 0.96
(1) Common shares issuable upon conversion of the 2021/2022 Second Lien Notes and 2019 Second Lien Notes were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.
(2) Common shares issuable upon conversion of the unsecured claims warrants not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive for the twelve months ended December 31, 2020.
1,409
-
(3) Common shares issuable upon conversion of the restricted stock not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive for the twelve months ended December 31, 2020. **
-
** Common shares issuable on assumed conversion of share-based compensation assumes a payout of the Company's performance share awards at 100% of the initial units granted (or a ratio of one unit to one common share). The range of common stock shares which may be earned ranges from zero to 200% of the initial performance units granted.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7-Income Taxes
The following table summarizes the tax expense (benefit) for the periods as noted below (in thousands):
Year Ended December 31, 2020
Year Ended December 31, 2019
Current tax expense (benefit)
Federal
$ (393 )
$ (393 )
State
-
-
Total current tax expense (benefit)
(393 )
(393 )
Deferred tax expense (benefit)
Federal
State
-
-
Total deferred tax expense (benefit)
Total tax expense (benefit)
$ -
$ -
The following is a reconciliation of the U.S. statutory income tax rate at 21% to our income before income taxes (in thousands):
Year Ended December 31, 2020
Year Ended December 31, 2019
Income tax expense (benefit)
Tax expense (benefit) at U.S. statutory rate
$ (9,270 )
$ 2,790
Disallowed executive compensation
Valuation allowance
12,547
(5,499 )
State income taxes, net of federal benefit
(3,597 )
Nondeductible expenses and other
(149 )
1,170
Total tax expense (benefit)
$ -
$ -
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (in thousands) for the years ended December 31, 2020 and 2019:
December 31,
Non-current deferred tax assets:
Operating loss carry-forwards
$ 47,778
$ 45,280
State tax NOL and credits
13,191
11,611
AMT tax credit carry-forward
-
Compensation
1,024
1,461
Contingent liabilities and other
Lease liabilities
Derivatives
1,050
-
Property and equipment
23,756
16,813
Total gross non-current deferred tax assets
87,637
76,401
Less valuation allowance
(86,697 )
(74,150 )
Net non-current deferred tax assets
2,251
Non-current deferred tax liabilities:
Derivatives
-
(1,214 )
Right of use asset
(719 )
(350 )
Other
(65 )
(97 )
Debt discount
(156 )
(197 )
Total non-current deferred tax liabilities
(940 )
(1,858 )
Net non-current deferred tax asset
$ -
$
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We recorded no income tax expense or benefit for the years ended December 31, 2020 or 2019. We maintained a valuation allowance as of December 31, 2020, which resulted in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance after an evaluation of all available evidence (including commodity prices and our history of tax net operating losses (“NOLs”) in 2020 and prior years) led to a conclusion that based upon the more-likely-than-not standard of the accounting literature our deferred tax assets were unrecoverable. The valuation allowance for deferred tax assets increased by $12.5 million to $86.7 million in 2020 related to current year activity. The valuation allowance was $74.2 million as of December 31, 2019, which resulted in a net non-current deferred tax asset of $0.4 million appearing on our statement of financial position at that time. The net $0.4 million deferred tax asset related to alternative minimum tax (“AMT”) credits which were refundable to the Company. Such AMT credits and accrued interest were subsequently received in the third quarter of 2020. The valuation allowance has no impact on our NOL position for tax purposes, and if we generate taxable income in future periods, we may be able to use our NOLs to offset taxable income at that time subject to any applicable tax limitations on NOLs.
As of December 31, 2020, we have federal net operating loss carry-forwards of approximately $858.5 million. These carry-forwards are subject to limitation by IRC Section 382 and it is estimated $227.5 million will be available to offset future U.S taxable income.
IRC Sections 382 and 383 provide an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in losses, against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from bankruptcy in October 2016 triggered a change in ownership for purposes of IRC Section 382. The limitation under the tax code is based on the value of the Company when it emerged from bankruptcy on October 12, 2016. This ownership change resulted in limitation which will eliminate an estimated $630.7 million of federal net operating losses previously available to offset future U.S. taxable income. The Company also has net operating losses in Louisiana and Mississippi which are subject to limitation due to the ownership change. The Company estimates state NOLs available for use of $96.6 million in Louisiana and $160.0 million in Mississippi after the reduction for unusable NOLs due to the ownership change.
We did not have any unrecognized tax benefits as of December 31, 2020. The amount of unrecognized tax benefits may change in the next twelve months; however, we do not expect the change to have a significant impact on our results of operations or our financial position. We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions. With limited exceptions, we are no longer subject to U.S. Federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2010.
Our continuing practice is to recognize estimated interest and penalties related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated Statement of Operations. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations before December 31, 2020.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8-Stockholders’ Equity
At December 31, 2020 there were 13,392,625 shares of our Company common stock outstanding and 75,000,000 shares authorized at $0.01 par value per share.
During the year ended December 31, 2020, the Company had vestings of its share-based compensation units representing a total fair value of $13.3 million and resulting in the issuance of approximately 1,282,000 common shares. During the year ended December 31, 2020, the Company paid $4.2 million in cash for the purchase of approximately 409,000 Treasury shares withheld from employees upon the vesting of restricted stock awards for the payment of taxes. All shares held in Treasury in 2020 were retired prior to December 31, 2020.
During the year ended December 31, 2019, the final 150,000 of the 10-year costless warrants associated with the 2019 Second Lien Notes were exercised. The Company received cash for the one cent par value for the issuance of the 150,000 common shares. During the year ended December 31, 2019, the Company had vestings of its share-based compensation units representing a total fair value of $5.1 million and resulting in the issuance of approximately 530,000 common shares. During the year ended December 31, 2019, the Company paid $2.1 million in cash for the purchase of approximately 208,000 Treasury shares withheld from employees upon the vesting of restricted stock awards for the payment of taxes. All shares held in Treasury in 2019 were retired prior to December 31, 2019.
In connection with the issuance of the 2021/2022 Second Lien Notes in May 2019, we recorded an equity component of $1.4 million, and in connection with the extension of the 2021/2022 Second Lien Notes in May 2020, we recorded an additional equity component of $0.3 million. For further details, see Note 5.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9-Derivative Activities
We use commodity and financial derivative contracts to manage fluctuations in commodity prices and interest rates. We are currently not designating our derivative contracts for hedge accounting. All derivative gains and losses during 2020 and 2019 are from our oil and natural gas derivative contracts and have been recognized in “Other income (expense)” on our Consolidated Statements of Operations.
