ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED
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PART II | ||
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PART III | ||
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PART IV | ||
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Business and Properties |
General
Goodrich Petroleum Corporation, a Delaware corporation (together with its subsidiary, “we,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 165176 producing oil and natural gas wells located in 3837 fields in seven states. At At December 31, 2017,2019, we had estimated proved reserves of approximately 428approximately 517 Bcfe, comprised of 415510 Bcf of natural gas and 2.11.1 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 public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, 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
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 assignorField
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)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 acresis 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 (“US 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, 2017,2019, nearly all of our proved oil and natural gas reserves were located in Louisiana, Texas and Mississippi. We spent substantially all of our 20172019 capital expendituresexpenditures of $41.8$98.4 million in the Haynesville Shale Trend of Northwest Louisiana. Our total capital expenditures, including accrued costs for services performed during 2017,2019, consisted of $41.2$97.9 million for drilling and completion costs, $0.5$0.3 million for leasehold acquisitionsasset retirement obligations, and extensions, and $0.1$0.2 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 20182020 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, 2017.
Average Producing Well Working Interest | Producing wells at December 31, 2017 | ||||||||||
Acreage As of December 31, 2017 | |||||||||||
| Field or Area | Gross | Net | |||||||||
| Tuscaloosa Marine Shale Trend | 87,635 | 64,945 | 65 | % | 40 | ||||||
| Haynesville Shale Trend | 50,097 | 25,855 | 33 | % | 91 | ||||||
| Eagle Ford Shale Trend | 32,430 | 14,148 | — | — | |||||||
| Other | 33,125 | 7,323 | 23 | % | 34 | ||||||
Acreage | Average | Producing wells | ||||||||||||||
As of December 31, 2019 | Producing Well | at December 31, | ||||||||||||||
Field or Area | Gross | Net | Working Interest | 2019 | ||||||||||||
Tuscaloosa Marine Shale Trend | 47,786 | 33,192 | 65 | % | 36 | |||||||||||
Haynesville Shale Trend | 39,767 | 21,696 | 39 | % | 116 | |||||||||||
Eagle Ford Shale Trend | 18,909 | 12,445 | - | - | ||||||||||||
Other | 33,125 | 7,323 | 9 | % | 24 | |||||||||||
Haynesville Shale Trend
As of December 31, 2017,2019, we have acquired or farmed-infarmed-in leases totaling approximately 50,10040,000 gross (25,900(22,000 net) acres in the Haynesville Shale Trend. During 2017, 2019, we added 59 gross (1.5(7.2 net) wells to productionproduction on our acreage. Our Haynesville Shale Trend drilling activities are currently located in leaseholdleasehold areas in Caddo, DeSoto and Red River parishes, Louisiana. AsAs of December 31, 2017,2019, we had 6had 7 gross (3.2 net) wells in the drilling phase and 5 additional gross wells waiting onor completion operationsphase in the HaynesvilleHaynesville Shale Trend.
Tuscaloosa Marine Shale Trend
As of December 31, 2017,2019, we have acquired approximately 87,600own approximately 48,000 gross (64,900(33,000 net) lease acresacres in the TMS, an oil shale play in Southwest Mississippi and Southeast Louisiana. Approximately 60,400Approximately 47,000 gross (41,900(33,000 net) acres areare currently held by production. During 2017,2019, we did not conduct any drilling operations and did not add any wells to production. As of December 31, 2017,2019, we had 2 gross (1.7 net) wells waiting on completion operations in the TMS.
Eagle Ford Shale Trend
As of December 31, 2017,2019, we have acquired or farmed-in leases totaling approximately 32,400 gross (14,100 net) lease acres in the Eagle Ford Shale Trend. We sold our Eagle Ford Shale Trend proved reserves and a portion of the associated leasehold on September 4, 2015 but retained approximately 14,100approximately 12,000 net acres of undeveloped leasehold in the Eagle Ford Shale Trend in Frio County, Texas for future development or sale.
Other
As of December 31, 2017,2019, 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, 20172019 and 2016,2018, 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, 20172019 on properties other than those located in the TMS. RSC prepared the estimate of proved reserves as of December 31, 20172019 for our TMS properties. Copies of the summary reserve reports of NSAI and RSC as of December 31, 20172019 are included as exhibits to this Annual Report on Form 10-K. For additional information see
Net proved reserves and the PV10PV-10 estimates at December 31, 20172019 below were calculated using flat, twelve month average commodity index prices of $51.34$55.69 per barrel and $2.98$2.58 per Mmbtu.
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 | 924 | 371,459 | 510,066 | ||||||||||||
Mcf Natural Gas Equivalent (Mmcfe) (2) | 144,308 | 924 | 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 | ||||||||||||||
| Proved Reserves at December 31, 2017 | ||||||||||||
Developed Producing | Developed Non-Producing | Undeveloped | Total | |||||||||
| (dollars in thousands) | ||||||||||||
| Net Proved Reserves: | ||||||||||||
| Oil (MBbls) (1) | 1,414 | 716 | — | 2,130 | ||||||||
| Natural Gas (Mmcf) | 40,841 | 12,020 | 362,363 | 415,224 | ||||||||
| Mcf Natural Gas Equivalent (Mmcfe) (2) | 49,326 | 16,313 | 362,363 | 428,002 | ||||||||
| Estimated Future Net Cash Flows | $ | 500,504 | ||||||||||
| PV-10 (3) | $ | 264,159 | ||||||||||
| Discounted Future Income Taxes | (3,849 | ) | ||||||||||
| Standardized Measure of Discounted Net Cash Flows (3) | $ | 260,310 | ||||||||||
| Proved Reserves at December 31, 2016 | ||||||||||||
Developed Producing | Developed Non-Producing | Undeveloped | Total | |||||||||
| (dollars in thousands) | ||||||||||||
| Net Proved Reserves: | ||||||||||||
| Oil (MBbls) (1) | 1,988 | 827 | — | 2,815 | ||||||||
| Natural Gas (Mmcf) | 23,277 | 4,266 | 258,495 | 286,038 | ||||||||
| Mcf Natural Gas Equivalent (Mmcfe) (2) | 35,207 | 9,225 | 258,495 | 302,927 | ||||||||
| Estimated Future Net Cash Flows | $ | 159,824 | ||||||||||
| PV-10 (3) | $ | 57,086 | ||||||||||
| Discounted Future Income Taxes | (164 | ) | ||||||||||
| Standardized Measure of Discounted Net Cash Flows (3) | $ | 56,922 | ||||||||||
Proved Reserves at December 31, 2018 | ||||||||||||||||
Developed | Developed | |||||||||||||||
Producing | Non-Producing | Undeveloped | Total | |||||||||||||
(dollars in thousands) | ||||||||||||||||
Net Proved Reserves: | ||||||||||||||||
Oil (MBbls) (1) | 1,441 | - | - | 1,441 | ||||||||||||
Natural Gas (Mmcf) | 91,404 | 714 | 378,819 | 470,937 | ||||||||||||
Mcf Natural Gas Equivalent (Mmcfe) (2) | 100,050 | 714 | 378,819 | 479,583 | ||||||||||||
Estimated Future Net Cash Flows | $ | 734,048 | ||||||||||||||
PV-10 (3) | $ | 417,770 | ||||||||||||||
Discounted Future Income Taxes | (20,185 | ) | ||||||||||||||
Standardized Measure of Discounted Net Cash Flows (3) | $ | 397,585 | ||||||||||||||
(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-US 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:
| December 31, 2017 | |||||||||||
| Area | Proved Developed | Proved Undeveloped | Proved Reserves | % of Total | |||||||
| Tuscaloosa Marine Shale Trend | 12,704 | — | 12,704 | 3 | % | ||||||
| Haynesville Shale Trend | 48,960 | 362,363 | 411,323 | 96 | % | ||||||
| Other | 3,975 | — | 3,975 | 1 | % | ||||||
| Total | 65,639 | 362,363 | 428,002 | 100 | % | ||||||
As of December 31, 2019 | ||||||||||||||||
Proved | Proved | Proved | % of | |||||||||||||
Area | Developed | Undeveloped | Reserves | Total | ||||||||||||
Tuscaloosa Marine Shale Trend | 6,549 | - | 6,549 | 1 | % | |||||||||||
Haynesville Shale Trend | 138,554 | 371,459 | 510,013 | 99 | % | |||||||||||
Other | 129 | - | 129 | 0 | % | |||||||||||
Total | 145,232 | 371,459 | 516,691 | 100 | % | |||||||||||
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
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-monthfirst-day-of-the-month price for the period of January 20172019 through December 2017,2019, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For reserves at December 31, 2017,2019, the average twelve month prices used were $2.98$2.58 per MMBtu of natural gas and $51.34$55.69 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 reservesreserves and related future net revenues.
Our proved reserve information as of December 31, 20172019 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 principal internal engineer has over 3035 years of experience in the oil and natural gas industry, including over 2530 years as a reserve evaluator, trainer or manager. Further professional qualifications of our principal engineer include a degree in petroleum engineering, extensive internal and external reserve training, and experience in asset evaluation and management. In addition, the principal engineer is an activea participant in professional industry groups and has been a member of the Society of Petroleum Engineers for over 3035 years.
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 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, 2017, 2019, as estimated by NSAI and RSC, were 428517 Bcfe, consisting of 415510 Bcf of natural gas and 2.11.1 MMBbls of oil and condensate. In 20172019, we added approximately 33218 Bcfe related to our drilling activities in the Haynesville Shale Trend. We had positivenegative revisions of approximately 105133 Bcfe due primarily to natural gas prices and produced 1248 Bcfe in 2017.2019. We are employing newcontinue to employ completion techniques on our Haynesville Shale Trend wells which have been proven onsuccessful by the successful producingproduction volume results from the wells we drilled in 20172019 and 2016.2018. These well results in conjunction with our acreage position and our new financial
Our proved undeveloped (“PUD”) reserves at December 31, 2017, 2019, all in our Haynesville Shale Trend, were 362371 Bcfe, or 85%72% of our total proved reserves. In 2017,2019, we had new additions of 182 Bcfe reflective of our plans to developed theses reserves in and after the year 2022 but before five years have elapsed. We had net positivenegative revisions of previous estimates of 84 Bcfe and new additions of 33139 Bcfe. We developed approximately 1350 Bcfe, or 5%13% of our total proved undeveloped reserves booked as of December 31, 2016,2018, through the drilling of 4 gross (2.3(3.9 net) development wells. Of the proved undeveloped reserves in our December 31, 20172019 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 positivenet negative PUD revision of previous estimates was primarily attributable to ever improvingrecognizing that reserves under current natural gas pricing representing approximately 147 Bcfe would not be developed within five years since they were originally booked. In addition, we had ownership decreases of 4 Bcfe and an increase of 12 Bcfe mostly due to economic parameter adjustments such as improved well completion technology and techniques was 47 Bcf. We increased our ownership in the well locations by negotiating acreage swaps with offset operators which added 22 Bcf and commodity price increases added 15 Bcf to PUD reserves.performance.
The following table sets forth the number of productive wells in which we maintain ownership interests as of December 31, 2017:
| Oil | Natural Gas | Total | |||||||||||||||
| Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | ||||||||||||
| Tuscaloosa Marine Shale Trend: | |||||||||||||||||
| Southeast Louisiana | 17 | 12 | — | — | 17 | 12 | |||||||||||
| Southwest Mississippi | 23 | 14 | — | — | 23 | 14 | |||||||||||
| Haynesville Shale Trend: | |||||||||||||||||
| East Texas | — | — | 6 | 5 | 6 | 5 | |||||||||||
| Northwest Louisiana | — | — | 91 | 30 | 91 | 30 | |||||||||||
| Other | 9 | 1 | 19 | 5 | 28 | 6 | |||||||||||
| Total Productive Wells | 49 | 27 | 116 | 40 | 165 | 67 | |||||||||||
Oil | Natural Gas | Total | ||||||||||||||||||||||
Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||||||||
Tuscaloosa Marine Shale Trend: | ||||||||||||||||||||||||
Southeast Louisiana | 13 | 9.2 | - | - | 13 | 9.2 | ||||||||||||||||||
Southwest Mississippi | 23 | 14.3 | - | - | 23 | 14.3 | ||||||||||||||||||
Haynesville Shale Trend: | ||||||||||||||||||||||||
East Texas | - | - | 3 | 0.9 | 3 | 0.9 | ||||||||||||||||||
Northwest Louisiana | - | - | 111 | 42.9 | 111 | 42.9 | ||||||||||||||||||
Other | 6 | 0.3 | 20 | 2.7 | 26 | 3.0 | ||||||||||||||||||
Total Productive Wells | 42 | 23.8 | 134 | 46.5 | 176 | 70.3 | ||||||||||||||||||
(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, 2017.2019. 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 | 28,369 | 19,981 | 9,560 | 5,459 | 37,928 | 25,440 | |||||||||||
| Southeast Louisiana | 32,053 | 21,919 | 17,653 | 17,586 | 49,706 | 39,505 | |||||||||||
| Haynesville Shale Trend: | |||||||||||||||||
| East Texas | 12,553 | 7,181 | 212 | 371 | 12,765 | 7,553 | |||||||||||
| Northwest Louisiana | 36,665 | 18,362 | 1,961 | 573 | 38,626 | 18,935 | |||||||||||
| Eagle Ford Shale Trend: | |||||||||||||||||
| South Texas | 11,185 | 7,457 | 21,244 | 6,691 | 32,430 | 14,148 | |||||||||||
| Other | 27,195 | 6,004 | 4,637 | 686 | 31,832 | 6,690 | |||||||||||
| Total | 148,020 | 80,904 | 55,267 | 31,366 | 203,287 | 112,271 | |||||||||||
Developed | Undeveloped | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Tuscaloosa Marine Shale Trend: | ||||||||||||||||||||||||
Southwest Mississippi | 29,191 | 20,372 | 76 | 1 | 29,267 | 20,373 | ||||||||||||||||||
Southeast Louisiana | 18,205 | 12,536 | 313 | 284 | 18,518 | 12,820 | ||||||||||||||||||
| Haynesville Shale Trend: | ||||||||||||||||||||||||
East Texas | 33,367 | 9,074 | 4,938 | 909 | 38,305 | 9,983 | ||||||||||||||||||
Northwest Louisiana | 31,596 | 18,040 | 880 | 792 | 32,476 | 18,832 | ||||||||||||||||||
| Eagle Ford Shale Trend: | ||||||||||||||||||||||||
South Texas | 5,525 | 3,951 | 13,384 | 8,493 | 18,909 | 12,444 | ||||||||||||||||||
Other | 2,103 | 195 | 9 | 9 | 2,112 | 204 | ||||||||||||||||||
Total | 119,987 | 64,168 | 19,600 | 10,488 | 139,587 | 74,656 | ||||||||||||||||||
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.
We have undeveloped lease acreage excluding optioned acreage,primarily in the Eagle Ford Shale Trend that will expire during the next fourtwo 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, 2017:
| Year | Net Acreage | |
| 2018 | 22,492 | |
| 2019 | 1,961 | |
| 2020 | 8,284 | |
| 2021 | 56 | |
Year | Net Acreage | |||
2020 | 8,610 | |||
2021 | 56 | |||
Operator Activities
We operate a majority of our producing properties by value, and will generally seek to become the operator of record on properties we drill oror 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, | |||||||||||||||||
| 2017 | 2016 | 2015 | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Development Wells: | |||||||||||||||||
| Productive | 5 | 1.5 | 2 | 0.4 | 8 | 6.7 | |||||||||||
| Non-Productive | — | — | — | — | — | — | |||||||||||
| Total | 5 | 1.5 | 2 | 0.4 | 8 | 6.7 | |||||||||||
| Exploratory Wells: | |||||||||||||||||
| Productive | — | — | — | — | — | — | |||||||||||
| Non-Productive | — | — | — | — | — | — | |||||||||||
| Total | — | — | — | — | — | — | |||||||||||
| Total Wells: | |||||||||||||||||
| Productive | 5 | 1.5 | 2 | 0.4 | 8 | 6.7 | |||||||||||
| Non-Productive | — | — | — | — | — | — | |||||||||||
| Total | 5 | 1.5 | 2 | 0.4 | 8 | 6.7 | |||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2019 | 2018 | 2017 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Development Wells: | ||||||||||||||||||||||||
Productive | 9 | 7.2 | 16 | 7.5 | 5 | 1.5 | ||||||||||||||||||
Non-Productive | - | - | - | - | - | - | ||||||||||||||||||
Total | 9 | 7.2 | 16 | 7.5 | 5 | 1.5 | ||||||||||||||||||
Exploratory Wells: | ||||||||||||||||||||||||
Productive | - | - | - | - | - | - | ||||||||||||||||||
Non-Productive | - | - | - | - | - | - | ||||||||||||||||||
Total | - | - | - | - | - | - | ||||||||||||||||||
Total Wells: | ||||||||||||||||||||||||
Productive | 9 | 7.2 | 16 | 7.5 | 5 | 1.5 | ||||||||||||||||||
Non-Productive | - | - | - | - | - | - | ||||||||||||||||||
Total | 9 | 7.2 | 16 | 7.5 | 5 | 1.5 | ||||||||||||||||||
At December 31, 2017,2019, we had 139 gross (5.9(4.9 net) developmentdevelopment wells waiting to be completed.