The following table summarizes the gains and losses we recognized on our oil and natural gas derivatives for the periods as noted below:
Oil and Natural Gas Derivatives (in thousands)
Year Ended December 31, 2020
Year Ended December 31, 2019
Gain on commodity derivatives not designated as hedges, settled
$ 15,192
$ 9,560
Gain (loss) on commodity derivatives not designated as hedges, not settled
(10,784 )
5,450
Total gain on commodity derivatives not designated as hedges
$ 4,408
$ 15,010
Commodity Derivative Activity
We enter into swap contracts, costless collars or other derivative agreements from time to time to manage commodity price risk for a portion of our production. Our policy is that all derivative contracts are approved by the Hedging Committee of our Board and reviewed periodically by the Board.
Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Decreases in domestic crude oil and natural gas spot prices will have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis. We routinely exercise our contractual right to net realized gains against realized losses when settling with our financial counterparties. Neither our counterparties nor we require any collateral upon entering into derivative contracts. We were not at risk of losing any fair value amounts had our counterparties been unable to fulfill their obligations as of December 31, 2020.
As of December 31, 2020, the open positions on our outstanding commodity derivative contracts, all of which were with Truist Bank, RBC Capital Markets, ARM Energy, and Citizens Commercial Banking, and the associated fair values (in thousands) were as follows:
Contract Type
Average Daily Volume
Total Volume
Weighted Average Fixed Price
December 31, 2020
Crude oil swaps (Bbls)
2021 (through March 31, 2021)
18,000
$ 56.58
$
Total oil
Natural gas swaps (MMBtu)
63,258
23,089,000
$ 2.56
$ (2,191 )
2022 (through March 31, 2022)
70,000
6,300,000
$2.53
(2,125 )
Natural gas collars (MMBtu)
29,260
10,680,000
$2.40-$3.52
2022 (through March 31, 2022)
30,000
2,700,000
$2.50-$3.52
Total natural gas
(3,337 )
Natural gas basis swaps (MMBtu)
50,000
18,250,000
NYMEX - $0.209
(54 )
50,000
18,250,000
NYMEX - $0.209
(321 )
50,000
18,250,000
NYMEX - $0.209
(516 )
50,000
18,300,000
NYMEX - $0.209
(917 )
Total natural gas basis
(1,808 )
Total
$ (5,002 )
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of December 31, 2020 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Note 1 for our discussion regarding fair value, including inputs used and valuation techniques for determining fair values.
Description
Level 1
Level 2
Level 3
Total
Fair value of oil and natural gas derivatives - Current Assets
$ -
$
$ -
$
Fair value of oil and natural gas derivatives - Non-current Assets
-
-
-
-
Fair value of oil and natural gas derivatives - Current Liabilities
-
(1,274 )
-
(1,274 )
Fair value of oil and natural gas derivatives - Non-current Liabilities
-
(3,871 )
-
(3,871 )
Total
$ -
$ (5,002 )
$ -
$ (5,002 )
We enter into oil and natural gas derivative contracts under which we have netting arrangements with each counter-party. The following table discloses and reconciles the gross amounts to the amounts as presented on the Consolidated Balance Sheets for the periods ending December 31, 2020:
December 31, 2020
Fair Value of Oil and Natural Gas Derivatives (in thousands)
Gross Amount
Amount Offset
As Presented
Fair value of oil and natural gas derivatives - Current Assets
$ 3,193
$ (3,050 )
$
Fair value of oil and natural gas derivatives - Non-current Assets
(537 )
-
Fair value of oil and natural gas derivatives - Current Liabilities
(4,324 )
3,050
(1,274 )
Fair value of oil and natural gas derivatives - Non-current Liabilities
(4,408 )
(3,871 )
Total
$ (5,002 )
$ -
$ (5,002 )
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 10-Commitments and Contingencies
We are party to various lawsuits from time to time arising in the normal course of business, including, but not limited to, royalty, contract, personal injury, and environmental claims. We have established reserves as appropriate for all such proceedings and intend to vigorously defend these actions. Management believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position results of operations, cash flows or liquidity.
The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2020 (in thousands):
Payment due by Period
Note
Total
2025 and After
Debt
$ 111,211
$ -
$ 14,811
$ -
$ 96,400
$ -
Office space leases
4,781
1,238
1,592
Operations contracts
1,469
1,406
-
-
Total contractual obligations (1)
$ 117,461
$ 2,644
$ 15,479
$
$ 97,061
$ 1,592
(1)
This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $4.7 million as of December 31, 2020. We record a separate liability for the asset retirement obligations. See Note 4.
Operating Leases-We have commitments under an operating lease agreements for office space and office equipment leases. Total rent expense for the years ended December 31, 2020, and 2019 was approximately $1.5 million and $1.7 million, respectively.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11-Leases
We adopted ASU 2016-02, Leases, on January 1, 2019, and we elected the transition relief package of practical expedients. We determine if an arrangement is or contains a lease at inception. Leases with an initial term of 12 months or less are not recorded on our Consolidated Balance Sheets. We lease our corporate office building in Houston, Texas. We recognize lease expense for this lease on a straight-line basis over the lease term. This operating lease is included in furniture, fixtures and equipment and other capital assets, accrued liabilities and other non-current liabilities on our Consolidated Balance Sheets. The operating lease asset and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term. As this lease did not provide an implicit rate, we used a collateralized incremental borrowing rate based on the information available at commencement date, including lease term, in determining the present value of future payments. The operating lease asset includes any lease payments made but excludes annual operating charges. Operating lease expense is recognized on a straight-line basis over the lease term and reported in general and administrative operating expense on our Consolidated Statements of Operations. We have also entered into leases for certain vehicles and other equipment which are immaterial to our financial statements and have therefore not been recorded on our Consolidated Balance Sheets.
The lease cost components for the year ended December 31, 2020 are classified as follows:
(in thousands)
Year Ended December 31, 2020
Year Ended December 31, 2019
Consolidated Statements of Operations Classification
Building lease cost
$ 1,341
$ 1,540
General and administrative expense
Variable lease cost (1)
General and administrative expense
$ 1,498
$ 1,658
(1) Includes building operating expenses.
The following are additional details related to our lease portfolio as of December 31, 2020:
(in thousands)
December 31, 2020
Consolidated Balance Sheets Classification
Lease asset, gross
$ 5,871
Furniture, fixtures and equipment and other capital assets
Accumulated depreciation
(2,445 )
Accumulated depletion, depreciation and amortization
Lease asset, net
$ 3,426
Current lease liability
$
Accrued liabilities
Non-current lease liability
2,810
Other non-current liabilities
Total lease liabilities
$ 3,772
The following table presents operating lease liability maturities as of December 31, 2020:
(in thousands)
December 31, 2020
1,238
Thereafter
1,592
Total lease payments
$ 4,781
Less imputed interest
$ 1,009
Present value of lease liabilities
$ 3,772
As of December 31, 2020, our office building operating lease has a weighted-average remaining lease term of 0.3 years and a weighted-average discount rate of 8.0 percent. Cash paid for amounts included in the measurement of operating lease liabilities for our building was $1.5 million for the year ended December 31, 2020.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12-COVID-19 Pandemic
The impact of the COVID-19 pandemic and related economic, business and market disruptions is both on-going and continuing to evolve, and its future effects are uncertain. The Company has seen impacts related to COVID-19 on oil price fluctuations due to market uncertainty.
Because we predominately produce natural gas and natural gas has not been impacted by the same market forces as crude oil, we have experienced less of an impact from COVID-19 than many of our peers. However, the scope and length of the COVID-19 pandemic and the ultimate effect on the price of natural gas and oil cannot be determined, and we could be adversely affected in future periods. Management is actively monitoring the impact on the Company’s results of operations, financial position, and liquidity in fiscal year 2020.
NOTE 13-Subsequent Events
On March 9, 2021, the Company completed the 2023 Second Lien Notes Offering. See Note 5-Debt.
On March 9, 2021, the Company entered into the Fourth Amendment, pursuant to which, among other things, the lenders agreed to waive the default caused by our failure to comply with the current ratio financial covenant under the 2019 Senior Credit Facility as of the last day of the fiscal quarter ended December 31, 2020. See Note 5-Debt.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
SUPPLEMENTAL INFORMATION
(Unaudited)
NOTE 14-Oil and Natural Gas Producing Activities (Unaudited)
Overview
All of our reserve information related to crude oil, condensate and natural gas was compiled based on estimates prepared and reviewed by our external engineers. The technical persons primarily responsible for overseeing the preparation of the reserves estimates meet the requirements regarding qualifications. Our internal professional staff has over 20 years of experience in the oil and natural gas industry, including over 15 years as a reserve evaluator, trainer or manager. Further professional qualifications include extensive internal and external reserve training. The reserves estimation is part of our internal controls process subject to management’s annual review and approval. These reserves estimates are prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company (“RSC”), our independent reserve engineer consulting firms. All of our proved reserves estimates shown herein at December 31, 2020 and 2019 have been independently prepared by NSAI and RSC. NSAI prepared the estimates on all our proved reserves as of December 31, 2020 and 2019 on our properties other than in the TMS. RSC prepared the estimate of proved reserves as of December 31, 2020 and 2019 for our TMS properties. Copies of the summary reserve reports of NSAI and RSC for 2020 are filed as exhibits 99.1 and 99.2, respectively to this Annual Report on Form 10-K. All of the subject reserves are located in the continental United States, primarily in Texas, Louisiana and Mississippi.
Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject to future revisions, some of which may be substantial, as additional information becomes available. Such additional knowledge may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other factors.
Regulations published by the SEC define proved oil and natural gas reserves as those quantities of oil and natural gas which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well.
Prices we used to value our reserves are based on the twelve-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2020. For oil volumes, the average price of $39.57 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For natural gas volumes, the average price of $1.99 per MMBtu is adjusted by lease for energy content, transportation fees, and regional price differentials.
Capitalized Costs
The table below reflects our capitalized costs related to our oil and natural gas producing activities at December 31, 2020 and 2019 (in thousands):
Year Ended December 31, 2020
Year Ended December 31, 2019
Proved properties
$ 359,112
$ 302,859
Unproved properties
359,352
302,982
Less: accumulated depreciation, depletion and amortization
(173,989 )
(91,958 )
Net oil and natural gas properties
$ 185,363
$ 211,024
We did not have any capitalized exploratory well costs that were pending the determination of proved reserves as of December 31, 2020 and 2019, respectively.
Costs Incurred
Costs incurred in oil and natural gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows (in thousands):
Year Ended December 31, 2020
Year Ended December 31, 2019
Property Acquisition
Unproved
$
$
Proved
-
-
Exploration
-
-
Development (1)
56,330
97,972
Total (2)
$ 56,382
$ 98,241
(1)
Includes asset retirement costs of $0.2 million in 2020 and $0.1 million in 2019.
(2)
Substantially all the costs incurred related to the Haynesville Shale Trend.
The following table sets forth our net proved oil and natural gas reserves at December 31, 2020, 2019 and 2018 and the changes in net proved oil and natural gas reserves during such years, as well as proved developed and proved undeveloped reserves at the beginning and end of each year:
Natural Gas (Mmcf)
Oil, Condensate and NGLs (MBbls)
Net proved reserves at beginning of period
510,066
470,937
415,224
1,104
1,441
2,130
Revisions of previous estimates (1)
(103,288 )
(132,005 )
(16,993 )
(434 )
(166 )
(388 )
Extensions, discoveries and improved recovery (2)
181,002
218,015
100,499
-
-
-
Purchases of minerals in place
-
-
-
-
-
Sales of minerals in place
-
(169 )
(3,349 )
-
-
(84 )
Production
(48,110 )
(46,712 )
(24,444 )
(143 )
(171 )
(217 )
Net proved reserves at end of period
540,004
510,066
470,937
1,104
1,441
Net proved developed reserves:
Beginning of period
138,607
92,118
52,861
1,104
1,441
2,130
End of period
151,732
138,607
92,118
1,104
1,441
Net proved undeveloped reserves:
Beginning of period
371,459
378,819
362,363
-
-
-
End of period
388,272
371,459
378,819
-
-
-
Natural Gas Equivalents (Mmcfe)
Net proved reserves at beginning of period
516,691
479,583
428,002
Revisions of previous estimates (1)
(105,895 )
(133,001 )
(19,320 )
Extensions, discoveries and improved recovery (2)
181,002
218,016
100,499
Purchases of minerals in place (3)
-
-
Sales of minerals in place (4)
-
(169 )
(3,852 )
Production
(48,968 )
(47,738 )
(25,746 )
Net proved reserves at end of period
543,164
516,691
479,583
Net proved developed reserves:
Beginning of period
145,232
100,764
65,639
End of period
154,892
145,232
100,764
Net proved undeveloped reserves:
Beginning of period
371,459
378,819
362,363
End of period
388,272
371,459
378,819
(1)
Revisions of previous estimates in 2020 and 2019 were negative, primarily due to commodity prices. Revisions of previous estimates in 2018 were negative, primarily due to increases in our operating expenditures and other tax rates.