The following table presents certain information with respect to oil and natural gas production attributable to our interests in all of our propertiesproperties (including two fields which have attributed more than 15% of our total proved reserves asas of December 31, 2017)2019), 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, 2017.
| Sales Volumes | Average Sales Prices (1) | Average | |||||||||||||||||||||||||
Natural Gas Mmcf | Oil & Condensate MBbls | Total Mmcfe | Natural Gas Mcf | Oil & Condensate Per Bbl | Total Per Mcfe | % of Total Revenue | Production Cost (2) Per Mcfe | ||||||||||||||||||||
| For Year 2017 (Successor): | |||||||||||||||||||||||||||
| TMS | — | 302 | 1,813 | $ | — | $ | 50.86 | $ | 8.48 | 34 | % | $ | 3.92 | ||||||||||||||
| Haynesville Shale Trend | 10,303 | — | 10,303 | 2.88 | — | 2.88 | 66 | % | 0.47 | ||||||||||||||||||
| Other | 20 | 2 | 34 | 5.86 | 55.67 | 7.25 | — | % | 3.84 | ||||||||||||||||||
| Total | 10,323 | 304 | 12,150 | $ | 2.89 | $ | 50.90 | $ | 3.73 | 100 | % | $ | 1.00 | ||||||||||||||
| For Year 2016 (Pro Forma) (4): | |||||||||||||||||||||||||||
| TMS | — | 473 | 2,837 | $ | — | $ | 40.81 | $ | 6.80 | 34 | % | $ | 1.98 | ||||||||||||||
| Haynesville Shale Trend | 5,471 | — | 5,471 | 1.44 | — | 1.44 | 66 | % | 0.48 | ||||||||||||||||||
| Other | 84 | 3 | 102 | 3.00 | 39.71 | 3.65 | — | % | 3.69 | ||||||||||||||||||
| Total | 5,555 | 476 | 8,410 | $ | 1.47 | $ | 40.80 | $ | 3.28 | 100 | % | $ | 1.02 | ||||||||||||||
| For Year 2015 (Predecessor): | |||||||||||||||||||||||||||
| TMS | — | 883 | 5,298 | $ | — | $ | 49.60 | $ | 8.27 | 55 | % | $ | 1.36 | ||||||||||||||
| Haynesville Shale Trend | 7,018 | — | 7,018 | 1.67 | — | 1.67 | 15 | % | 0.39 | ||||||||||||||||||
| Eagle Ford Shale Trend (3) | 776 | 453 | 3,494 | 2.39 | 46.30 | 6.54 | 29 | % | 1.37 | ||||||||||||||||||
| Other | 190 | — | 190 | 3.58 | — | 3.58 | 1 | % | 4.55 | ||||||||||||||||||
| Total | 7,984 | 1,336 | 16,000 | $ | 1.79 | $ | 48.50 | $ | 4.94 | 100 | % | $ | 0.97 | ||||||||||||||
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 2019: | ||||||||||||||||||||||||||||||||
TMS | - | 169 | 1,011 | $ | - | $ | 60.92 | $ | 10.15 | 9 | % | $ | 5.30 | |||||||||||||||||||
Haynesville Shale Trend | 46,436 | - | 46,436 | 2.31 | - | 2.31 | 90 | % | 0.14 | |||||||||||||||||||||||
Other | 275 | 2 | 290 | 3.12 | 50.28 | 3.38 | 1 | % | 1.04 | |||||||||||||||||||||||
Total | 46,711 | 171 | 47,737 | $ | 2.31 | $ | 60.77 | $ | 2.48 | 100 | % | $ | 0.26 | |||||||||||||||||||
For Year 2018: | ||||||||||||||||||||||||||||||||
TMS | - | 215 | 1,289 | $ | - | $ | 68.03 | $ | 11.34 | 17 | % | $ | 4.37 | |||||||||||||||||||
Haynesville Shale Trend | 24,410 | - | 24,410 | 2.99 | - | 2.99 | 83 | % | 0.19 | |||||||||||||||||||||||
Other | 34 | 2 | 47 | 4.18 | 58.11 | 5.72 | 0 | % | 2.38 | |||||||||||||||||||||||
Total | 24,444 | 217 | 25,746 | $ | 2.99 | $ | 67.93 | $ | 3.42 | 100 | % | $ | 0.41 | |||||||||||||||||||
For Year 2017: | ||||||||||||||||||||||||||||||||
TMS | - | 302 | 1,813 | $ | - | $ | 50.86 | $ | 8.48 | 34 | % | $ | 3.92 | |||||||||||||||||||
Haynesville Shale Trend | 10,303 | - | 10,303 | 2.88 | - | 2.88 | 66 | % | 0.47 | |||||||||||||||||||||||
Other | 20 | 2 | 34 | 5.86 | 55.67 | 7.25 | 0 | % | 3.84 | |||||||||||||||||||||||
Total | 10,323 | 304 | 12,150 | $ | 2.90 | $ | 50.90 | $ | 3.73 | 100 | % | $ | 1.00 | |||||||||||||||||||
(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,Year Ended December 31, | ||||||||
2019 | 2018 | |||||||
| CIMA Energy, LP | 39 | % | 41 | % | ||||
| Shell | 19 | % | 0 | % | ||||
ETC | 19 | % | 15 | % | ||||
| CES | 10 | % | 8 | % | ||||
Genesis Crude Oil LP | 8 | % | 13 | % | ||||
| Year Ended December 31, | |||||
| 2017 | 2016 (Pro Forma) | ||||
| Genesis Crude Oil LP | 20 | % | 44 | % | |
| Sunoco, Inc. | 13 | % | 30 | % | |
| Williams Energy Resources LLC | 29 | % | — | % | |
| ETC | 15 | % | 4 | % | |
| Occidental Energy MA | 7 | % | 13 | % | |
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.
Employees
At February 26, 201828, 2020 we had 4447 employees in our Houston administrative office and 4 employees in our field offices, all ofof whom 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.
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. For example, in December 2016, the U.S. Environmental Protection Agency (“EPA”) and certain environmental organizations entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. 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 (“SPCC”) 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 2015Act (the “WOTUS” rule). Several legal challenges to the rule followed, and the WOTUS rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear casesrescinded in the matter and, inSeptember 2019. On January 2017, the U.S. Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. Recently, in January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. Following the Supreme Court’s decision,23, 2020, the EPA and the Corps issued a finalfinalized the Navigable Waters Protection Rule, which narrows jurisdiction under the CWA relative to the WOTUS rule. However, legal challenges to the new rule in January 2018 staying implementationare expected, and multiple challenges to the EPA's prior rulemakings remain pending. Therefore, the scope of jurisdiction under the 2015 rule for two years. As a result of these recent developments, future implementation of the June 2015 ruleCWA is uncertain.uncertain at this time. To the extent the June 2015 rule is implemented or any replacement 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, (“OPA”), 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, the Texas Railroad Commission (“RRC”) has previously adopted new oil and gas permit rules in October 2014 for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. 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 following actions and issued: guidance under the SDWA for hydraulic fracturing activities involving the use of diesel fuel; final regulations under the federal Clean Air Act (“CAA”) governing air emission performance standards, including standards for the capture of volatile organic compounds and methane emissions released during hydraulic fracturingfracturing; and final rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. However, the BLM finalized a rule in December 2017 repealing its March 2015 hydraulic fracturing regulations. The repeal has been challenged in court and the final outcome is uncertain at this time.
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 some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.certain limited circumstances. The EPA has not proposed to take any action in response to the report’s findings, and additional regulation of hydraulic fracturing at the federal level appears unlikely at this time.
While 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, the prospect of additional federal legislation related to hydraulic fracturing appears remote at this time. At the state level, some states where we operate, including Louisiana and Texas, where we operate, 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.
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. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% ofstandards, and the U.S. counties as either “attainment/unclassifiable” or “unclassifiable”. In December 2017, the EPA responded to states preliminary agency completed attainment/non-attainment designations and expects to issue final non-attainment designations during the first half ofin 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. In addition, in June 2016, the EPA finalized rules under the CAA regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air
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 determinedadopted regulations that, greenhouse gases present an endangerment to public health and the environment and has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstructionamong other things, establish construction and operating permit requirementsreviews for GHG emissions from certain large stationary sources, of greenhouse gas emissions (“GHG”). The EPA has also adopted rules requiringrequire the monitoring and annual reporting of greenhouse gasGHG emissions from a variety ofcertain petroleum and natural gas system sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions from completions and workovers from hydraulically fractured oil wells. Also, in June 2016,implement New Source Performance Standard (“NSPS”) OOOOa directing the EPA finalized rules that establish new air emission controls forreduction of methane emissions from certain new, modified, or reconstructed equipmentfacilities in the oil and processesnatural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. In August 2019, EPA proposed amendments to NSPS OOOOa that would remove methane specific requirements from the oil and natural gas source category, including production, processing, transmission and storage activities. However,while keeping in June 2017,place requirements for volatile organic compounds. Legal challenges to any final rulemaking that rescinds NSPS OOOOa is expected. Similarly, the EPA published a proposed ruleBureau of Land Management has adopted certain regulations relating to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. In another example, the BLM published a final rule in November 2016 that imposes requirements to reduce methaneGHG emissions from venting, flaring, and leakingoperations on federal and Indian lands. However,tribal land, and certain rescissions are pending legal challenge. 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, there is an agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in December 2017, the BLM published a final rule that temporarily suspends or delays certain requirements containedincreasing political risks in the November 2016 final rule until January 17, 2019. The suspensionUnited States, including climate change related pledges made by certain candidates seeking the office of the President of the United States in 2020. Two critical declarations made by one or more candidates running for the Democratic nomination for President include threats to take actions banning hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions that could be pursued by presidential candidates may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as the reversal of the United States’ withdrawal from the Paris Agreement in November 2016 final rule is being challenged2020. 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 exploration and production companies in court. These rules, should they remainstate or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in effect,fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or anyall 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. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. 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 new methane emissionregulatory initiatives that impose more stringent standards imposed onfor 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 to our operations as well as result in delaysof compliance or curtailment in such operations, which costs delays or curtailment could adversely affect our business.
Finally, it should be noted that somemany 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.
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.
Risk Factors |
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 riskrisks and uncertainties:
• | the market prices of oil and natural gas; |
• | volatility in the commodity-futures market; |
• | financial market conditions and availability of capital; |
• | future cash flows, credit availability and borrowings; |
• | sources of funding for exploration and development; |
• | our financial condition; |
• | our ability to repay our debt; |
• | the securities, capital or credit markets; |
• | planned capital expenditures; |
• | future drilling activity; |
• | uncertainties about the estimated quantities of our oil and natural gas reserves and production from our wells; |
• | the creditworthiness of our hedging counterparties and the effect of our hedging arrangements; |
• | litigation matters; |
• | pursuit of potential future acquisition opportunities; |
• | general economic conditions, either nationally or in the jurisdictions in which we are doing business; |
• | 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; |
• | the creditworthiness of our financial counterparties and operating partners; and |
• | 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. |
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;
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 the Organization of Petroleum Exporting Countries, 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. During the period from January 1, 20142015 to December 31, 2017,2019, average daily prices for NYMEX Henry Hub natural gas ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu and NYMEX WTI oil prices ranged from a high of $107.26 per Bbl to a low of $26.55 per Bbl.Bbl, and in the first quarter of 2020, the NYMEX Henry Hub price for natural gas has neared the five-year low. 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:
worldwide and regional economic conditions impacting the supply and demand for oil and natural gas;
the level of global oil and natural gas exploration and production;
the level of global inventories;
prevailing prices on local price indices in the areas in which we operate and expectations about future commodity prices;
the extent of natural gas production associated with increased oil production;
the proximity, capacity, cost and availability of gathering and transportation facilities;
localized and global supply and demand fundamentals and transportation availability;
weather conditions across North America and, increasingly due to liquified natural gas, across the globe;
technological advances affecting energy consumption;
risks associated with operating drilling rigs;
speculative trading in commodity markets;
end user conservation trends;
petrochemical, fertilizer, ethanol, transportation supply and demand balance;
the price and availability of alternative fuels;
domestic, local and foreign governmental regulation and taxes; and
liquefied petroleum products supply and demand balances.
Changes in commodity prices significantly affect our capital resources, liquidity and expected operating results. 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 any increases inthe levels of production or reserves for various reasons.we have estimated. Exploration activities involve numerous risks,
reductions in oil and natural gas prices;
inadequate capital resources;
limitations in the market for oil and natural gas;
lack of acceptable prospective acreage;
unexpected drilling conditions;
pressure or irregularities in formations;
equipment failures or accidents;
unavailability or high cost of drilling rigs, equipment or labor;
title problems;
compliance with governmental regulations;
mechanical difficulties; and
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 which we currently have planned.planned and increased costs could reduce the profitability of our operations. Any delay in the drilling of new wells or significant increase 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. Historically,In recent years, we have paid for these expenditures with cash from operating activities proceeds from debt and, equity financings and asset sales.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:
our proved reserves;
the volume of hydrocarbons we are able to produce from existing wells;
the prices at which our production is sold;
our ability to acquire, locate and produce new reserves;
the extent and levels of our derivative activities;
the levels of our operating expenses; and
our ability to borrow under our 20172019 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. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. 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. WhereIn addition, where we are not the majority owner or operator of an oil and natural gas
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, 2017, 85%2019, 72% 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 chose not to develop such reserves on anticipated schedules in future adverselower oil or natural gas price environments. RecoveryIn 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 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 report 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 2017.2019. 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:
historical production from the area compared with production from other similar producing wells;
the assumed effects of regulations by governmental agencies;
assumptions concerning future oil and natural gas prices; and
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:
the quantities of oil and natural gas that are ultimately recovered;
the production and operating costs incurred;
the amount and timing of future development expenditures; and
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 document 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:
the amount and timing of actual production;
supply and demand for oil and natural gas;
increases or decreases in consumption; and
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, ismay not necessarily 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.
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.
We have incurred losses from operations and may continue to do so in the future.
We had operating income of $11.1 million for the year ended December 31, 2019 and $17.4 million for the year ended December 31, 2018, but had an operating loss of $2.2 million for the year ended December 31, 2017. We had accumulated earnings of $2.7 million at December 31, 2019. Our development of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report 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.
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 $9.6 million during 2019 and negative net cash settlements of $3.2 million during 2018.
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.
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 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 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 had no impairment for the years ended December 31, 2019 and 2018.
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.
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, 2019 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.
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 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, 2019, approximately 10% of our reserves and approximately 14% 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.
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.
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.
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 sources as a percent of oil and natural gas revenues for the years ended December 31, 2019 and 2018 were 39% and 41%, 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.
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, 2019 and 2018 are as follows:
Year Ended December 31, | ||||||||
2019 | 2018 | |||||||
| CIMA Energy, LP | 39 | % | 41 | % | ||||
| Shell | 19 | % | 0 | % | ||||
ETC | 19 | % | 15 | % | ||||
| CES | 10 | % | 8 | % | ||||
Genesis Crude Oil LP | 8 | % | 13 | % | ||||
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 success depends on our management team and other key personnel, the loss of any of whom could disrupt our business operations.
Our success will depend on our ability to retain and attract our senior management as well as experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.