(2)
Extensions and discoveries were positive on an overall basis in all three periods presented, primarily reflecting our successful drilling results on our Haynesville Shale Trend properties.
(3) In 2020, we acquired approximately 334 Mmcfe through a well swap transaction.
(4)
In 2019, we sold approximately 55 Mmcfe and in 2018, we sold approximately 2,500 Mmcfe, attributed to the sale of producing properties in the TMS and Haynesville Shale.
Standardized Measure
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of year-end is shown below (in thousands):
Future revenues
$ 1,016,173
$ 1,272,504
$ 1,494,557
Future lease operating expenses and production taxes
(355,052 )
(377,851 )
(410,957 )
Future development costs (1)
(278,480 )
(338,116 )
(349,552 )
Future income tax expense
-
(13,945 )
(56,784 )
Future net cash flows
382,641
542,592
677,264
10% annual discount for estimated timing of cash flows
(199,904 )
(248,269 )
(279,679 )
Standardized measure of discounted future net cash flows
$ 182,737
$ 294,323
$ 397,585
Index price used to calculate reserves (2)
Natural gas (per Mcf)
$ 1.99
$ 2.58
$ 3.10
Oil (per Bbl)
$ 39.57
$ 55.69
$ 65.56
(1)
Includes cumulative asset retirement obligations of $7.9 million and $7.4 million in 2020 and 2019, respectively.
(2)
These index prices, used to estimate our reserves at these dates, are before deducting or adding applicable transportation and quality differentials on a well-by-well basis.
The estimated future net cash flows are discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount.
Changes in the Standardized Measure
The following are the principal sources of change in the standardized measure of discounted net cash flows for the years shown (in thousands):
Year Ended December 31,
Balance, beginning of year
$ 294,323
$ 397,585
$ 260,310
Net changes in prices and production costs related to future production
(151,520 )
(146,806 )
95,927
Sales and transfers of oil and natural gas produced, net of production costs
(58,987 )
(82,706 )
(63,846 )
Net change due to revisions in quantity estimates
(65,342 )
(130,244 )
(25,595 )
Net change due to extensions, discoveries and improved recovery
41,512
101,012
129,207
Net change due to purchases and sales of minerals in place
(1,653 )
(3,382 )
Changes in future development costs
131,548
125,172
(4,608 )
Previously estimated development cost incurred in period
24,523
31,340
7,923
Net change in income taxes
2,631
17,555
(16,336 )
Accretion of discount
29,695
41,777
26,416
Change in production rates (timing) and other
(63,993 )
(60,372 )
(8,431 )
Net increase (decrease) in standardized measures
(111,586 )
(103,262 )
137,275
Balance, end of year
$ 182,737
$ 294,323
$ 397,585

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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
Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2020. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2020.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15(d)-15(f) promulgated under the Securities Exchange Act of 1934, as amended). We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission and that any material information relating to us is recorded, processed, summarized and reported to our management including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report and, during the third and fourth quarters of fiscal year 2020, identified a material weakness in our internal control over financial reporting. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2020.
Notwithstanding the identified material weakness, the Company's management, including our Chief Executive Officer and Chief Financial Officer, have determined, based on the procedures we have performed, that the unaudited consolidated financial statements included in this report fairly present in all material respects our financial condition and results of operations as of and for the years ended December 31, 2020 and 2019 in accordance with U.S. GAAP.
Material Weakness in Internal Control Over Financial Reporting
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis.
During the third and fourth quarters of fiscal year 2020, management, in connection with our independent auditors, identified a material weakness in our controls over the determination of the estimated PV-10 of our reserves. Specifically, we did not design and maintain effective controls to sufficiently review the completeness and accuracy of the future development costs component of the estimated PV-10 of our reserves and, thus, failed to identify the omission of capital expenditure costs from the future costs required to develop certain of our reserves. This material weakness resulted in an undiscovered $7.3 million error in the amount of impairment expense recorded in relation to our oil and gas properties for the three and six months ended June 30, 2020, which required the Company to restate its consolidated financial statements as of and for the three and six months ended June 30, 2020, and also resulted in corrected errors in the amount of impairment expense recorded in relation to our oil and gas properties in the consolidated financial statements of $1.0 million and $3.3 million as of and for the three and nine months ended September 30, 2020 and the three months and year ended December 31, 2020, respectively.
Plan for Remediation of Material Weakness
Our management is actively engaged in the planning for, and implementation of, remediation efforts to address the material weakness identified. Specifically, our management is currently evaluating our policies and procedures related to its process of verifying the completeness and accuracy of data inputs into our reserves calculation. As part of our commitment to strengthening our internal control over financial reporting, we are implementing the following remedial actions under the oversight of the Audit Committee of our Board of Directors to address deficiencies in the preparation of reserves estimates, including:
•
implementation of a quarterly review by independent reserve engineers to verify the completeness and accuracy of data inputs into the reserves calculation;
•
implementation of additional procedures to perform enhanced internal detailed reviews of reserves report components, including (but not necessarily limited to) future development costs; and
•
revision and communication of the accounting controls, policies and procedures relating to identifying and assessing changes that could potentially impact the system of internal control governing the full cost ceiling test calculation.
We will continue to monitor the design and effectiveness of these procedures and controls and make any further changes management determines appropriate. We believe the control improvements described above will remediate the material weakness that management has identified. However, this material weakness will not be considered remediated until the applicable remedial controls operate effectively for a sufficient period of time.
Attestation Report of the Registered Public Accounting Firm
Pursuant to Regulation S-K Item 308(b), this Annual Report on Form 10-K does not include an attestation report of our Company's independent registered public accounting firm regarding internal control over financial reporting.