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:
well blowouts;
cratering;
explosions;
uncontrollable flows of oil, natural gas, brine or well fluids;
fires;
formations with abnormal pressures;
shortages of, or delays in, obtaining water for hydraulic fracturing operations;
environmental hazards such as crude oil spills;
natural gas leaks;
pipeline and tank ruptures;
unauthorized discharges of brine, well stimulation and completion fluids or toxic gases into the environment;
encountering naturally occurring radioactive materials;
other pollution; and
other 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.
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:
personal injury;
bodily injury;
third party property damage;
medical expenses;
legal defense costs;
pollution in some cases;
well blowouts in some cases; and
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 materially 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 materially 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.
We may be unable to maintain compliance with the financial maintenance or other covenants in the 2019 Senior Credit Facility and New 2L 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 New 2L 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 4.00 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 New 2L 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.
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 February 28, 2020, we have outstanding (i) 1.0 million warrants exercisable into approximately 1.3 million shares of the Company's common stock at an exercise price of $17.48 per share, (ii) New 2L Notes convertible into approximately 0.7 million shares of the Company's common stock at an exercise price of $21.33, and (iii) approximately 1.0 million restricted stock awards at target, collectively representing in total approximately 20% 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.
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,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
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 taken the following actions and issued: guidance under the SDWA for hydraulic fracturing activities involving the use of diesel fuel; final regulations under the federal CAA governing performance standards, including standards for the capture of volatile organic compounds and methane emissions released during hydraulic fracturingfracturing; and finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indiantribal lands. However, the BLM finalized a rule in December 2017 repealing its March 2015 hydraulic fracturing regulations. The repeal has been challenged in court and the final outcome is uncertain at this time.
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 some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.certain limited circumstances. The EPA has not proposed to take any action in response to the report’s findings and additional federal regulation of hydraulic fracturing appears unlikely at this time.
While 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, the prospect of additional federalsuch legislation related to hydraulic fracturing appears remote at this time.has not been passed. At the state level, some states where we operate, including Louisiana and Texas, where we operate, 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 legislation or regulations restricting emissions of “greenhouse gases”that could result in increased operating costs, and reduced demand forlimit the crudeareas in which oil and natural gas that we produce.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have found thatbeen made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of carbon dioxide, methaneGHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our oil and other “greenhouse gases”natural gas exploration and production customers are contributingsubject to warminga series of regulatory, political, litigation, and financial risks associated with the earth’s atmosphereproduction and other climatic changes. Based on these findings,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 determinedhas adopted regulations that, greenhouse gases present an endangerment to public health and the environment and has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstructionamong other things, establish construction and operating permit requirementsreviews for GHG emissions from certain large stationary sources. The EPA has also adopted rules requiringsources, require the monitoring and annual reporting of greenhouse gasGHG emissions from a variety ofcertain petroleum and natural gas system sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, including greenhouse gas emissions from completions and workovers from hydraulically fractured oil wells. The revisions also includeimplement New Source Performance Standards directing the additionreduction of well identification reporting requirements for certain facilities. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment and processesfacilities in the oil and natural gas source
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in December 2017, the BLM published a final rule that temporarily suspends or delays certain requirements containedincreasing political risks in the November 2016 final rule until January 17, 2019. The suspensionUnited States, including climate change related pledges made by certain candidates seeking the office of the President of the United States in 2020. Two critical declarations made by one or more candidates running for the Democratic nomination for President include threats to take actions banning hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions that could be pursued by presidential candidates may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as the reversal of the United States’ withdrawal from the Paris Agreement in November 2016 final rule is being challenged2020. 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 exploration and production companies in court. These rules, should they remainstate or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in effect,fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or anyall 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. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. 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 new methane emissionregulatory initiatives that impose more stringent standards imposed onfor 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 to our operations as well as result in delaysof compliance or curtailment in such operations, which costs delays or curtailment could adversely affect our business.
Finally, it should be noted that somemany 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.
We have incurred losses from operations and may continue to do so in the future.
| Year Ended December 31, | |||||
| 2017 | 2016 (Pro Forma) | ||||
| Genesis Crude Oil LP | 20 | % | 44 | % | |
| Sunoco, Inc. | 13 | % | 30 | % | |
| Williams Energy Resources LLC | 29 | % | — | % | |
| ETC | 15 | % | 4 | % | |
| Occidental Energy MA | 7 | % | 13 | % | |
Our common stock is now listed on the NYSE American. The market price of our common stock could be subject to wide fluctuations
The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.
The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, 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.
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 6, 2020, our largest three stockholders collectively beneficially own approximately 46% of our outstanding common stock. As a result, these stockholders will be circumstances in whichable 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 our significantthese stockholders could be inwith 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.
We do not expect tocurrently pay dividends in the near future.
We do not anticipate thatcurrently pay cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future.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.
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 CharterThird 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 Boardboard 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.
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.
Unresolved Staff Comments |
None.
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.Mine Safety Disclosures |
Not Applicable.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Market Price of Our Common Stock
The Predecessor Company's common stock was traded on the New York Stock Exchange (“NYSE”) under the symbol “GDP” throughout 2015. The NYSE delisted our common stock due to our abnormally low trading price in January 2016. Our common stock subsequently traded on the OTC Pink marketplace under the symbol “GDPMQ” until its cancellation on October 12, 2016, pursuant to the bankruptcy court's confirmation of our Plan of Reorganization. Upon our bankruptcy emergence, we issued 6.8 million shares of our new common stock, and commenced trading on the OTCQX marketplace under the symbol “GDPP” on December 8, 2016. On April 11, 2017, the Company's common stock commenced tradingtrades on the NYSE American under the symbol (“GDP”)“GDP”.
At March 1, 2018,2, 2020, the number of holders of record of our common stock was 5287 and 11,359,88712,532,950 shares were outstanding. High and low sales prices for our common stock for each quarter during 2017 and 2016 were as follows:
| 2017 | 2016 | ||||||||||||||
| High | Low | High | Low | ||||||||||||
| First Quarter | $ | 15.00 | $ | 13.00 | $ | 0.28 | $ | 0.05 | |||||||
| Second Quarter | 17.25 | 10.81 | 0.08 | 0.02 | |||||||||||
| Third Quarter | 14.37 | 8.20 | 0.05 | 0.01 | |||||||||||
| Fourth Quarter | 11.95 | 8.96 | 14.00 | 10.75 | |||||||||||
Dividends
We do not anticipate declaringcurrently pay any dividends on our common stock in the foreseeable future.
Issuer Repurchases of Equity Securities
No private or open market repurchases of our common stock were made by or on our behalf or any that of any affiliated purchaser for the year ended December 31, 2017.
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 Current Report on Form 8-K.
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.
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 boardBoard of directorsDirectors (the “Board”) on a quarterly basis and revised throughout the year as circumstancescircumstances warrant. We take into consideration our projected operating cash flow and externally available sources of financing, such as bank debt, asset divestures,divestitures, issuance of debt and equity securities and strategic joint-ventures, when establishing our capital expenditure budget.
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 unrealized hedging gains (losses), 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. Such pricing factorsThe prices we receive for our production are largely beyond our control; however, we employ commodity hedging techniquescontrol, and in an attemptthe first quarter of 2020, the NYMEX Henry Hub price for natural gas has neared the five-year low. We have historically been able to minimizehedge our natural gas production at prices that are higher than current strip prices. However, in the volatility of short termcurrent commodity price fluctuations onenvironment, our earnings and operating cash flow.
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 take advantage of improved completion technology to significantly increase production volumevolumes and consequently reduce our per unit finding cost and operating expenses.
Expand acreage position in the Haynesville Shale Trend. As of December 31, 2017,2019, we held approximately 25,90022,000 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, 2017,2019, we had $26.0$1.5 million in cash and a$92.9 million of outstanding borrowings with $32.1 million of availability under the 2019 Senior Credit Facility borrowing base of $40 million under our $250 million Amended and Restated Senior Secured Revolving Credit Agreement, dated October 17, 2017, by and between the Subsidiary, as borrower, JPMorgan Chase Bank, N.A. as administrative agent, and certain lenders named therein (the “2017 Senior Credit Facility”) on which we had $23.3 million available in borrowing capacity.$125 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 costless collars.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 2019 Results
We incurredgrew production by 85% in 2019 as we conducted drilling or completion costsoperations on 16 wells, adding 9 gross (7.2 net) wells to production in the Haynesville Shale Trend. 11 gross wells are waiting completion as of December 31, 2017;Trend;
We ended the year with 428grew reserves by 8% to 517 Bcfe of proved oil and natural gas reserves;reserves with a PV-10 of $297 million;
We increased our oil and natural gas revenues to $118.4 million, representing an increase of 35% from 2018;
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 50,100approximately 40,000 gross (25,900(22,000 net) acres as of December 31, 20172019 producing from or prospective for the Haynesville Shale Trend. We incurred drilling or completioncompletion costs on 16 gross (5.7 net) wells in 20172019, spending $38.4$93.4 million of which $0.3$0.5 million was leasehold cost. We added 9 gross (7.2 net) wells to production in 2019. Our netnet production volumes from our Haynesville Shale Trend wells represented approximately 85%approximately 97% of our total equivalent production on a Mcfe basis and substantially all of our total natural gas production for 2017.
Tuscaloosa Marine Shale Trend
We held approximately 87,60048,000 gross (64,900(33,000 net) acres in the TMS as of December 31, 20172019 with approximately 60,400approximately 47,000 gross (41,900(33,000 net) acresacres held by production.production. During 2016 and 2017,2019, 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 15% 2% of our total equivalent production on a Mcfe basis and approximately 99% of our totaltotal oil production for the year ended December 31, 2017.2019. During 2017,2019, we spent $0.4 milliondid not spend any capital in the TMS, which included $0.2TMS; however, we did spend $1.0 million for leasehold costs.on workover expense activities to maintain volumes on producing wells.
Eagle Ford Shale Trend
As of December 31, 2017,2019, we have retained approximately 14,100approximately 12,000 net acres of undeveloped leasehold in the Eagle Ford Shale Trend in Frio County, Texas, which is prospective for future development or sale.Texas.
Results of Operations
For the Successor also adopted the Full Cost Method of Accounting as of the Effective Date. Prior to the Effective Date, the Predecessor used the Successful Efforts Method of Accounting. The results of 2017 and 2016 operations of the Successor are not generally comparable to the results of 2016 operations of the Predecessor. We believe however, that production volumes, oil and natural gas revenues, lease operating expenses and production and other taxes are generally comparable; consequently, unless otherwise indicated the tables and discussions below include pro forma results of the Predecessor and the Successor together for the periods in 2016 for these operational items. We believe this pro forma presentation gives the reader a better understanding of our operational results in 2017.
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.
| Successor | Successor | Predecessor | Pro Forma | ||||||||||||||||||
| Year Ended December 31, | October 13, to December 31, 2016 | January 1, 2016 to October 12, 2016 | Year Ended December 31, | ||||||||||||||||||
| Summary Operating Information: | 2017 | 2016 | Variance | ||||||||||||||||||
| Revenues: | |||||||||||||||||||||
| Natural gas | $ | 29,829 | $ | 2,327 | $ | 5,817 | $ | 8,144 | $ | 21,685 | 266 | % | |||||||||
| Oil and condensate | 15,491 | 4,210 | 15,210 | 19,420 | (3,929 | ) | (20 | )% | |||||||||||||
| Natural gas, oil and condensate | 45,320 | 6,537 | 21,027 | 27,564 | 17,756 | 64 | % | ||||||||||||||
| Net Production: | |||||||||||||||||||||
| Natural gas (Mmcf) | 10,323 | 1,198 | 4,357 | 5,555 | 4,768 | 86 | % | ||||||||||||||
| Oil and condensate (MBbls) | 304 | 88 | 388 | 476 | (172 | ) | (36 | )% | |||||||||||||
| Total (Mmcfe) | 12,150 | 1,723 | 6,687 | 8,410 | 3,740 | 44 | % | ||||||||||||||
| Average daily production (Mcfe/d) | 33,288 | 21,538 | 23,381 | 22,979 | 10,309 | 45 | % | ||||||||||||||
| Average Realized Sales Price Per Unit: | |||||||||||||||||||||
| Natural gas (per Mcf) | $ | 2.89 | $ | 1.94 | $ | 1.34 | $ | 1.47 | $ | 1.42 | 97 | % | |||||||||
| Natural gas (per Mfc) including the effect of realized gains/losses on derivatives | $ | 2.94 | $ | 1.97 | $ | 1.41 | $ | 1.47 | $ | 1.47 | 100 | % | |||||||||
| Oil and condensate (per Bbl) | $ | 50.90 | $ | 47.84 | $ | 39.20 | $ | 40.80 | $ | 10.10 | 25 | % | |||||||||
Oil and condensate (per Bbl) including the effect of realized gains/losses on derivatives | $ | 50.61 | $ | 47.84 | $ | 39.20 | $ | 40.80 | $ | 9.81 | 24 | % | |||||||||
| Average realized price (per Mcfe) | $ | 3.73 | $ | 3.79 | $ | 3.14 | $ | 3.28 | $ | 0.45 | 14 | % | |||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||
Summary Operating Information: | 2019 | 2018 | Variance | |||||||||||||
Revenues: | ||||||||||||||||
Natural gas | $ | 107,966 | $ | 73,198 | $ | 34,768 | 47 | % | ||||||||
Oil and condensate | $ | 10,387 | $ | 14,745 | $ | (4,358 | ) | (30 | %) | |||||||
Natural gas, oil and condensate | $ | 118,353 | $ | 87,943 | $ | 30,410 | 35 | % | ||||||||
Net Production: | ||||||||||||||||
Natural gas (Mmcf) | 46,712 | 24,444 | 22,268 | 91 | % | |||||||||||
Oil and condensate (MBbls) | 171 | 217 | (46 | ) | (21 | %) | ||||||||||
Total (Mmcfe) | 47,737 | 25,746 | 21,991 | 85 | % | |||||||||||
Average daily production (Mcfe/d) | 130,787 | 70,537 | 60,250 | 85 | % | |||||||||||
Average Realized Sales Price Per Unit: | ||||||||||||||||
Natural gas (per Mcf) | $ | 2.31 | $ | 2.99 | $ | (0.68 | ) | (23 | %) | |||||||
Natural gas (per Mcf) including the effect of realized gains/losses on derivatives | $ | 2.53 | $ | 2.94 | $ | (0.41 | ) | (14 | %) | |||||||
Oil and condensate (per Bbl) | $ | 60.77 | $ | 67.93 | $ | (7.16 | ) | (11 | %) | |||||||
Oil and condensate (per Bbl) including the effect of realized gains/losses on derivatives | $ | 56.78 | $ | 59.27 | $ | (2.49 | ) | (4 | %) | |||||||
Average realized price (per Mcfe) | $ | 2.48 | $ | 3.42 | $ | (0.94 | ) | (27 | %) | |||||||
Oil and Natural Gas Revenue
Natural gas, oil and condensate revenues increased in 2017during the year ended December 31, 2019 compared to pro forma 2016the prior year period in 2018 reflecting increases in our average realized sales prices for natural gas, oil and condensate and an increase in natural gas production offset by decreased oil and condensate production. The increases inproduction as well as decreased realized sales prices for natural gas, oil and condensate realized sales prices and incondensate. Increased natural gas production contributed approximately $12.7$51.5 million to our increased revenues while decreased realized prices and $13.8 million, respectively, to the increase in natural gas, oil and condensate revenue. Decreaseddecreased oil and condensate production reduced natural gas, oil and condensate revenuerevenues by approximately $8.7$21.1 million compared to pro forma 2016.
The difference on a pro forma basis between our average realized pricesprices inclusive and exclusive of net cash derivative settlements for the yearyears ended December 31, 20172019 and pro forma 2016 relates2018 related to our oil and natural gas swap contracts. We had no natural gas or oil derivative contract settlements in 2016 while, in 2017,In 2019, we had oil derivative settlementsreceived a net $10.3 million on 400 Bbls per day, only for the month of December 2017 at the fixed price of $51.08 per Bbl, and natural gas derivative settlements on a daily average of 15,008 Mmbtuapproximately 95,000 MMBtu with a weighted average putfixed price of $3.49$2.90 per Mmbtu. We received $0.6MMBtu and paid a net $0.7 million inon oil derivative settlements on a daily average of 312 barrels at a weighted average price of $51.08 per barrel. In 2018, we paid a net $1.4 million on natural gas derivative settlements from our counterpartieson a daily average of approximately 30,600 MMBtu with a weighted average fixed price of $3.01 per MMBtu and paid our counterparties $0.1a net $1.9 million inon oil derivative settlements in 2017.