Changes in Internal Control over Financial Reporting
Except for the remedial actions described above, there were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B.
Other Information
Note Purchase and Exchange Agreement
On March 9, 2021 (the “Closing Date”), the Company and the Subsidiary entered into a note purchase and exchange agreement (the “Purchase and Exchange Agreement”) with certain purchasers (each such purchaser, together with its successors and assigns, the “2023 Second Lien Notes Purchasers”) pursuant to which the Company issued (A) $15.2 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2023 (the “2023 Second Lien Notes”) to certain of the 2023 Second Lien Notes Purchasers in exchange for an equal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2022 (the “2021/2022 Second Lien Notes”) and (B) $15.0 million of the 2023 Second Lien Notes to the 2023 Second Lien Notes Purchasers in exchange for cash.
Indenture
The 2023 Second Lien Notes are governed by an Indenture (the “Indenture”), dated as of the Closing Date, among the Company, as issuer, the Subsidiary, as subsidiary guarantor, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral agent and are senior obligations of the Company and are secured by a second lien on substantially all assets of the Company and the Subsidiary. The 2023 Second Lien Notes are fully and unconditionally guaranteed on a senior secured basis by the Subsidiary.
Interest and Maturity
The 2023 Second Lien Notes will mature on May 31, 2023. The 2023 Second Lien Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may elect to pay all or any portion of interest in kind on the then outstanding principal amount of the 2023 Second Lien Notes by increasing the principal amount of the outstanding 2023 Second Lien Notes or by issuing additional 2023 Second Lien Notes.
Optional Redemption
At any time prior to March 9, 2022, the Company may redeem, in whole or in part, the 2023 Second Lien Notes, at a redemption price equal to 101% of the principal amount of the 2023 Second Lien Notes redeemed plus accrued and unpaid interest thereon, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date).
At any time on or after March 9, 2022, the Company may redeem, in whole or in part, the 2023 Second Lien Notes at a redemption price equal to 100% of the principal amount of the 2023 Second Lien Notes redeemed plus accrued and unpaid interest thereon, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date).
Any redemption shall be made on a pro rata basis, subject to adjustment in a manner that most nearly approximates a pro rata basis.
Change of Control
If the Company experiences certain kinds of changes of control set forth in the Indenture, each holder of the 2023 Second Lien Notes may require the Company to repurchase all or a portion of its 2023 Second Lien Notes for cash at a price equal to 101% of the aggregate principal amount of such 2023 Second Lien Notes, plus any accrued and unpaid interest to the date of repurchase.
Certain Covenants
The Indenture contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Company’s ability and the ability of its restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) make investments; (iv) create certain liens; (v) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vi) transfer or sell assets and subsidiary stock; (vii) engage in transactions with affiliates; (viii) create unrestricted subsidiaries; and (ix) consolidate, merge or transfer all or substantially all of their assets.
Events of Default
Upon an Event of Default (as defined in the Indenture), the Trustee or the holders of at least 25% of the aggregate principal amount of the then outstanding 2023 Second Lien Notes may declare the 2023 Second Lien Notes immediately due and payable, except that a default resulting from certain events of bankruptcy or insolvency with respect to the Company, any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding 2023 Second Lien Notes to become due and payable.
The foregoing description of the Indenture is qualified in its entirety by reference to such Indenture, a copy of which is filed herewith as Exhibit 4.3 and is incorporated herein by reference.
Credit Agreement Amendment
On the Closing Date, the Company entered into the Fourth Amendment to Credit Agreement with the Subsidiary, Truist Bank, as administrative agent, and the lenders party thereto, which, among other things, permitted the issuance of the 2023 Second Lien Notes and pursuant to which the lenders under the Company’s senior credit facility agreed to waive the default caused by our failure to comply with the current ratio financial covenant under such facility as of the last day of the fiscal quarter ended December 31, 2020.
The foregoing description of the Fourth Amendment to Credit Agreement is qualified in its entirety by reference to such Fourth Amendment to Credit Agreement, a copy of which is filed herewith as Exhibit 10.5 and is incorporated herein by reference.
Registration Rights Agreement
On the Closing Date, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with the 2023 Second Lien Notes Purchasers, pursuant to which the Company agreed to file with the Securities and Exchange Commission within 90 days following the Closing Date, a shelf registration statement for the offer and resale of the 2023 Second Lien Notes held by certain holders that duly request inclusion in such registration statement within 30 days of the Closing Date. The holders have customary demand, underwritten offering and piggyback registration rights, subject to the limitations set forth in the Registration Rights Agreement. Under their underwritten offering registration rights, the holders may request to sell all or any portion of their registrable securities (as defined in the Registration Rights Agreement) in an underwritten offering that is registered, subject to certain restrictions. The Registration Rights Agreement contains other customary terms and conditions, including, without limitation, provisions with respect to blackout periods and indemnification.
The foregoing description of the Registration Rights Agreement is qualified in its entirety by reference to such Registration Rights Agreement, a copy of which is filed herewith as Exhibit 4.2 and is incorporated herein by reference.
Termination of 2021/2022 Second Lien Notes Indenture
In connection with the issuance of the 2023 Second Lien Notes described above, on March 9, 2021, the Company cancelled the remaining outstanding 2021/2022 Second Lien Notes. In connection with such cancellation, the Company's obligations under the indenture, dated as of May 31, 2019, among the Company, as issuer, the Subsidiary, as subsidiary guarantor, and the Trustee (the "2021/2022 Second Lien Notes Indenture"), governing the 2021/2022 Second Lien Notes, as supplemented by the first amendment to the indenture and notes, dated as of May 6, 2020, was satisfied and discharged. No consideration was paid in connection with such cancellation, satisfaction and discharge, other than the exchange of the 2023 Second Lien Notes for the 2021/2022 Second Lien Notes as described above. The material terms of the 2021/2022 Second Lien Notes and 2021/2022 Second Lien Notes Indenture were previously described in Item 1.01 of the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission (the "SEC") on June 3, 2019.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10.
Directors, Executive Officers and Corporate Governance
Our executive officers and directors and their ages and positions as of March 12, 2021, are as follows:
Name
Age
Position
Walter G. “Gil” Goodrich
Chairman of the Board of Directors, Chief Executive Officer and Director
Robert C. Turnham, Jr.