Operating Expenses
(in thousands) | Year Ended December 31, | Year Ended December 31, | ||||||||||||||
2019 | 2018 | Variance | ||||||||||||||
Lease operating expenses | $ | 12,371 | $ | 10,446 | $ | 1,925 | 18 | % | ||||||||
Production and other taxes | 2,573 | 2,605 | (32 | ) | (1 | %) | ||||||||||
Transportation and processing | 20,703 | 11,046 | 9,657 | 87 | % | |||||||||||
Per Mcfe | Year Ended December 31, | Year Ended December 31, | ||||||||||||||
2019 | 2018 | Variance | ||||||||||||||
Lease operating expenses | $ | 0.26 | $ | 0.41 | $ | (0.15 | ) | (37 | %) | |||||||
Production and other taxes | $ | 0.05 | $ | 0.10 | $ | (0.05 | ) | (50 | %) | |||||||
Transportation and processing | $ | 0.43 | $ | 0.43 | $ | - | 0 | % | ||||||||
| Successor | Successor | Predecessor | Pro Forma | ||||||||||||||||||
| (in thousands) | Year Ended December 31, | October 13, to December 31, 2016 | January 1, 2016 to October 12, 2016 | Year Ended December 31, | |||||||||||||||||
| 2017 | 2016 | Variance | |||||||||||||||||||
| Lease operating expenses | $ | 12,125 | $ | 2,109 | $ | 6,504 | $ | 8,613 | $ | 3,512 | 41 | % | |||||||||
| Production and other taxes | 1,183 | 619 | 1,946 | 2,565 | (1,382 | ) | (54 | )% | |||||||||||||
| Transportation and processing | 6,222 | 228 | 1,265 | * | — | — | % | ||||||||||||||
| Exploration | — | — | 577 | * | — | — | % | ||||||||||||||
| Successor | Successor | Predecessor | Pro Forma | ||||||||||||||||||
| Per Mcfe | Year Ended December 31, | October 13, to December 31, 2016 | January 1, 2016 to October 12, 2016 | Year Ended December 31, | |||||||||||||||||
| 2017 | 2016 | Variance | |||||||||||||||||||
| Lease operating expenses | $ | 1.00 | $ | 1.22 | $ | 0.97 | $ | 1.02 | $ | (0.02 | ) | (2 | )% | ||||||||
| Production and other taxes | 0.10 | 0.36 | 0.29 | 0.30 | (0.20 | ) | (67 | )% | |||||||||||||
| Transportation and processing | 0.51 | 0.13 | 0.19 | * | — | — | % | ||||||||||||||
| Exploration | — | — | 0.09 | * | — | — | % | ||||||||||||||
Lease Operating Expense
Our leaseLease operating expense (“LOE”) increased $1.9 million to $12.4 million during 2017 increasedthe year ended December 31, 2019 compared to 2016 onthe prior year period. The increase in LOE between years was attributable primarily to increased natural gas production volumes which increased variable lease operating costs such as saltwater disposal and equipment rental expenses, while fixed expenses remained relatively flat between years. The per unit cost of production decreased by 37% to $0.26 per Mcfe for the year ended December 31, 2019. Per unit LOE is expected to continue to decrease as we increase production in the Haynesville Shale Trend, which carries a pro forma basis.lower per unit LOE in 2017 included $3.4than the Company’s current per unit rate. We incurred $1.3 million in workover expense an increasein 2019 and $1.4 million in 2018. The majority of $2.2 million compared to 2016 LOE pro forma. The increases arethe workover expense incurred in both years was attributed to workover operations in our Haynesville Shale Trend. Additionally, our LOE related to our TMS oil wells increased by $1.5 million in 2017 compared to 2016 pro forma driven by increased salt water disposal and production enhancement costs. The oil wells require more attentionan effort to maintain production as they age.
Production and Other Taxes
Production and other taxes includes severance and ad valorem taxes. Severance taxes were $1.6 million for the year ended 2017 included production tax of $1.3 million and ad valorem tax credit of $0.1 million. Production taxes increased $0.3 million in 2017 compared to 2016 on a pro forma basis driven by expiration of our severance tax exemptions in Mississippi and Louisiana offsetDecember 31, 2019, which decreased by $0.2 million compared to the prior year period. Severance taxes in audit refunds. The State2018 were higher due to a non-recurring tax rate true-up associated with our non-operated take-in-kind natural gas volumes. Ad valorem taxes were $1.0 million for the year ended December 31, 2019, which was an increase of Mississippi has enacted an exemption from$0.2 million compared to the existing 6.0% severance tax for horizontalprior year period. We expect ad valorem taxes to increase as our newly producing wells drilled after July 1, 2013 with production commencing before July 1, 2018, which is partially offsetbegin to be valued by a 1.3% local severance tax on such wells. The exemption is applicable until the earlier of (i) 30 months from the date of first sale of production or (ii) payout of the well.taxing jurisdictions. The State of Louisiana has also enacted an exemption from the existing 12.5% severance tax on oil production and from the $0.098 per Mcf (through June 30, 2017) and $0.11$0.111 per Mcf (from July 1, 2017 through June 30, 2018), $0.122 per Mcf (from July 1, 2018 through June 30, 2019) and $0.125 per Mcf (which began on July 1, 2019) severance tax on natural gas production 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. The net revenues from our wellsOur recently drilled in our TMS acreage in Southwestern Mississippi and Southeast Louisiana have been favorably impacted by these exemptions. The Louisiana Haynesville Shale Trend wells that we brought on line in 2017 and will bring on line in 2018 will receive the benefit of these tax exemptions.
Transportation and Processing
Our natural gas production incurs substantially all of our transportation and processing cost. Transportation and processing expenses for the year 2017 includes a $0.4 million non-recurring charge for infrastructure cost paidended December 31, 2019 increased while per unit expense remained flat compared to the prior year period, reflecting increased production from our transporter to connect our wells for sales. Additionally, in 2017, we incurred higher transportation and processing rates on theoperated Haynesville Shale Trend wells. Our natural gas volumes from operated wells generally carry less transportation cost than those from wells we do not operate. Additionally, the wells we have recently put on production are producing from leases that stipulate that the royalty is free from transportation cost; consequently, we took in kindcurrently are incurring a proportionately higher transportation cost on non-operated Haynesville Shale Trend wells, which represented approximately 57% ofthe production from those wells. Our per unit transportation cost will continue to decrease as we increase our operated natural gas production in 2017, or $4.2 million. Prior to August 2016, theunder more favorable transportation contracts and processing cost on these non-operated wells were netted against the Company's realized natural gas price under an agency agreement.
| Successor | Successor | Predecessor | |||||||||
| (in thousands) | Year Ended December 31, 2017 | October 13, to December 31, 2016 | January 1, 2016 to October 12, 2016 | ||||||||
| Depreciation, depletion & amortization | $ | 12,125 | $ | 1,556 | $ | 8,276 | |||||
| Impairment | — | 2,486 | 1,583 | ||||||||
| General & administrative | 16,696 | 2,200 | 14,474 | ||||||||
| Gain on sale of assets | — | (2 | ) | (840 | ) | ||||||
| Successor | Successor | Predecessor | |||||||||
| Per Mcfe | Year Ended December 31, 2017 | October 13, to December 31, 2016 | January 1, 2016 to October 12, 2016 | ||||||||
| Depreciation, depletion & amortization | $ | 1.00 | $ | 0.90 | $ | 1.24 | |||||
| Impairment | — | 1.44 | 0.24 | ||||||||
| General & administrative | 1.37 | 1.28 | 2.16 | ||||||||
| Gain on sale of assets | — | — | (0.13 | ) | |||||||
(in thousands) | Year Ended December 31, | Year Ended December 31, | ||||||||||||||
2019 | 2018 | Variance | ||||||||||||||
Depreciation, depletion & amortization | $ | 50,722 | $ | 26,809 | $ | 23,913 | 89 | % | ||||||||
General & administrative | 20,775 | 19,663 | 1,112 | 6 | % | |||||||||||
| Other | 106 | 7 | 99 | 1414 | % | |||||||||||
Per Mcfe | Year Ended December 31, | Year Ended December 31, | ||||||||||||||
2019 | 2018 | Variance | ||||||||||||||
Depreciation, depletion & amortization | $ | 1.06 | $ | 1.04 | $ | 0.02 | 2 | % | ||||||||
General & administrative | $ | 0.44 | $ | 0.76 | $ | (0.32 | ) | (42 | %) | |||||||
| Other | $ | - | $ | - | $ | - | 0 | % | ||||||||
Depreciation, Depletion & Amortization (“DD&A”)
DD&A expense infor the 2017 Successor periodyear ended December 31, 2019 and 2018 was calculated on the Full Cost Method of Accounting. We adjust our DD&A rates 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. DD&A increased for the year ended December 31, 2019 versus the prior year period as a result of an increase in the DD&A rate based on the 2019 reserve reports and also because of additional production volumes to which the DD&A rate was applied. Included in DD&A for 2017 isthe year ended December 31, 2019 was the depletion of our oil and gas properties of $11.7$50.1 million, accretion of our Asset Retirement Obligationasset retirement obligation of $0.2 million, and $0.2$0.4 million in depreciation of our furniture and fixtures.
Impairment
Our Full Cost Ceiling Test performed quarterly did not require recording an impairment in 2017.
General and Administrative Expense (“G&A”)
General and Administrative Expense for the year ended December 31, 2017 includes $4.52019 was $20.8 million, in share-based compensation and $3.1which included $6.3 million of accrued performance bonus compensation which is expected to be paidshare based compensation. The $1.1 million increase in 2018 in a combination of cash and common stock. Our 2017 Senior Credit Facility and 13.50% Convertible Second Lien Senior Secured Notes due 2019 placed limitations on cash general and administrative expenses through 2017 of $10.1 million. G&A payable in cash, which excludes share-based compensation, accrued performance bonus to be compensated in stock and accrued rent expense was $9.2 million for the year ended December 31, 2017.2019 compared to the prior year period was substantially attributed to an increase in the annual performance bonus accrual and payment of special bonuses partially offset by a decrease in share based compensation. The special bonus was granted to non-executives in 2019 in lieu of any year-end 2018 restricted stock grants. We capitalized $2.4$3.7 million and $3.5 million of G&A directly attributed to our capital development to the full cost pool during 2017. Withfor the exception of share-based compensationyear ended December 31, 2019 and accrued performance bonus increases, ourDecember 31, 2018, respectively. Our G&A expense decreased in 2017 by approximately $3.6 million. It is expected that overall G&A expense will increase slightly due to salary and wage increases in 2018 but will decrease on a per unit of production basisdecreased by 42% in 2019 and is expected to continue to decrease entirely due to our increasing production volume increases from our drilling and development program.
Other Income (Expense)
| Successor | Successor | Predecessor | |||||||||
| Year Ended December 31, 2017 | October 13, to December 31, 2016 | January 1, 2016 to October 12, 2016 | |||||||||
| Other Income (Expense): | |||||||||||
| Interest expense | $ | (9,725 | ) | $ | (1,824 | ) | $ | (11,398 | ) | ||
| Interest income and other | 1,236 | 1 | 117 | ||||||||
| Gain on derivatives not designated as hedges | 1,552 | — | 30 | ||||||||
| Restructuring | — | — | (5,128 | ) | |||||||
| Reorganization net gain | 118 | 130 | 399,944 | ||||||||
| Income tax benefit | 978 | — | — | ||||||||
| Average funded borrowings adjusted for debt discount | 50,708 | 26,399 | * | ||||||||
| Average funded borrowings | 60,314 | 59,503 | * | ||||||||
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||
2019 | 2018 | Variance | ||||||||||||||
Other Income (Expense): | ||||||||||||||||
Interest expense | $ | (11,001 | ) | $ | (11,944 | ) | $ | (943 | ) | (8 | %) | |||||
Interest income and other | 25 | 508 | (483 | ) | (95 | %) | ||||||||||
Gain (loss) on derivatives not designated as hedges | 15,010 | (3,986 | ) | 18,996 | 477 | % | ||||||||||
| Loss on early extinguishment of debt | (1,846 | ) | - | (1,846 | ) | (100 | %) | |||||||||
Reorganization items loss, net | - | (305 | ) | 305 | 100 | % | ||||||||||
Income tax benefit | - | 57 | (57 | ) | (100 | %) | ||||||||||
Average funded borrowings adjusted for debt discount | $ | 86,493 | $ | 55,672 | ||||||||||||
Average funded borrowings | $ | 89,909 | $ | 62,476 | ||||||||||||
Interest Expense
Interest expense infor the year ended December 31, 2019 included $0.9 million incurred on the 2017 Successor period includes $1.2Senior Credit Facility, $3.4 million incurred on the 2019 Senior Credit Facility, $5.3 million incurred on the Convertible Second Lien Notes, and $1.4 million incurred on the New 2L Notes. The interest on the Convertible Second Lien Notes and New 2L 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 for the year ended December 31, 2018 included $1.1 million incurred on the 2017 Senior Credit Facility and Exit Credit Facility and $8.5$10.8 million incurred on the 13.5% Convertible Second Lien Senior Secured Notes due 2019 (the “Convertible Second Lien Notes”). The interest on the Convertible Second Lien Notes was all non-cash consisting of $5.9 million in paid-in-kind interest and amortized debt discount of $2.6 million.
Interest expense decreased for the year ended December 31, 2019 compared to the prior year period due to a reduction in our average interest rate on our debt offset by an increase in our funded debt amount, mainly resulting from additional borrowings on our 2019 Senior Credit Facility and accretion of the paid-in-kind interest on our New 2L Notes. On May 29, 2019, we redeemed our Convertible 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 foroverall because a large portion of our debt was moved to the 2016 Predecessor period reflects2019 Senior Credit Facility, which has a lower interest rate, but an increase in interest payable in cash of $8.5 million and non-cash interest of $2.7 million. The Predecessor Company did not record interest expense subsequent to April 15, 2016 on any of its outstanding second lien and senior notes. All the accrued interest on such indebtedness was never paid as the underlying debt was canceled in bankruptcy.
Interest Income and Other
Interest income and other in 2017for the year ended December 31, 2019 was less than $0.1 million.
Interest income and other for the year ended December 31, 2018 of $0.5 million primarily related to the receipt of cash that was previously held in escrow related to the sale of Predecessor's assets insales tax refunds received on audits we performed on a prior period.
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 fromfrom 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 inas hedges of $15.0 million for the 2017 Successor period isyear ended December 31, 2019 was comprised of an unrealizeda mark-to-market gain of $1.1$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 $0.5 million.settlements. The unrealizedmark-to-market gain represents a $2.6represented an $8.2 million gain in the fair value of our natural gas derivative contracts, offset by a $1.5$2.4 million loss in the fair value of our basis swaps and a $0.4 million loss in the fair value 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.
Loss on commodity derivatives not designated as hedges for the year ended December 31, 2018 was comprised of a mark-to-market loss of $0.8 million and a loss of $3.2 million from net cash settlements. The mark-to-market loss represented a $2.7 million loss in the fair value of our natural gas derivative contracts offset by a $1.9 million gain in the fair value of our oil derivative contracts. The net gainloss on cash settlements reflects $0.6reflected a net $1.3 million cash receivedpaid to our counter-parties on settlement of our natural gas derivatives offset by $0.1and a net $1.9 million paymentpaid to our counter-parties on the settlement on ourof oil derivatives.
Reorganization items, net
We settled the final outstanding bankruptcy claims in the 2016 Successor period and2018, which resulted in a net reorganization loss of $0.3 million for the year 2017 realized gains on reorganization of $0.1 million in each period.ended December 31, 2018 including legal and trustee fees. We continue to work on settling bankruptcy claims. We anticipate that we will continue to incur professionalsettled all remaining claims and United States Bankruptcy Trustee fees until theclosed our bankruptcy case is final. We will record these fees in the period in which they are incurred. We believethird quarter of 2018. In the fourth quarter of 2018, we distributed the remaining approximately 39 thousand shares of common stock and related warrants that were granted to the estimated liability of $0.2 million we have established for the claims is sufficient to cover such costs.