President, Chief Operating Officer and Director
Michael J. Killelea
Executive Vice President, General Counsel and Corporate Secretary
Kristen M. McWatters
Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller
Ronald F. Coleman
Director
K. Adam Leight
Director
Timothy D. Leuliette
Director
Jeffrey S. Serota
Director
Edward J. Sondey
Director
Thomas M. Souers
Director
Walter G. “Gil” Goodrich became Chairman of the Board in 2015 and served as Vice Chairman of our Board since 2003. He has served as our Chief Executive Officer since 1995. Mr. Goodrich was Goodrich Oil Company’s Vice President of Exploration from 1985 to 1989 and its President from 1989 to 1995. He joined Goodrich Oil Company, which held interests in and served as operator of various properties owned by a predecessor of the Company, as an exploration geologist in 1980. He has served as a director since 1996. Mr. Goodrich’s perspective as our top executive officer on the Board and his experience as a geologist and a businessman make him qualified to be a member of our Board.
Robert C. Turnham, Jr. has served as our Chief Operating Officer since 1995. He became President and Chief Operating Officer in 2003. He has held various positions in the oil and natural gas business since 1981. From 1981 to 1984, Mr. Turnham served as a financial analyst for Pennzoil. In 1984, he formed Turnham Interests, Inc. to pursue oil and natural gas investment opportunities. From 1993 to 1995, he was a partner in and served as President of Liberty Production Company, an oil and natural gas exploration and production company. He has served as a director since 2006. Mr. Turnham brings invaluable oil and gas operating experience to the Board. Additionally, he has held various executive management positions in the oil and natural gas business since 1981 and is able to assist the Board in creating and evaluating the Company’s strategic plan. For these reasons, Mr. Turnham is qualified to be a member of our Board.
Michael J. Killelea joined the Company as Senior Vice President, General Counsel and Corporate Secretary in 2009. He was named Executive Vice President in December 2016. Mr. Killelea has over 32 years of experience in the energy industry. In 2008, he served as interim-Vice President, General Counsel and Corporate Secretary for Maxus Energy Corporation. Prior to that time, Mr. Killelea was Senior Vice President, General Counsel and Corporate Secretary of Pogo Producing Company from 2000 through 2007. Mr. Killelea held various positions within the legal department at CMS Energy Corporation from 1988 to 2000, including Chief Counsel at CMS Oil & Gas Company from 1995 to 2000.
Kristen M. McWatters joined the Company in 2017 as Assistant Controller and served as Controller since March 2020 until being appointed to her current position in December 2020. Prior to joining the Company, Ms. McWatters served as Controller for Spark Energy, Inc. from 2015 to 2016 and their Senior Manager, Financial Reporting from 2014 to 2015. From 2011 to 2014, Ms. McWatters served in various positions with Southwestern Energy, including Manager, Financial Reporting from 2013 to 2014. From 2008 to 2011, Ms. McWatters worked for KPMG, LLP. She is a certified public accountant and holds a Masters of Science in Finance from Texas A&M University.
Ronald F. Coleman is an energy executive with over 37 years of international and domestic oilfield services operations experience. From 2012 to 2014, Mr. Coleman was president North America and executive vice president of Archer. Prior to that, Mr. Coleman served as chief operating officer and executive vice president of Select Energy Services in 2011. Mr. Coleman spent 33 years at BJ Services Company, serving as vice president of operations in U.S. and Mexico from 1998 to 2007 and Vice President North America Pumping from 2007 to 2010. He has served on numerous boards, including Torqued Up Energy Services, Titan Liner (CWCS Company), Solaris Oil Field Services, and Ranger Energy Services. He has also been appointed by boards to serve in advising roles for CSL Energy Opportunities Fund II, LP, and Matador Resources Company. He was appointed to the Company’s Board of Directors in 2016. Mr. Coleman’s many years of experience in oilfield service operations and service on the boards of various energy companies makes him qualified to serve as a member of our Board.
K. Adam Leight has spent over 35 years building and managing investment research departments, covering the energy industry for major financial institutions, and advising investors and managements. Mr. Leight is presently a managing member of Ansonia Advisors LLC, which provides independent research, capital markets, and corporate advisory services to various institutions and to the energy industry. He is also a Senior Advisor with Al Petrie Advisors, providing capital markets and investor relations advice to energy industry managements. Previously, Mr. Leight served as a managing director at RBC Capital Markets from 2008 to 2016, managing director at Credit Suisse from 2000 to 2007 and managing director at Donaldson, Lufkin & Jenrette from 1994 to 2000. Before that, Mr. Leight was managing director at Cowen & Company, vice president at Drexel Burnham Lambert, and an analyst at Sutro & Co. He currently serves on the board of Warren Resources, an independent oil and gas production company. Mr. Leight has also served on the advisory boards of Falcon Capital Management, University of Wisconsin ASAP, and various non-profit boards. Mr. Leight holds an A.B. in economics from Washington University, an M.S. in investment finance from the University of Wisconsin and is a Chartered Financial Analyst. He was appointed to the Company’s Board of Directors in 2016. Mr. Leight has held management positions at several investment banks. His finance and business leadership skills from his career in investment banking make him qualified to be a member of our Board as well as his qualifications as an audit committee financial expert under the SEC guidelines.
Timothy D. Leuliette served as the president, chief executive officer and a member of the board of directors of Visteon Corporation from September 2012 to June 2015. Upon assuming his role at Visteon, Mr. Leuliette left FINNEA Group, a firm he had co-founded and where he was a senior managing director. He left the FINNEA Group’s predecessor firm to serve as chairman, president and chief executive officer of Dura Automotive LLC for two years to oversee its emergence from bankruptcy, its financial and operational restructuring and its successful sale. Prior to that, Mr. Leuliette was co-chief executive officer of Asahi Tec Corporation and chairman and chief executive officer of its subsidiary Metaldyne Corporation, a company he co-founded in 2000. Mr. Leuliette was formerly president and chief operating officer of Penske Corporation, president and chief executive officer of ITT Automotive Group and senior vice president of ITT Industries Inc. Before joining ITT, Mr. Leuliette served as president and chief executive officer of Siemens Automotive L.P and was a member of the Siemens Automotive managing board and a corporate vice president of Siemens AG. Mr. Leuliette has also served on numerous boards and recent directorships, including Visteon Corporation, Business Leaders of Michigan, and The Detroit Economic Club. He is a past chairman of the board of The Detroit Branch of The Federal Reserve Bank of Chicago. Mr. Leuliette holds a B.S. in mechanical engineering and a Master’s Degree in business administration from the University of Michigan. He was appointed to the Company’s Board of Directors in 2016. Mr. Leuliette has many years of experience serving in leadership roles of publicly traded companies. His perspective as an executive officer and his experiences as a businessman and director make him qualified to be a member of our Board.
Jeffrey S. Serota serves as Vice Chairman and Chief Investment Officer of Corbel Capital Partners, an independent investment firm that makes non-control investments in debt or equity securities in lower middle-market businesses. Mr. Serota has over 30 years of experience as a principal investor, financial services professional and operating executive. Independent of his responsibilities at Corbel, Mr. Serota currently serves as the Chairman of Great Elm Capital Group and as a Director of Maverick Natural Resources. Prior to joining Corbel, Mr. Serota served as a Senior Partner with Ares Management in Los Angeles from 1997 to 2012 and as a Senior Advisor to Ares in 2013. While at Ares, Mr. Serota was a member of the Investment Committee for all private equity related transactions. He has led transactions (including sourcing, due diligence, financing, consummating, monitoring and exiting) of a variety of sizes and in numerous industries including industrials, energy, chemicals, manufacturing and business services. As part of his role as Senior Partner at Ares, Mr. Serota acted as an interim CEO for certain portfolio company investments of Ares, led fundraising efforts for private equity investment funds, and participated in numerous private and public companies as a member of the boards of directors. Prior to joining Ares, Mr. Serota worked at Bear Stearns, Dabney/Resnick, Inc. and Salomon Brothers Inc. Mr. Serota received a B.S. in Economics from the Wharton School at the University of Pennsylvania, and an M.B.A. from the Anderson School of Management at the University of California at Los Angeles. He was elected to the Company’s Board of Directors in 2019. For these reasons, Mr. Serota is qualified to be a member of our Board.
Edward J. Sondey serves as Senior Managing Director of Private Equity at LS Power Group where he is responsible for the firm’s E&P and midstream investments. Mr. Sondey joined LS Power in 2011 and has over twenty-five years of experience in the energy industry. Prior to joining LS Power, Mr. Sondey served as Managing Director in the BofA Merrill Lynch global energy & power investment banking group from 2005 to 2011. He was head of competitive generation, and advised a broad range of industrial and financial clients on the execution of M&A, capital markets and structured commodity transactions. Prior to BofA Merrill, Mr. Sondey was Vice President, Finance for PSEG Power from 2000 to 2005 where he led strategic and finance activities and executed several asset M&A and development transactions. Mr. Sondey started his career as an early member of J. Makowski Associates, a Warburg Pincus portfolio company. Mr. Sondey received a BA degree from Princeton University. He was elected to the Company’s Board of Directors in 2019. For these reasons, Mr. Sondey is qualified to be a member of our Board.
Thomas M. Souers served as a petroleum engineering consultant at Netherland, Sewell & Associates, Inc. (NSAI) from 1991 until his retirement in 2016. During that time, Mr. Souers worked on a range of oil and gas reserves estimations, property evaluations for sales and acquisitions, analysis of secondary recovery projects, field studies, deliverability studies, prospect evaluations, and economic evaluations utilizing deterministic methodology for projects in North America, Europe, Africa, South America, and Asia. His areas of expertise are the Gulf of Mexico and horizontal drilling in various US basins. Mr. Souers has also served as expert witness on a number of civil cases. Mr. Souers also served as a consulting COO of a private oil and gas company during his employment at NSAI. Prior to that time, Mr. Souers served as an operations engineer with GLG Energy LP, senior staff engineer with Wacker Oil Inc., area manager with Transco Exploration Company, and supervising engineer with Exxon Company, U.S.A. Mr. Souers holds a B.S. in civil engineering from North Carolina State University and an M.S. in civil engineering from the University of Florida. He was appointed to the Company’s Board of Directors in 2016. Mr. Souers’ experience as a petroleum engineer makes him qualified to be a member of our Board.
Additional information required under this “Item 10 - Directors, Executive Officers and Corporate Governance,” will be provided in our Proxy Statement for the 2020 Annual Meeting of Stockholders. The information required by this Item is incorporated by reference to the information provided in our definitive proxy statement for the 2021 annual meeting of stockholders to be filed within 120 days from December 31, 2020. Additional information regarding our corporate governance guidelines as well as the complete text of our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and our Nominating and Corporate Governance Committee may be found on our website at www.goodrichpetroleum.com.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11.
Executive Compensation
The information required by this Item is incorporated by reference to the information provided under the caption “Executive Compensation” in our definitive proxy statement for the 2020 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2020.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this Item is incorporated by reference to the information provided under the caption “Security Ownership of Certain Beneficial Owners and Management” in our definitive proxy statement for the 2020 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2020.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information required by this Item is incorporated by reference to the information provided under the captions “Transactions with Related Persons” and “Corporate Governance-Our Board-Board Size; Director Independence” in our definitive proxy statement for the 2021 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2020.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14.
Principal Accounting Fees and Services
The information required by this Item is incorporated by reference to the information provided under the caption “Audit and Non-Audit Fees” in our definitive proxy statement for the 2020 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2020.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15.
Exhibits, Financial Statement Schedules
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See “Index to Consolidated Financial Statements” on page 46.
All schedules are omitted because they are not applicable, not required or the information is included within the consolidated financial information or related notes.
(a)(3) Exhibits
3.1
Third Amended and Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated August 16, 2019, (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form 8-K (File No. 333-12719) filed on August 21, 2019).
3.2
Second Amended and Restated Bylaws of Goodrich Petroleum Corporation, dated October 12, 2016, (Incorporated by reference to Exhibit 4.2 of the Company’s Registration Statement on Form S-8 (File No. 333-214080) filed on October 12, 2016).
4.1
Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement on Form S-8 (File No. 33-01077) filed February 20, 1996).
4.2*
Indenture, dated as of March 9, 2021, by and between Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C., as the Subsidiary Guarantor, and Wilmington Trust, National Association, as trustee and collateral agent, relating to the 13.50% Convertible Second Lien Senior Secured Notes due 2023.
4.3* Registration Rights Agreement, dated as of March 9, 2021, by and among Goodrich Petroleum Corporation and the Holders party thereto, relating to the 2023 Second Lien Notes.