Income Tax Benefit
We recorded no income tax benefit or expense for the unwinding of an embedded derivative related to the second lien notes.
Adjusted EBITDA
Adjusted EBITDA grew by 65% to maintain a full valuation allowance for our net deferred tax assets as of December 31, 2017.
The following table presents a reconciliation of the non-US GAAP measure of Adjusted EBITDA/EBITDAXEBITDA to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP:
| Successor | Successor | Predecessor | |||||||||
| Year Ended December 31, 2017 | October 13, to December 31, 2016 | January 1, 2016 to October 12, 2016 | |||||||||
| (In thousands) | |||||||||||
| Net income (loss) (US GAAP) | $ | (7,996 | ) | $ | (4,307 | ) | $ | 369,944 | |||
| Depreciation, depletion and amortization | 12,125 | 1,556 | 8,276 | ||||||||
| Income tax benefit | (978 | ) | — | — | |||||||
| Exploration Expense | — | — | 577 | ||||||||
| Impairment | — | 2,486 | 1,583 | ||||||||
| Share-based compensation | 6,863 | 240 | 3,307 | ||||||||
| Interest expense | 9,725 | 1,824 | 11,398 | ||||||||
| Gain on reorganization | (118 | ) | (130 | ) | (399,422 | ) | |||||
| Gain on commodity derivatives not designated as hedges | (1,552 | ) | — | (30 | ) | ||||||
| Net cash received (paid) in settlement of derivative instruments | 471 | — | — | ||||||||
| Other items (1) | (38 | ) | (3 | ) | (957 | ) | |||||
| Adjusted EBITDA/EBITDAX | $ | 18,502 | $ | 1,666 | $ | (5,324 | ) | ||||
| Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||
(In thousands) | ||||||||
Net income (US GAAP) | $ | 13,288 | $ | 1,750 | ||||
Depreciation, depletion and amortization | 50,722 | 26,809 | ||||||
Income tax benefit | - | (57 | ) | |||||
Share based compensation expense (non-cash) | 6,400 | 6,545 | ||||||
Interest expense | 11,001 | 11,944 | ||||||
Loss on reorganization | - | 305 | ||||||
(Gain) loss on commodity derivatives not designated as hedges | (15,010 | ) | 3,986 | |||||
Net cash received (paid) in settlement of derivative instruments | 9,560 | (3,236 | ) | |||||
| Loss on early extinguishment of debt | 1,846 | - | ||||||
Other items (1) | 1,146 | (96 | ) | |||||
Adjusted EBITDA | $ | 78,953 | $ | 47,950 | ||||
(1) | |
Other items include $1.2 million and zero, respectively, from the impact of accounting for operating leases under ASC 842 as well as interest income, reorganization items and other |
Management believes that this non-US GAAP financial measure provides useful information to investors because it is
LIQUIDITY AND CAPITAL RESOURCES
Overview
Our primary sources of cash during 20172019 were cash on hand, cash flow from operating activities which includes a $1.2of $79.1 million, refund$21.2 million net proceeds from borrowings on our senior credit facilities and the issuance of escrowed funds related to the saleNew 2L Notes, and cash proceeds of our East Texas properties in 2014 and $0.7$1.3 million from asset sales. We used $99.3 million in ad valorem tax refunds, and cash from asset sale proceeds of $0.6 million. We used cash in 2017 primarily to fund our drilling and development capital program. In 2016,program, $2.8 million to pay issuance costs related to our primary sourcesdebt and $2.1 million for purchases of cash ontreasury stock for tax withholding purposes related to stock compensation. We currently plan to fund our operations and after the Effective Date werecapital expenditures for 2020 through a combination of cash on hand, cash flow from operating activities proceeds fromand borrowings (if any) under the sale of the Convertible Second Lien Notes, proceeds from the private placement of our common stock and proceeds from the sale of non-core oil and gas properties. We used cash to fund our capital expenditures, to pay interest on and pay down amounts outstanding on the Exit2019 Senior Credit Facility, andalthough we may from time to pay professional fees related totime consider other funding alternatives.
On May 14, 2019, the reorganization.
The 20172019 Senior Credit Facility matures on a) October 17, 2021(a) May 14, 2024 or b) December 3, 2020, if the Convertible Second LienNew 2L Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by September 30, 2019, September 30, 2019. Revolving borrowingsDecember 3, 2020, which is the date that is 180 days prior to the “Maturity Date” as defined in the indenture governing the New 2L Notes (the “New 2L Notes Indenture”) as in effect on the issuance date of the New 2L Notes. The maximum credit amount under the 20172019 Senior Credit Facility are limited to, and subject to periodic redeterminations,is $500 million with a current borrowing base of the borrowing base.$125 million. The amount of the borrowing base is determined by the lendersscheduled to be redetermined in their sole discretionMarch and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The initial borrowing base is $40 million. Pursuant to the terms of the 2017 Senior Credit Facility, borrowing base redeterminations will be on a semi-annual basis on or about March 1st and September 1st of each calendar year, commencing on or about March 1, 2018. The borrowing baseand 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, weeach of the Borrower and the administrative agentAdministrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. JPMorgan Chase Bank, N.A.The amount of the borrowing base is determined by the lead lenderlenders at their sole discretion and administrative agentconsistent 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 20172019 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 entered into a purchase agreement with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New 2L Notes Purchaser”) pursuant to which the Company issued to the New 2L Notes Purchasers (the “New 2L Notes Offering”) $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “New 2L Notes”). The closing of the New 2L Notes Offering occurred on May 31, 2019. Proceeds from the sale of the New 2L Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility.
The New 2L Notes, as set forth in the New 2L Notes Indenture, are scheduled to mature on May 31, 2021. The New 2L 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 New 2L Notes by increasing the principal amount of the outstanding New 2L Notes.
We exited 2019 with $1.5 million in cash through operating activities ending the year withof cash on hand and $92.9 million of $26.0 million. Asoutstanding borrowings with $32.1 million of availability under the current borrowing base of $125.0 million on the 2019 Senior Credit Facility. Due to the timing of payment of our capital expenditures, we reflected a working capital deficit of $19.7 million as of December 31, 2017,2019. To the extent we had $23.3 millionoperate with a working capital deficit, we expect such deficit to be offset by liquidity available under the 2017our 2019 Senior Credit Facility. We are beginning the year 20182020 with $49.3$33.6 million in immediately available capital resources.
Our total capital expenditures for 20182020 are expected to be approximatelyapproximately $55 to $65 to $75 million with flexibility to increase or decrease this amount based on the 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, and we currently contemplate drilling and developing 1613 gross (5.7(5.8 net) wells utilizing improved completion techniques.
We believe the results of the capital investments we made in 20172019 will generate additional cash flows and additional value whichthat will allow us to raise capital to continue our capital development into 2018 and beyond.
In addition, to support future cash flows, we entered into strategic derivative positions as of December 31, 2017,2019 covering approximately 41% and 14%approximately 47% of our anticipated oil and natural gas sales volumes for 20182020 and 2019, respectively.54% of our anticipated oil sales volumes for 2020. See Note 9-“9—Derivative Activities”Activities in the Notes to consolidatedConsolidated Financial Statements in Part II “Item 8—Financial Statements and Supplementary Data” of the Annual Report on Form 10-K.
We continuously monitor our balancebalance 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 equitydebt securities;
joint ventures in our TMS and/or Haynesville Shale Trend acreage;
sale of non-core assets.
issuance of equity securities if favorable conditions exist.
The table below summarizes our cash flows for the periods indicated (in thousands):
| Cash flow statement information: | Successor | Successor | Predecessor | ||||||||
| Year Ended December 31, 2017 | October 13, to December 31, 2016 | January 1, 2016 to October 12, 2016 | |||||||||
| Net Cash: | |||||||||||
| Provided by (used in) operating activities | $ | 18,306 | $ | (4,327 | ) | $ | (16,684 | ) | |||
| Used in investing activities | (28,200 | ) | (2,383 | ) | (3,495 | ) | |||||
| Provided by (used in) financing activities | (964 | ) | 39,880 | 12,077 | |||||||
| Increase (decrease) in cash and cash equivalents | $ | (10,858 | ) | $ | 33,170 | $ | (8,102 | ) | |||
Cash flow statement information: | Year Ended December 31, 2019 | Year Ended December 31, 2018 | ||||||
Net Cash: | ||||||||
Provided by operating activities | $ | 79,071 | $ | 49,186 | ||||
Used in investing activities | (97,967 | ) | (78,249 | ) | ||||
Provided by financing activities | 16,280 | 7,139 | ||||||
Decrease in cash and cash equivalents | $ | (2,616 | ) | $ | (21,924 | ) | ||
At December 31, 2017, we had positive2019, our capital expenditures at the end of 2019 resulted in a working capital deficit of $2.2$19.7 million, and $55.7which was more than offset by the liquidity available under the 2019 Senior Credit Facility. We had approximately $104.4 million in long-term debt.
For the Year Ended December 31, 2017
Operating activities: Net cash provided by operating activities for theYear Ended December 31, 2017 was $18.3 million. Production from our wells, the price of oil and natural gas and operating costs represent the main drivers of our cash flow from operations. In addition, net cash settlements of $0.5 million related to our derivative contracts and a $0.5 million change in working capital also positively impacted cash flows.
Investing activities: Net cash used in investing activities was $2.4$98.0 million for the 2016 Successor period. While we bookedyear 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 this period, which reflected the capitalization of approximately $4.3$0.3 million we paid out cash amounts totaling $3.2in asset retirement obligation and $0.7 million of non-cash internal cost reduced by a net $1.9 million in the period. The difference is attributed to utilizing $0.4 millionchange of net cash calls and a net $0.5 million increased in the capital expenditure
Financing activities: Net cash provided inby financing activities for Successor periodthe year ended December 31, 2019consisted was $16.3 million consisting ofnet proceedsdraws 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 Convertible Second Lien Notesof $40.0millionandnet proceedsfromthe sale of common stock of $23.6million partially offset by net repayments ofborrowingsunder our 20172019 Senior Credit Facility and Exitissuance of the New 2L Notes.
For the Year Ended December 31, 2018
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 cash flows. Net cash provided by operating activities for the year ended December 31, 2018 was $49.2 million including operating cash flows before working capital changes of $46.3 million reduced by net cash payments of $3.2 million for settlements of derivative contracts. The substantial increase in cash provided by operating activities in 2018 compared to 2017 was attributable to a 94% increase in oil and natural gas revenues driven by a 112% increase in equivalent production volumes.
Investing activities: Net cash used in investing activities was $78.3 million for the year ended December 31, 2018, which reflected cash expended on capital projects of $105.1 million reduced by $26.8 million cash proceeds received from sales of oil and gas properties. We recorded $106.9 million in capital expenditures in this period, which reflected the utilization of $1.2 million of cash calls paid in the previous period, the utilization of $1.9 million from materials inventory, capitalization of $0.4 million in asset retirement obligation and capitalization of $0.7 million of non-cash internal cost reduced by a net $2.4 million in the change of the capital expenditure accrual. We conducted drilling and completion operations on 19 gross (12.1 net) wells bringing 16 gross (7.5 net) wells on production in the Haynesville Shale Trend during the year ended December 31, 2018, and we capitalized $3.5 million in internal costs. We had 5 gross (4.6 net) wells waiting completion at December 31, 2018.
Financing activities: Net cash provided by financing activities for the year ended December 31, 2018 was $7.1 million consisting of net draws of $10.3 million on the 2017 Senior credit facility reduced by $3.1 million for the purchase of shares withheld from employee stock awards for the payments of taxes and $0.1 million of debt issuance cost paid upon the amendment of the 2017 Senior Credit Facility of $23.7 million.Facility.
Debt consisted of the following balances as of the dates indicated (in thousands):
| December 31, 2017 | December 31, 2016 | ||||||||||||||||||||||
| Principal | Carrying Amount | Fair Value | Principal | Carrying Amount | Fair Value | ||||||||||||||||||
| Exit Credit Facility (1) | $ | — | $ | — | $ | — | $ | 16,651 | $ | 16,651 | $ | 16,651 | |||||||||||
| 2017 Senior Credit Facility (1) | 16,723 | 16,723 | 16,723 | — | — | — | |||||||||||||||||
| Convertible Second Lien Notes (2) | 47,015 | 39,002 | 62,026 | 41,170 | 30,554 | 29,036 | |||||||||||||||||
| Total debt | $ | 63,738 | $ | 55,725 | $ | 78,749 | $ | 57,821 | $ | 47,205 | $ | 45,687 | |||||||||||
December 31, 2019 | December 31, 2018 | |||||||||||||||||||||||
Principal | Carrying Amount | Fair Value | Principal | Carrying Amount | Fair Value | |||||||||||||||||||
| 2017 Senior Credit Facility (1) | $ | - | $ | - | $ | - | $ | 27,000 | $ | 27,000 | $ | 27,000 | ||||||||||||
2019 Senior Credit Facility (1) | 92,900 | 92,900 | 92,900 | - | - | - | ||||||||||||||||||
| Convertible Second Lien Notes (2) | - | - | - | 53,691 | 49,820 | 60,857 | ||||||||||||||||||
| New 2L Notes (3) | 12,969 | 11,535 | 12,952 | - | - | - | ||||||||||||||||||
Total debt | $ | 105,869 | $ | 104,435 | $ | 105,852 | $ | 80,691 | $ | 76,820 | $ | 87,857 | ||||||||||||
(1) | |
The carrying |
(2) | The debt discount was being amortized using the effective interest rate method based upon a maturity date of August 30, 2019 until the Convertible Second Lien Notes were fully paid off on May 29, 2019. |
| The debt discount is being amortized using the effective interest rate method based upon a maturity date of |
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, 2019 | Year Ended December 31, 2018 | |||||||||||||||
Effective | Effective | |||||||||||||||
Interest | Interest | Interest | Interest | |||||||||||||
Expense | Rate | Expense | Rate | |||||||||||||
2017 Senior Credit Facility | $ | 872 | 7.2 | % | $ | 1,130 | 8.9 | % | ||||||||
2019 Senior Credit Facility | 3,409 | 6.0 | % | - | - | |||||||||||
Convertible Second Lien Notes (1) | 5,304 | 24.1 | % | 10,814 | 23.9 | % | ||||||||||
| New 2L Notes (2) | 1,416 | 21.6 | % | - | - | |||||||||||
Total | $ | 11,001 | $ | 11,944 | ||||||||||||
| (1) | The Convertible 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) and 23.9% for the year ended December 31, 2018. 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. Interest expense for the year ended December 31, 2018 included $4.1 million of debt discount amortization and $6.7 million of paid-in-kind interest. |
| (2) | The New 2L 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 21.6% for the year ended December 31, 2019. Interest expense for the year ended December 31, 2019 included $0.3 million of debt discount amortization and $1.0 million of accrued interest to be paid in-kind. |
| Successor | Successor | Predecessor | ||||||||||||||||||
| Year Ended December 31, 2017 | Period from October 12, 2016 through December 31, 2016 | Period from January 1, 2016 through October 12, 2016 | ||||||||||||||||||
| Interest Expense | Effective Interest Rate | Interest Expense | Effective Interest Rate | Interest Expense | Effective Interest Rate | |||||||||||||||
| Senior Credit Facility | $ | — | — | % | $ | — | — | % | $ | 3,342 | * | |||||||||
| Exit Credit Facility | 947 | 7.1 | % | 306 | 7.3 | % | — | — | % | |||||||||||
| 2017 Senior Credit Facility | 244 | 7.2 | % | — | — | % | — | — | % | |||||||||||
| Convertible Second Lien Notes (1) | 8,534 | 24.1 | % | 1,518 | 24.7 | % | — | — | % | |||||||||||
| Obligations Canceled on the Effective Date | — | — | % | — | — | % | 8,010 | * | ||||||||||||
| Other | — | — | % | — | — | % | 46 | * | ||||||||||||
| Total | $ | 9,725 | $ | 1,824 | $ | 11,398 | ||||||||||||||
Future Commitments
The table below (in thousands) provides estimates of the timing of future paymentspayments that we are obligated to make based on agreements in place at December 31, 2017.2019. In addition to the contractual obligations presented in the table below, our Consolidated Balance Sheet at December 31, 20172019 reflects accrued interest on our bank debt of $0.2 million payable in the first halfquarter of 2017.2020. For additional information see Note 5—Debt, and 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 | 2018 | 2019 | 2020 | 2021 | 2022 and After | |||||||||||||||||||
| Debt | 5 | $ | 75,387 | $ | — | $ | 58,664 | $ | — | $ | 16,723 | $ | — | ||||||||||||
| Office space leases | 5,103 | 1,510 | 1,540 | 1,540 | 513 | — | |||||||||||||||||||
| Operations contracts | 871 | 836 | 20 | 15 | — | — | |||||||||||||||||||
| Total contractual obligations (1) | $ | 81,361 | $ | 2,346 | $ | 60,224 | $ | 1,555 | $ | 17,236 | $ | — | |||||||||||||
Payment due by Period | ||||||||||||||||||||||||||||
Note | Total | 2020 | 2021 | 2022 | 2023 | 2024 | ||||||||||||||||||||||
and After | ||||||||||||||||||||||||||||
Debt | 5 | $ | 105,869 | $ | - | $ | 12,969 | $ | - | $ | - | $ | 92,900 | |||||||||||||||
| Office space leases | 11 | 2,353 | 1,540 | 813 | - | - | - | |||||||||||||||||||||
| Operations contracts | 2,491 | 2,491 | - | - | - | - | ||||||||||||||||||||||
Total contractual obligations (1) | $ | 110,713 | $ | 4,031 | $ | 13,782 | $ | - | $ | - | $ | 92,900 | ||||||||||||||||
(1) | |
This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of |
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, 20172019 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. Generally Accepted Accounting Principles (“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.