4.4 Indenture, dated as of May 31, 2019, by and between Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C., as the Subsidiary Guarantor, and Wilmington Trust, National Association, as trustee and collateral agent, relating to the 13.50% Convertible Second Lien Senior Secured Notes due 2021 (Incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K (File No. 001-12719) filed on June 3, 2019).
4.5 First Amendment to Indenture and Notes, dated as of May 6, 2020, by and between Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C., as the subsidiary guarantor, and Wilmington Trust, National Association, as trustee and collateral agent, relating to the 13.50% Convertible Second Lien Senior Secured Notes due 2022 (Incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 7, 2020).
4.6 Registration Rights Agreement, dated as of May 31, 2019, by and among Goodrich Petroleum Corporation and the Holders party thereto, relating to the 2021/2022 Second Lien Notes (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K (File No. 001-12719) filed on June 3, 2019).
4.7 Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Incorporated by reference to Exhibit 4.4 of the Company’s Annual Report on Form 10-K (File No. 001-12719) filed on March 5. 2020).
10.1
Second Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 14, 2019, among Goodrich Petroleum Corporation, as Parent Guarantor, Goodrich Petroleum Company, L.L.C., as Borrower, SunTrust Bank, as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 14, 2019).
10.2
First Amendment to Second Amended and Restated Senior Secured Revolving Credit Agreement, dated as of August 16, 2019, among Goodrich Petroleum Corporation, as Parent Guarantor, Goodrich Petroleum Company, L.L.C., as Borrower, SunTrust Bank, as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 7, 2020).
10.3 Second Amendment to Second Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 6, 2020, among Goodrich Petroleum Corporation, as Parent Guarantor, Goodrich Petroleum Company, L.L.C., as Borrower, SunTrust Bank, as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 7, 2020).
10.4 Third Amendment to Second Amended and Restated Senior Secured Revolving Credit Agreement, dated as of October 30, 2020, among Goodrich Petroleum Corporation, as Parent Guarantor, Goodrich Petroleum Company, L.L.C., as Borrower, Truist Bank, as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K (File No. 001-12719) filed on November 5, 2020).
10.5* Fourth Amendment to Second Amended and Restated Senior Secured Revolving Credit Agreement, dated as of March 9, 2021, among Goodrich Petroleum Corporation, as Parent Guarantor, Goodrich Petroleum Company, L.L.C., as Borrower, Truist Bank, as Administrative Agent, and the Lenders party thereto.
10.6
Warrant Agreement, dated as of October 12, 2016, by and between Goodrich Petroleum Corporation and American Stock Transfer & Trust Company, LLC, relating to the UCC Warrants (Incorporated by reference to Exhibit 10.6 of the Company’s Form 8-K (File No. 001-12719) filed on October 14, 2016).
10.7
Registration Rights Agreement, dated as of October 12, 2016, by and among Goodrich Petroleum Corporation and the Holders party thereto (Incorporated by reference to Exhibit 10.7 of the Company’s Form 8-K (File No. 001-12719) filed on October 14, 2016).
10.8
Registration Rights Agreement, dated as of December 22, 2016, by and among the Company and the Purchasers named therein (Incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K (File No. 001-12719) filed on December 22, 2016).
10.9†
Goodrich Petroleum Corporation Management Incentive Plan. (Incorporated by reference to Exhibit 4.3 of the Company’s Registration Statement on Form S-8 (File No. 333-214080) filed on October 12, 2016).
10.10†
First Amendment to the Goodrich Petroleum Corporation Management Incentive Plan effective December 8, 2016 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on August 4, 2017).
10.11†
Second Amendment to the Goodrich Petroleum Corporation Management Incentive Plan effective May 23, 2017 (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on August 4, 2017).
10.12† Form Agreement of the Restricted Stock and Performance Stock Unit awards dated December 14, 2017 and December 10, 2019 under the 2016 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Company’s Annual Report on Form 10-K (File No. 001-12719) filed on March 5, 2020).
10.13†
Form of Grant of Restricted Stock. (Incorporated by reference to Exhibit 4.4 of the Company’s Registration Statement on Form S-8 (File No. 333-214080) filed on October 12, 2016) (attached as Exhibit A to the 2016 Long Term Incentive Plan).
10.14†
Form of Grant of Restricted Stock (Secondary Exit Award; UCC Warrant Exercise). (Incorporated by reference to Exhibit 4.5 of the Company’s Registration Statement on Form S-8 (File No. 333-214080) filed on October 12, 2016).
10.15†
Form of Grant of Restricted Stock (Secondary Exit Award; 2L Note Conversion). (Incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement on Form S-8 (File No. 333-214080) filed on October 12, 2016).
10.16†
Amendment and Restatement of Severance Agreement between the Company and Walter G. Goodrich dated August 22, 2018 (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K (File No. 001-12719) filed on August 23, 2018).
10.17†
Amendment and Restatement of Severance Agreement between the Company and Robert C. Turnham, Jr. dated August 22, 2018 (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K (File No. 001-12719) filed on August 23, 2018).
10.18†
Amendment and Restatement of Severance Agreement between the Company and Mark E. Ferchau dated August 22, 2018(Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K (File No. 001-12719) filed on August 23, 2018).
Subsidiary of the Registrant:
Goodrich Petroleum Company L.L.C. - Organized in the State of Louisiana.
22* Subsidiary Guarantors of Guaranteed Securities
23.1*
Consent of Moss Adams LLP-Independent Registered Public Accounting Firm.
23.2*
Consent of Netherland, Sewell & Associates, Inc.
23.3*
Consent of Ryder Scott Company.
24.1* Power of Attorney (included on the signature page hereto)
31.1*
Certification by Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification by Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*
Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.
99.2*
Report of Ryder Scott Company, Independent Petroleum Engineers and Geologists.
101.INS*
XBRL Instance Document
101.SCH*
XBRL Schema Document
101.CAL*
XBRL Calculation Linkbase Document
101.LAB*
XBRL Labels Linkbase Document
101.PRE*
XBRL Presentation Linkbase Document
101.DEF*
XBRL Definition Linkbase Document
*
Filed herewith.
**
Furnished herewith.
+ The schedules to this agreement have been omitted from this filing pursuant to Item 601(a)(5) of Regulation S-K. The Company will furnish copies of any such schedules to the SEC upon request.
†
Denotes management contract or compensatory plan or arrangement.