Under the Full Cost Method, we will 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. We now 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 therebytherefore subject to DD&A. Our sales of oil and gas properties are now 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 now capitalized, and DD&A expense is now 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 (the “UOP”) method. This entails the provision for DD&A expense being computed by dividing production volumes for the period by theAn amortization rate is calculated based on total proved reserves converted to equivalent thousand cubic feet of natural gas (“Mcfe”) as of the beginning of the period (beginning of period reserves being determined by adding
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 which represent fair value because of the short-term nature of these instruments. For definitions for 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 which 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.
Quantitative and Qualitative Disclosures About Market Risk |
As a smaller reporting company, we are attributablenot required to fluctuations in commodity prices and interest rates. These fluctuations can affect revenues and cash flow from operating, investing and financing activities. Our risk-management policies provide for the useinformation required by this Item 7A.
Financial Statements and Supplementary Data |
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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Management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. Our internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. We assessed the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO). Based on our evaluation under the framework in Internal Control—Integrated Framework, we have concluded that our internal control over financial reporting was effective as of December 31, Management of Goodrich Petroleum Corporation GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (In Thousands) December 31, 2019 December 31, 2018 ASSETS CURRENT ASSETS: Cash and cash equivalents Accounts receivable, trade and other, net of allowance Accrued oil and natural gas revenue Fair value of oil and natural gas derivatives Inventory Prepaid expenses and other Total current assets PROPERTY AND EQUIPMENT: Unevaluated properties Oil and gas properties (full cost method) Furniture, fixtures and equipment Less: Accumulated depletion, depreciation and amortization Net property and equipment Fair value of oil and natural gas derivatives Deferred tax asset Other TOTAL ASSETS LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT) CURRENT LIABILITIES: Accounts payable Accrued liabilities Total current liabilities Long term debt, net Accrued abandonment costs Fair value of oil and natural gas derivatives Total liabilities 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 12,532,550 shares issued and outstanding at December 31, 2019 and $0.01 par value, 75,000,000 shares authorized, and 12,150,918 shares issued and outstanding at December 31, 2018 Additional paid-in capital Retained earnings (deficit) Total stockholders’ equity TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY See accompanying notes to consolidated financial statements. CONSOLIDATED STATEMENTS OF OPERATIONS (In Thousands, Except Per Share Amounts) REVENUES: Oil and natural gas revenues Other OPERATING EXPENSES: Lease operating expense Production and other taxes Transportation and processing Depreciation, depletion, and amortization General and administrative Other Operating income OTHER INCOME (EXPENSE): Interest expense Interest income and other Gain (loss) on derivatives not designated as hedges Reorganization items, net Income before income taxes Income tax benefit Net income PER COMMON SHARE: Net income per common share—basic Net income per common share—diluted Weighted average shares of common stock outstanding—basic Weighted average shares of common stock outstanding—diluted See accompanying notes to consolidated financial statements. CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands) Year Ended December 31, 2019 Year Ended December 31, 2018 CASH FLOWS FROM OPERATING ACTIVITIES: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization Deferred income taxes (Gain) loss on derivatives not designated as hedges Net cash received (paid) in settlement of derivative instruments Share-based compensation (non-cash) Amortization of finance cost, debt discount, paid-in-kind interest and accretion Reorganization items (non-cash) Loss (gain) 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 Prepaid expenses and other Accounts payable Accrued liabilities Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures Proceeds from sale of assets Net cash used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Principal payments of bank borrowings Proceeds from bank borrowings Issuance cost, net Other including purchase of treasury stock Net cash provided by financing activities Decrease in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period Supplemental disclosures of cash flow information: Cash paid during the year for interest Cash paid during the year for taxes Decrease in non-cash capital expenditures See accompanying notes to consolidated financial statements. 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, 2017 Net income Share-based compensation Restricted stock vesting & other Convertible Second Lien Notes warrants and conversions Issuance cost Treasury stock activity Balance at December 31, 2018 Net income Share-based compensation Restricted stock vesting & other Convertible Second Lien Notes warrant exercises New 2L Notes conversion Treasury stock activity Balance at December 31, 2019 See accompanying notes to consolidated financial statements. 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 Use of Estimates Cash and Cash Equivalents Accounts Payable December 31, 2019 2018 Trade payables Revenue payables Prepayments from partners Other Total Accounts payable Accrued Liabilities December 31, 2019 2018 Accrued capital expenditures Accrued lease operating expense Accrued production and other taxes Accrued transportation and gathering Accrued performance bonus Accrued interest Accrued office lease Accrued general and administrative expense and other Inventory GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Property and Equipment— 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 Under the Full Cost Method, we amortize our investment in oil and natural gas properties through DD&A expense using the units of production 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 Ceiling Test performed as of December 31, Fair Value Measurement 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 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. Included in this Level would be our initial measurement of asset retirement obligations. As of December 31, Asset Retirement Obligations 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 Derivative Instruments Income Taxes 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 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 Commitments and Contingencies Concentration of Credit Risk Year Ended December 31, 2019 2018 ETC Genesis Crude Oil LP Share-based Compensation Guarantee Debt Issuance Cost New Accounting Pronouncements In August 2018, the FASB issued ASU GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 2—Revenue Recognition On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and the series of related ASU's that followed under ASC Topic 606 (collectively, “Topic 606”).Under Topic 606, revenue will generally be 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 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, 2019 and December 31, 2018, receivables from contracts with customers were $11.3 million and $14.5 million, respectively. Topic 606 will not change our pattern of timing of revenue recognition. We utilized the full retrospective method for adoption of Topic 606, and in accordance with this method our consolidated financial statements for periods The following tables present our oil and natural gas revenues disaggregated by revenue source and by operated and non-operated properties: Year Ended December 31, 2019 (In thousands) Oil Revenue Gas Revenue NGL Revenue Total Oil and Natural Gas Revenues Operated Non-operated Total oil and natural gas revenues Year Ended December 31, 2018 (In thousands) Oil Revenue Gas Revenue NGL Revenue Total Oil and Natural Gas Revenues Operated Non-operated Total oil and natural gas revenues 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, 2016 Long Term Incentive Plan Our 2016 Long Term Incentive Plan (the “LTIP”), formerly referred to as the Management Incentive Plan, In Performance Share Unit Awards In December 2019, the Company granted approximately 205,000 PSUs. The • Volatility factor - The volatility factor represents the extent to which the market price of a share of the Company's common stock is expected to fluctuate between the grant date and the end of the performance period. • Dividend yield - The dividend yield on the Company's common stock was assumed to be zero since the Company does not anticipate paying dividends within the vesting term of the PSU’s. • Risk-free interest rate - The risk-free interest rate is based upon the yield of US Treasuries with a three year term. • Expected term - The expected term represents the period of time that the PSUs will be outstanding, which is the grant date to the end of the performance period, or three years. GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The grant date fair value of each PSU as determined by the Monte Carlo simulation model was Number of simulations Grant price Volatility factor Dividend yield Risk-free interest rate Expected term (in years) P3Y The fair value of the Share-based Compensation The following tables summarizes the pre-tax components of our share-based compensation program under the Year Ended December 31, 2016 Long Term Incentive Plan 2019 2018 RSU expense - employees PSU expense RSU expense - directors Total share-based compensation GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS RSUs and RSU and PSU activity and changes under the LTIP for the 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, 2017 Granted (1) Vested (1) Forfeited Unvested at December 31, 2018 Granted Vested Forfeited Unvested at December 31, 2019 (1) Includes 201,969 shares of common stock issued in settlement for 2017 performance bonuses, which were paid in 2018. As of December 31, 2016 Long Term Incentive Plan Unrecognized compensation costs Weighted Average years to recognition (thousands) (years) RSU PSU Total RSU PSU Total December 31, 2019 December 31, 2018 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, 2019 December 31, 2018 Beginning balance Liabilities incurred Revisions in estimated liabilities (1) Liabilities settled Accretion expense Dispositions (2) Ending balance Current liability Long term liability (1) (2) See Note 12 for further information on the dispositions during the year ended December 31, 2019. 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, 2019 December 31, 2018 Principal Carrying Amount Fair Value Principal Carrying Amount Fair Value 2019 Senior Credit Facility (1) New 2L Notes (3) Total debt (1) The carrying amount for the (2) The debt discount was being amortized using the effective interest rate method based upon a maturity date of August 30, 2019 until the Convertible Second Lien Notes were fully paid off on May 29, 2019. 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, 2019 Year Ended December 31, 2018 Interest Expense Effective Interest Rate Interest Expense Effective Interest Rate 2019 Senior Credit Facility Convertible Second Lien Notes (1) Total 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, All amounts outstanding under the 2017 Senior Credit Facility 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 (a) May 14, 2024 or b) December 3, 2020, if the New 2L Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by December 3, 2020, which is the date that is 180 days prior to the “Maturity Date” as defined in the indenture governing the New 2L Notes (the “New 2L Notes Indenture”) as in effect on the issuance date of the New 2L Notes. The 2019 Senior Credit Facility provides for a maximum credit amount of $500 million subject to a borrowing base limitation, which originally was $115 million. The borrowing base was increased to $125 million in August of 2019 and is scheduled to be redetermined thereafter 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 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 As of December 31, As of December 31, GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Convertible Second Lien In October 2016, the Company The Convertible Second Lien Notes Upon issuance of the Convertible 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 New Convertible Second Lien Notes On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New 2L Notes Purchaser”) pursuant to which the Company issued to the New 2L Notes Purchasers (the “New 2L Notes Offering”) $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “New 2L Notes”). The closing of the New 2L Notes Offering occurred on May 31, 2019. Proceeds from the sale of the New 2L Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility. Holders of the New 2L Notes have a second priority lien on all assets of the Company. The New 2L Notes, as set forth in the indenture governing such notes (the “New 2L Notes Indenture”), are scheduled to mature on May 31, 2021. The New 2L 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 New 2L Notes by increasing the principal amount of the outstanding New 2L Notes. The New 2L 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 New 2L 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 New 2L 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 New 2L Notes are convertible into the Company’s common stock at the conversion rate, which is the sum of the outstanding principal amount of New 2L 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 New 2L 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 New 2L Notes Indenture, (2) cash or (3) a combination of shares of its common stock and cash; however, the Company’s ability to redeem the New 2L Notes with cash is subject to the terms of the 2019 Senior Credit Agreement. The New 2L Notes were issued and sold to the New 2L Notes Purchasers pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereunder. The Company has completed the registration with the U.S. Securities and Exchange Commission of the resale of the New 2L Notes and the shares of common stock issuable upon conversion of The New 2L Notes. Upon issuance of the New 2L 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. As of December 31, 2019, $1.1 million of debt discount As of December 31, GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 6— Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted Basic net income per common share: Net income applicable to common stock Weighted-average shares of common stock outstanding Basic net income per common share Diluted net income per common share: Net income applicable to common stock Weighted-average shares of common stock outstanding Common shares issuable upon conversion of the Convertible Second Lien Notes associated warrants Common shares issuable upon conversion of warrants of unsecured claim holders Common shares issuable on assumed conversion of restricted stock * Diluted weighted average shares of common stock outstanding Diluted net income per common share (1) (1) Common shares issuable upon conversion of the New 2L Notes and Convertible Second Lien Notes were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. * Common shares issuable on assumed conversion of restricted stock from share-based compensation assumes a payout of the Company's performance share awards at 100% of the initial performance 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 250% 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): Current tax expense (benefit) Federal State Total current tax expense (benefit) 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 Income tax expense (benefit) Tax expense at U.S. statutory rate Valuation allowance State income taxes, net of federal benefit Nondeductible expenses and other 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, December 31, 2019 2018 Non-current deferred tax assets: Operating loss carry-forwards State tax NOL and credits Statutory depletion carry-forward AMT tax credit carry-forward Compensation Contingent liabilities and other Lease liabilities Debt discount Property and equipment Total gross non-current deferred tax assets Less valuation allowance Net non-current deferred tax assets Non-current deferred tax liabilities: Derivatives Total non-current deferred tax liabilities Net non-current deferred tax asset GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The As of December 31, 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 We did not have any unrecognized tax benefits as of December 31, 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, GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 8—Stockholders’ Equity At December 31, During the year ended December 31, In connection with the issuance of the New 2L Notes, we recorded an equity component of $1.4 million. For further details, see Note 5. During the year ended December 31, 2018, certain holders of the 10 year costless warrants associated with the Convertible Second Lien Notes exercised 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 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) Gain (loss) on commodity derivatives not designated as hedges, settled Gain (loss) on commodity derivatives not designated as hedges, not settled Total gain (loss) on commodity derivatives not designated as hedges 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 Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural As of December 31, Contract Type Average Daily Volume Total Volume Weighted Average Fixed Price Crude oil swaps (Bbls) 2020 2020 2021 $2.64 Natural gas basis swaps (MMBtu) 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, 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 Fair value of oil and natural gas derivatives - Non-current Liabilities Total We enter into oil and natural gas derivative contracts under which we have netting arrangements with each December 31, 2019 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 Fair value of oil and natural gas derivatives - Non-current Assets Fair value of oil and natural gas derivatives - Current Liabilities Fair value of oil and natural gas derivatives - Non-current Liabilities Total 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, Payment due by Period Note Total 2020 2021 2022 2023 2024 and After Debt Operations contracts Total contractual obligations (1) (1) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of Operating Leases 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, 2019 are classified as follows: (in thousands) Consolidated Statements of Operations Classification Building lease cost General and administrative expense Variable lease cost (1) General and administrative expense The following are additional details related to our lease portfolio as of December 31, 2019: (in thousands) December 31, 2019 Consolidated Balance Sheets Classification Lease asset, gross Furniture, fixtures and equipment and other capital assets Accumulated depreciation Accumulated depletion, depreciation and amortization Lease asset, net Current lease liability Accrued liabilities Non-current lease liability Other non-current liabilities Total lease liabilities The following table presents operating lease liability maturities as of December 31, 2019: (in thousands) December 31, 2019 2020 2021 2022 2023 Thereafter Total lease payments Less imputed interest Present value of lease liabilities As of December 31, 2019, our office building operating lease has a GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 12—Dispositions and On March 1, 2019, the Company On May 21, 2018, the On February 28, 2018, the Company closed, in two separate transactions, the sale of working interests in certain oil and gas leases, wells, units and facilities The Company also sold other miscellaneous acreage during the year ended December 31, 2018 for $0.7 million, which was also recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheets. SUPPLEMENTAL INFORMATION (Unaudited) NOTE 13—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 engineers. The technical persons primarily responsible for overseeing the preparation of the reserves estimates meet the requirements regarding qualifications. Our principal internal engineer has over 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 Capitalized Costs The table below reflects our capitalized costs related to our oil and natural gas producing activities at December 31, Proved properties Unproved properties Less: accumulated depreciation, depletion and amortization Net oil and natural gas properties We did not have any capitalized exploratory well costs that were pending the determination of proved reserves as of December 31, Costs incurred in oil and natural gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows (in thousands): Property Acquisition Unproved Proved Exploration Development (1) Total (2) (1) Includes asset retirement costs of (2) Substantially all the costs incurred The following table sets forth our net proved oil and natural gas reserves at December 31, Natural Gas (Mmcf) Oil, Condensate and NGLs (MBbls) 2019 2018 2017 2019 2018 2017 Net proved reserves at beginning of period Revisions of previous estimates (1) Extensions, discoveries and improved recovery (2) Purchases of minerals in place Sales of minerals in place Production Net proved reserves at end of period Net proved developed reserves: Beginning of period Net proved undeveloped reserves: Beginning of period Natural Gas Equivalents (Mmcfe) 2019 2018 2017 Sales of minerals in place (3) (1) Revisions of previous estimates in 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. Revisions of previous estimates in 2017 were positive, primarily due to the application of both experience and ever improving technology in drilling and completing Haynesville Shale natural gas wells. Well production performance has improved by drilling longer laterals, increasing both the number of frac stages and the amount of sand used in each frac stage. (2) Extensions and discoveries were positive on an overall basis in all three periods presented, primarily (3) In 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): 2019 2018 2017 Future revenues Future lease operating expenses and production taxes Future development costs (1) Future income tax expense Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted future net cash flows Index price used to calculate reserves (2) Natural gas (per Mcf) Oil (per Bbl) (1) Includes cumulative asset retirement obligations of (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, 2019 2018 2017 Balance, beginning of year Net changes in prices and production costs related to future production Sales and transfers of oil and natural gas produced, net of production costs Net change due to revisions in quantity estimates Net change due to extensions, discoveries and improved recovery Net change due to purchases and sales of minerals in place Changes in future development costs Previously estimated development cost incurred in period Net change in income taxes Accretion of discount Change in production rates (timing) and other Net increase (decrease) in standardized measures Balance, end of year Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Controls and Procedures Evaluation of Disclosure Controls and Procedures 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 SEC rule 13a-15(b), 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(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of December 31, Management’s Annual Report on Internal Control Over Financial Reporting See Item 8—Financial Statements and Supplementary Data—Management’s Annual Report on Internal Controls over Financial Reporting” of this Annual Report on Form 10-K Attestation Report of the Registered Public Accounting Firm See “Item 8— Financial Statements and Supplementary Data Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting. Other Information None. Directors, Executive Officers and Corporate Governance Our executive officers and directors and their ages and positions as of March Name Age Position Walter G. “Gil” Goodrich 61 Chairman of the Board of Directors, Chief Executive Officer and Director Robert C. Turnham, Jr. 62 President, Chief Operating Officer and Director Mark E. Ferchau 65 Executive Vice President Michael J. Killelea 57 Executive Vice President, General Counsel and Corporate Secretary Robert T. Barker 69 Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer Ronald F. Coleman 65 Director K. Adam Leight Director Director Director 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 1995. 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. Mark E. Ferchau became Executive Vice President of the Company in 2004. He had previously served as the Company’s Senior Vice President, Engineering and Operations, after initially joining the Company as a Vice President in 2001. Mr. Ferchau previously served as Production Manager for Forcenergy Inc. from 1997 to 2001 and as Vice President, Engineering of Convest Energy Corporation from 1993 to 1997. Prior thereto, Mr. Ferchau held various positions with Wagner & Brown, Ltd. and other independent oil and gas companies. 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 30 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 law department at CMS Energy Corporation from 1988 to 2000, including Chief Counsel at CMS Oil & Gas Company from 1995 to 2000. Robert T. Barker joined the Company in 2007 as Manager, Financial Reporting and has held various positions within the Accounting Department with increasing responsibility, most recently Ronald F. Coleman is an energy executive with over 37 years of international and domestic oilfield services K. Adam Leight has spent over 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, 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 Thomas M. Souers Additional information required under this “Item 10—Directors, Executive Officers and Corporate Governance,” will be provided in our Proxy Statement for the 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 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 Certain Relationships and Related Transactions and Director Independence The information required by this Item is incorporated by reference to the information provided under the caption “Transactions with Related Persons” and “Corporate Governance-Our Board-Board Size; Director Independence” in our definitive proxy statement for the 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 Exhibits, Financial Statement Schedules (a)(1) and (2) Financial Statements and Financial Statement Schedules See “Index to Consolidated Financial 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 10.4 10.5 10.6 10.7† 10.8† 10.9† 10.10† 10.11† 10.12† 10.13† 10.14† 10.15† 21 Subsidiary of the Registrant: Goodrich Petroleum Company L.L.C. - Organized in the State of Louisiana. 23.1* 23.2* 23.3* 31.1* 31.2* 32.1** 32.2** 99.1* 99.2* 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. † Denotes management contract or compensatory plan or arrangement. Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March GOODRICH PETROLEUM CORPORATION By: /s/ WALTER G. GOODRICH Walter G. Goodrich Chief Executive Officer POWER OF ATTORNEY Each person whose signature appears below hereby constitutes and appoints Walter G. Goodrich and Robert T. Barker and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities indicated on March Signature Title /s/ WALTER G. GOODRICH Chairman, Chief Executive Officer and Director (Principal Executive Officer) Walter G. Goodrich / President, Chief Operating Officer and Director Robert C. Turnham, Jr. / Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer Robert T. Barker / Director Ronald Coleman / Director Adam Leight /s/ TIM LEULIETTE Director Tim Leuliette /s/ JEFFREY SEROTA Director Jeffrey Serota /s/ EDWARD SONDEY Director Edward Sondey /s/ TOM SOUERS Director Tom Souers 85boardBoard of directorsDirectors of the Company and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.2017.sheetsheets of Goodrich Petroleum Corporation and subsidiary (the “Company”) as of December 31, 2017 (Successor),2019 and 2018, the related consolidated statements of operations, stockholders’ equity and cash flows for the yearyears then ended, (Successor), 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, 2017,2019 and 2018, and the consolidated results of its operations and its cash flows for the yearyears then ended, in conformity with accounting principles generally accepted in the United States of America.Emphasis of MatterAs discussed in Note 2 to the consolidated financial statements, the Company emerged from bankruptcy on October 12, 2016. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification 852-10, Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods as described in Note 2.audit.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.auditaudits 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 auditaudits 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.auditaudits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial 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 auditaudits 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 audit providesaudits provide a reasonable basis for our opinion.2, 20185, 2020To the Board of Directors and StockholdersGoodrich Petroleum CorporationWe have audited the accompanying consolidated balance sheet of Goodrich Petroleum Corporation and subsidiary (the “Company”) as of December 31, 2016 (Successor) and the related consolidated statements of operations, stockholders’ equity and cash flows for the periods from October 13, 2016 through December 31, 2016 (Successor), and January 1, 2016 through October 12, 2016 (Predecessor). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Goodrich Petroleum Corporation and subsidiary as of December 31, 2016 (Successor) and the results of their operations and their cash flows for the periods from October 13, 2016 through December 31, 2016 (Successor) and January 1, 2016 through October 12, 2016 (Predecessor), in conformity with U.S. generally accepted accounting principles.As discussed in Note 2 to the consolidated financial statements, the Company emerged from bankruptcy on October 12, 2016. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification 852-10, Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods as described in Note 2./s/ Hein & Associates LLPHouston, TexasMarch 3, 2017NOTES TO CONSOLIDATED FINANCIAL STATEMENTSGOODRICH PETROLEUM CORPORATION AND SUBSIDIARY $ 1,452 $ 4,068 1,131 744 11,345 14,464 8,537 803 234 596 549 533 23,248 21,208 123 180 302,859 206,097 4,450 1,360 307,432 207,637 (94,124 ) (42,447 ) 213,308 165,190 31 - 393 786 2,338 580 $ 239,318 $ 187,764 $ 26,348 $ 25,734 16,615 16,518 42,963 42,252 104,435 76,820 4,169 3,791 2,786 471 Non-current operating lease liability 800 - 155,153 123,334 - - 125 122 81,305 74,861 2,735 (10,553 ) 84,165 64,430 $ 239,318 $ 187,764 December 31,
2017 December 31,
2016ASSETS CURRENT ASSETS: Cash and cash equivalents $ 25,992 $ 36,850 Accounts receivable, trade and other, net of allowance 1,371 1,998 Accrued oil and natural gas revenue 4,958 3,142 Fair value of oil and natural gas derivatives 2,034 — Inventory 2,521 4,125 Prepaid expenses and other 1,614 755 Total current assets 38,490 46,870 PROPERTY AND EQUIPMENT: Unevaluated properties 5,984 24,206 Oil and gas properties (full cost method) 120,333 60,936 Furniture, fixtures and equipment 1,039 984 127,356 86,126 Less: Accumulated depletion, depreciation and amortization (15,899 ) (4,006 ) Net property and equipment 111,457 82,120 Fair value of oil and natural gas derivatives 566 — Deferred tax asset 937 — Other 691 322 TOTAL ASSETS $ 152,141 $ 129,312 LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Accounts payable $ 17,204 $ 14,392 Accrued liabilities 18,075 3,882 Fair value of oil and natural gas derivatives 1,002 — Total current liabilities 36,281 18,274 Long term debt, net 55,725 47,205 Accrued abandonment cost 3,367 2,933 Fair value of oil and natural gas derivatives 517 — Total liabilities 95,890 68,412 Commitments and contingencies (See Note 10) STOCKHOLDERS’ EQUITY: Successor Preferred stock: 10,000,000 shares $1.00 par value authorized, and none issued and outstanding — — Successor Common stock: $0.01 par value, 75,000,000 shares authorized, and 10,770,962 and 9,108,826 shares issued and outstanding as of December 31, 2017 and 2016, respectively 108 91 Additional paid in capital 68,446 65,116 Accumulated deficit (12,303 ) (4,307 ) Total stockholders’ equity 56,251 60,900 TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 152,141 $ 129,312 Year Ended December 31, 2019 Year Ended December 31, 2018 $ 118,353 $ 87,943 (3 ) 53 118,350 87,996 12,371 10,446 2,573 2,605 20,703 11,046 50,722 26,809 20,775 19,663 106 7 107,250 70,576 11,100 17,420 (11,001 ) (11,944 ) 25 508 15,010 (3,986 ) Loss on early extinguishment of debt (1,846 ) - 2,188 (15,422 ) - (305 ) 13,288 1,693 - 57 $ 13,288 $ 1,750 $ 1.09 $ 0.15 $ 0.96 $ 0.13 12,233 11,622 13,895 13,665 Successor Successor Predecessor Year ended December 31, 2017 Period from October 13, 2016 to December 31, 2016 Period ended October 12, 2016 REVENUES: Oil and natural gas revenues $ 45,320 $ 6,537 $ 21,027 Other 833 45 (341 ) 46,153 6,582 20,686 OPERATING EXPENSES: Lease operating expense 12,125 2,109 6,504 Production and other taxes 1,183 619 1,946 Transportation and processing 6,222 228 1,265 Depreciation, depletion and amortization 12,125 1,556 8,276 Exploration — — 577 Impairment — 2,486 1,583 General and administrative 16,696 2,200 14,474 Gain on sale of assets — (2 ) (840 ) Other (43 ) — — 48,308 9,196 33,785 Operating loss (2,155 ) (2,614 ) (13,099 ) OTHER INCOME (EXPENSE): Interest expense (9,725 ) (1,824 ) (11,398 ) Interest income and other 1,236 1 117 Gain on derivatives not designated as hedges 1,552 — 30 Restructuring — — (5,128 ) (6,937 ) (1,823 ) (16,379 ) Reorganization items, net 118 130 399,422 Income (loss) before income taxes (8,974 ) (4,307 ) 369,944 Income tax benefit 978 — — Net income (loss) (7,996 ) (4,307 ) 369,944 Preferred stock, net — — 11,237 Net income (loss) applicable to common stock $ (7,996 ) $ (4,307 ) $ 358,707 PER COMMON SHARE Net income (loss) applicable to common stock—basic $ (0.80 ) $ (0.60 ) $ 4.64 Net income (loss) applicable to common stock—diluted $ (0.80 ) $ (0.60 ) $ 3.69 Weighted average common shares outstanding—basic 9,975 7,184 77,236 Weighted average common shares outstanding—diluted 9,975 7,184 98,369 $ 13,288 $ 1,750 50,722 26,809 Right of use asset depreciation 1,252 - - (57 ) (15,010 ) 3,986 9,560 (3,236 ) 6,400 6,545 Loss on early extinguishment of debt 1,846 - 7,097 10,983 - (476 ) 327 (32 ) 6 835 3,119 (9,506 ) Inventory 35 - (45 ) (249 ) 614 8,530 (140 ) 3,304 79,071 49,186 (99,301 ) (105,088 ) 1,334 26,839 (97,967 ) (78,249 ) (49,500 ) (16,723 ) 115,400 27,000 Repayment of Convertible Second Lien Notes (56,728 ) - Proceeds from New 2L Notes 12,000 - (2,795 ) (49 ) (2,097 ) (3,089 ) 16,280 7,139 (2,616 ) (21,924 ) 4,068 25,992 $ 1,452 $ 4,068 $ 4,137 $ 575 $ - $ - $ (1,911 ) $ (2,425 ) Successor Successor Predecessor Year ended December 31, 2017 October 13, to December 31, 2016 January 1, 2016 to October 12, 2016 CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ (7,996 ) $ (4,307 ) $ 369,944 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depletion, depreciation and amortization 12,125 1,556 8,276 Deferred income taxes (937 ) — — (Gain) on derivatives not designated as hedges (1,552 ) — (30 ) Net cash received in settlement of derivative instruments 471 — — Impairment — 2,486 1,583 Embedded derivative — — (5,538 ) Amortization of leasehold costs — — 67 Share-based compensation (non-cash) 6,863 240 3,307 Gain on sale of assets — — (840 ) Amortization of finance cost and debt discount 8,534 1,518 7,425 Reorganization items (1 ) (6,658 ) (410,875 ) Gain from material transfers (367 ) — — Amortization of transportation obligation — — 156 Change in assets and liabilities: Accounts receivable, trade and other, net of allowance 627 (1,408 ) 724 Accrued oil and natural gas revenue (1,816 ) 1,065 (786 ) Inventory — — (265 ) Prepaid expenses and other (881 ) (66 ) 811 Accounts payable 1,888 1,631 (4,332 ) Accrued liabilities 1,348 (384 ) 13,689 Net cash provided by (used in) operating activities 18,306 (4,327 ) (16,684 ) CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (28,763 ) (3,232 ) (3,789 ) Proceeds from sale of assets 563 849 294 Net cash used in investing activities (28,200 ) (2,383 ) (3,495 ) CASH FLOWS FROM FINANCING ACTIVITIES: Principal payments of bank borrowings (16,651 ) (23,742 ) — Proceeds from bank borrowings 16,723 — 13,000 Proceeds from equity offering, net of issuance costs — 23,622 — Proceeds from Second Lien Notes — 40,000 — Note conversions — — (804 ) Debt issuance costs (694 ) — (114 ) Issuance cost, net (342 ) — — Other — — (5 ) Net cash provided by (used in) financing activities (964 ) 39,880 12,077 Increase (decrease) in cash and cash equivalents (10,858 ) 33,170 (8,102 ) Cash and cash equivalents, beginning of period 36,850 3,680 11,782 Cash and cash equivalents, end of period $ 25,992 $ 36,850 $ 3,680 Supplemental disclosures of cash flow information: Cash paid during the year for interest $ 1,228 $ 498 $ 1,656 Cash paid during the year for taxes $ — $ — $ — Increase (decrease) in non-cash capital expenditures $ 9,863 $ 556 $ (836 ) - $ - 10,771 $ 108 $ 68,446 - $ - $ (12,303 ) $ 56,251 - - - - - - - 1,750 1,750 - - - - 7,322 - - - 7,322 - - 690 7 2,186 (230 ) (2,970 ) - (777 ) - - 920 9 (5 ) - - - 4 - - - - (120 ) - - - (120 ) - - (230 ) (2 ) (2,968 ) 230 2,970 - - - - 12,151 122 74,861 - - (10,553 ) 64,430 - - - - - - - 13,288 13,288 - - - - 7,221 - - - 7,221 - - 232 4 (90 ) (208 ) (2,098 ) - (2,184 ) - - 150 1 (20 ) - - - (19 ) - - - - 1,429 - - - 1,429 - - - (2 ) (2,096 ) 208 2,098 - - - $ - 12,533 $ 125 $ 81,305 - $ - $ 2,735 $ 84,165 Preferred
Stock Common
Stock Additional
Paid-in Treasury
Stock Retained
Earnings/ Total
Stockholders’Predecessor Company Shares Value Shares Value Capital Shares Value (Deficit) Equity/(Deficit) Balance at December 31, 2015 1,502 $ 1,502 63,910 $ 12,782 $ 1,069,673 (173 ) $ (41 ) $ (1,492,001 ) $ (408,085 ) Net income — — — — — — — 369,944 369,944 Preferred stock dividends — — — — — — — 4,112 4,112 Preferred stock conversion (9 ) (9 ) 6,102 1,220 (5,322 ) — — — (4,111 ) Share-based compensation — — — — 6,115 — — — 6,115 Warrant issuance — — — — 403 — — — 403 Equity offering — — — — — — — — — Director shares issued — — — — — — — — — Treasury stock activity — — 146 29 (29 ) (47 ) (5 ) — (5 ) Convertible note issuance — — — — — — — — — Note conversions — — 9,818 1,964 29,663 — — — 31,627 Balance at October 12, 2016 1,493 $ 1,493 79,976 $ 15,995 $ 1,100,503 (220 ) $ (46 ) $ (1,117,945 ) $ — Cancellation of predecessor equity (1,493 ) (1,493 ) (79,976 ) (15,995 ) (1,100,503 ) 221 46 1,117,945 — Balance at October 12, 2016 Predecessor — $ — — $ — $ — — $ — $ — $ — Successor Company Issuance of common stock and warrants — — 6,836 68 30,312 — — — 30,380 Net loss — — — — — — — (4,307 ) (4,307 ) Share-based compensation — — — — 240 — — — 240 Second Lien warrants and conversion — — — — 10,964 — — — 10,964 Equity offering — — 2,273 23 23,727 — — — 23,750 Issuance cost — — — — (127 ) — — — (127 ) Balance at December 31, 2016 Successor — $ — 9,109 $ 91 $ 65,116 — $ — $ (4,307 ) $ 60,900 Net loss — — — — — — — (7,996 ) (7,996 ) Share-based compensation — — — — 4,458 — — — 4,458 Restricted stock vesting — — 232 2 (2 ) — — — — Second Lien warrants and conversion — — 1,430 15 (158 ) (1 ) (7 ) — (150 ) Issuance cost — — — — (37 ) — — — (37 ) Treasury stock activity — — — — (931 ) 1 7 — (924 ) Balance at December 31, 2017 Successor — $ — 10,771 $ 108 $ 68,446 — $ — $ (12,303 ) $ 56,251 20172019 and 20162018 (in thousands): $ 11,461 $ 8,633 14,483 16,665 - 132 404 304 $ 26,348 $ 25,734 December 31, 2017 2016 Trade Payables $ 4,092 $ 2,357 Revenue Payables 10,692 10,943 Prepayments from Partners 2,193 966 Other 227 126 Total Accounts Payable $ 17,204 $ 14,392 20172019 and 20162018 (in thousands): $ 6,175 $ 8,086 989 1,100 430 338 2,258 1,888 4,642 3,420 208 443 1,414 598 499 645 Total Accrued liabilities $ 16,615 $ 16,518 December 31, 2017 2016 Accrued capital expenditures $ 10,511 $ 648 Accrued lease operating expense 786 547 Accrued production and other taxes 449 552 Accrued transportation and gathering 1,130 70 Accrued performance bonus 3,869 — Accrued interest 244 278 Accrued office lease 696 99 Accrued reorganization costs 168 1,235 Accrued general and administrative expense and other 222 453 $ 18,075 $ 3,882 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTSthatthat 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.Transition from Successful Efforts Method to Full Cost Accounting Method--Under US 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 oiloil 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&A”) expense and the assessment of impairment of oil and gas properties.Prior to the Effective Date, we followed the Successful Efforts Method of Accounting for exploration and development expenditures. Under this method, costs of acquiring unproved and proved oil and natural gas leasehold acreage were capitalized. When proved reserves were found on an unproved property, the associated leasehold cost was transferred to proved properties. Significant unproved leases were reviewed periodically, and a valuation allowance was provided for any estimated decline in value. Costs of all other unproved leases were amortized over the estimated average holding period of the leases. Development costs were capitalized, including the costs of unsuccessful development wells. Additionally, oil and gas properties were assessed for impairment in accordance with Accounting Standards Codification 360.Because a new entity was created at the Effective Date, and there is no comparability to the predecessor company financial statements, upon emergence from bankruptcy weWe have elected to adopt the Full Cost Method of Accounting. We believe that the true cost of developing a “portfolio” of reserves should reflect both successful and unsuccessful attemptsat exploration and production. Application of the Full Cost Method of accounting better reflects the true economics of exploring for anddeveloping our oil and gas reserves. Therefore, since the Effective Date, we have used the Full Cost Method to account for our investment in oil and gas properties in the reorganized company.impairment.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 therebytherefore subject to DD&A and the full cost ceiling test. For the yearyears ended December 31, 20172019 and for the period from the Effective Date to December 31, 2016,2018, we transferred $18.8$0.3 million and $2.5$6.0 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.After the Effective Date and under (the “UOP”) 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.Prior to the Effective Date and under the Successful Efforts Method, depreciation and depletion of producing oil and natural gas properties was calculated using the units-of-production method. Proved developed reserves were used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves were used for unamortized leasehold costs.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS2016 resulted in recording a $2.5 million write-down of the oil2019 and gas properties. The Full Cost Ceiling Test performed as of December 31, 20172018 resulted in no write-down of the oil and gas properties.Exploration—Prior to the Effective Date, we followed the Successful Efforts Method of Accounting. Under Successful Efforts Method of Accounting exploration expenditures, including geological and geophysical costs, delay rentals and exploratory dry hole costs were expensed as incurred. Costs of drilling exploratory wells were initially capitalized pending determination of whether proved reserves can be attributed to the discovery. If management determined that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells were expensed.Impairment—Prior to the Effective Date under the Successful Efforts Method of Accounting, we periodically assessed our long-lived assets recorded in oil and natural gas properties on the Consolidated Balance Sheets to ensure that they were not overstated or carried in excess of fair value, which was computed using level 3 inputs such as discounted cash flow models or valuations. Significant level 3 assumptions associated with discounted cash flow models or valuations used in the impairment evaluation included estimates of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. An evaluation was performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicate that our oil and natural gas properties may be impaired.To determine if a field was impaired, we compared the carrying value of the field to the undiscounted future net cash flows by applying management’s estimates of proved reserves, future oil and natural gas prices, future production of oil and natural gas reserves and future operating costs over the economic life of the property. In addition, other factors such as probable and possible reserves were taken into consideration when justified by economic conditions and the availability of capital to develop proved undeveloped reserves. For each property determined to be impaired, we recognized an impairment loss equal to the difference between the estimated fair value and the carrying value of the field.Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depletion, depreciation and amortization to reduce the carrying value of the field. Each part of this calculation is subject to a large degree of judgment, including the determination of the fields’ estimated reserves, future cash flows and fair value.Exit Credit Facilitysenior 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; andGOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS20172019 and 2016,December 31, 2018, 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.when production is sold to a purchaser at a fixed or determinable price, whenupon delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues from the production of crudeour produced oil and natural gas propertiesvolumes to our customers. We record revenue in whichthe 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 have an interest with other producers are recognized usingrequired to estimate the entitlements method. 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. At December 31, 2017 2019 and 2016,2018, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.stockholdersstock for each reporting period by the weighted-average numbershares of common sharesstock outstanding during the period. Diluted net income (loss) per common share is computed by dividing net income (loss) applicable to common stockholdersstock for each reporting period by the weighted average numberweighted-average shares of common sharesstock 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.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS2017,2019and pro forma full year 20162018are as follows: CIMA Energy, LP 39 % 41 % Shell 19 % 0 % 19 % 15 % CES 10 % 8 % 8 % 13 % Year Ended December 31, 2017 2016 (Pro Forma) Genesis Crude Oil LP 20 % 44 % Sunoco, Inc. 13 % 30 % Williams Energy Resources LLC 29 % — % ETC 15 % 4 % Occidental Energy MA 7 % 13 % the December 31, 20172019 Goodrich Petroleum Company LLC,LLC, the wholly owned subsidiary of Goodrich Petroleum Corporation, was the Subsidiary Guarantor of our 13.50% Convertible Second Lien Senior Secured notes due 2019 (the “Convertible Second Lien Notes”)New 2L 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.Convertible Second Lien Notes.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.On August 28, 2017,In December 2019, the FinancialFinancial Accounting Standards Board (“FASB”(“FASB”) issued Accounting Standards Update (“ASU”) 2017-12, Derivatives and Hedging2019-12, Income Taxes (Topic 815)740): Targeted Improvements toSimplifying the Accounting for Hedging Activities. This ASU is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, theIncome Taxes. The amendments in this ASU makeadds new guidance to simplify accounting for income taxes, changes the accounting for certain targetedincome tax transactions and makes minor improvements to simplify the application of the hedge accounting guidance in current GAAP based on the feedback received from preparers, auditors, users, and other stakeholders.codification. For public entities, the amendments in this ASU are effective for annualfiscal periods beginning after December 15, 2018.2020, including interim periods therein. We do not expect this ASU toare evaluating the expected impact these amendments will have a material impact on our consolidated financial statements as we currently mark to market all of our derivative positions;statements; however, we are evaluatingdo not expect a material impact from the impactadoption of this ASU should we choose to utilize hedge accounting in the future.ASU.On May 10, 2017,2017-09, Compensation2018-13, Fair Value Measurements (Topic 820): Disclosure Framework - Stock Compensation (Topic 718): Scope of Modification Accounting. This ASU amends the scope of modification accounting for share-based payment arrangements and provides guidance on the types of changesChanges to the terms or conditionsDisclosure Requirements for Fair Value Measurement. The amendments in this ASU modify the disclosure requirements on fair value measurements in Topic 820 including the removal, modification and addition of share-based payment awards to which an entity would be required to apply modification accounting under ASC 718.certain disclosure requirements. For publicall entities, the amendments in this ASU are effective for annualfiscal periods beginning after December 15, 2017 and should be applied prospectively to an award modified on or after2019, including interim periods therein. We no do anticipate a material impact from the adoption date. We plan to adopt this ASU on January 1, 2018 and believe the provisions of this ASU will be immaterial to our consolidated financial statements.ASU.On November 17, 2016, the FASB issued ASU 2016-18, StatementTable of Cash Flows (Topic 230): Restricted Cash. This ASU is intended to reduce diversity in the presentation of restricted cash and restricted cash equivalents in the statement of cash flows and requires that restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this ASU should be applied using a retrospective transition method to each period presented. For public entities, theContentsamendmentseffectiveprimarily 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 will 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 other joint owner working interests. Our revenues are recorded and presented on our financial statements net of the royalty and other joint owner working interests. Our revenue stream does not include any payments for annualservices or ancillary items other than sale of oil and natural gas.beginning after December 15, 2017.prior to January 1, 2018 were not materially affected or revised. We also do not anticipate this standard will have a material impact on our consolidated financial statements.On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public entities, the amendments are effective for annual periods beginning after December 15, 2016. We adopted this standard in 2017 and recognized associated tax windfalls, which were offset by a valuation allowance on our consolidated balance sheet as of December 31, 2017. We note that there were no other material impacts on our consolidated financial statements as a resulton an ongoing basis. $ 9,961 $ 91,811 $ - $ 101,772 426 16,142 13 16,581 $ 10,387 $ 107,953 $ 13 $ 118,353 $ 14,189 $ 58,911 $ - $ 73,100 556 14,236 51 14,843 $ 14,745 $ 73,147 $ 51 $ 87,943 On February 25, 2016 the FASB issued ASU 2016-02, Leases (Topic 842). The key difference between the existing standards and ASU 2016-02 is the requirement for lessees to recognize on their balance sheet all lease contracts with lease terms greater than 12 months, including operating leases. Specifically, lessees are required to recognize on the balance sheet at lease commencement, both: (i) a right-of-use asset, representing the lessee’s right to use the leased asset over the term of the lease; and, (ii) a lease liability, representing the lessee’s contractual obligation to make lease payments over the term of the lease. For lessees, ASU 2016-02 requires classification of leases as either operating or finance leases, which are similar to the current operating and capital lease classifications. However, the distinction between these two classifications under the ASU does not relate to balance sheet treatment, but relates to treatment and recognition in the statements of income and cash flows. Lessor accounting is largely unchanged from current US GAAP. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The update provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, for public entities. Early application is permitted. We are currently evaluating the provisions of this ASU and assessing the impact it may have on our consolidated financial statements.In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The update was issued to increase stakeholders’ awareness of the proposals for technical corrections and to expedite improvements. These ASUs are effective for annual and interim periods beginning after December 15, 2017. The Company plans to adopt these standards using the full retrospective transition method. The Company analyzed the impact of Update 2014-09, and the related ASU's, to evaluate the impact of the new standard on its revenue contracts and does not expect a material impact to our recording of revenue or consolidated financial statements. The Company is currently preparing to comply with new disclosure requirements beginning in Q1 2018 in accordance with requirements of these standards.NOTE 2—Fresh Start AccountingEmergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy CodeOn April 15, 2016 (the “Petition Date”), we and our subsidiary Goodrich Petroleum Company, L.L.C. (the “Subsidiary”, and together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions” and, the cases commenced thereby, the (“Chapter 11 Cases”) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”), to pursue a Chapter 11 plan of reorganization. The Company filed a motion with the Bankruptcy Court seeking joint administration of the Chapter 11 Cases under the caption In re Goodrich Petroleum Corporation, et al. (Case No. 16-31975). The Debtors received Bankruptcy Court confirmation of their joint plan of reorganization (the “Plan of Organization”) on September 28, 2016 (the “Approval Date”) and subsequently emerged from bankruptcy on October 12, 2016 (the “Effective Date”).During the Chapter 11 Cases, the Company conducted normal business activities and was authorized to continue to pay and has paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders, critical vendors and other third parties, such as royalty holders and partners.During the pendency of the Chapter 11 Cases, we operated our business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. ASC 852-10 applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities, as well as expenses and income directly associated with the Chapter 11 Cases.The Company accounted for the bankruptcy in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, “Reorganizations”. ASC 852 requires that the financial statements, for periods subsequent to the filing of the Bankruptcy Petitions, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, realized gains and losses and provisions for losses that are realized or incurred in the Chapter 11 Cases are recorded in “Reorganization items, net” in the accompanying Consolidated Statements of Operations.While operating as debtors-in-possession under Chapter 11 of the Bankruptcy Code, we could sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in our consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, the Plan of Reorganization materially changed the amounts and classifications in our historical consolidated financial statements.Plan of ReorganizationThe significant features of the Plan of Reorganization confirmed by the Bankruptcy Court are as follows:1.Each holder of an allowed priority claim (other than a priority tax claim or administrative claim) received either: (a) cash equal to the full allowed amount of its claim or (b) such other treatment as may otherwise be agreed to by such holder, the Debtors, the holders of at least 50% in principal amount of the Second Lien Notes (the “Majority Consenting Noteholders”), and the purchasers of the new Convertible Second Lien Notes (“New 2L Notes Purchasers”);2.Each holder of a secured claim (other than a priority tax claim, Senior Credit Facility claim, or Second Lien Notes claim) received, at the Debtors’ election and with the consent of the Majority Consenting Noteholders, either: (a) cash equal to the full allowed amount of its claim, (b) reinstatement of such holder’s claim, (c) the return or abandonment of the collateral securing such claim to such holder, or (d) such other treatment as may otherwise be agreed to by such holder, the Debtors, the Majority Consenting Noteholders, and the New 2L Notes Purchasers;3.The Senior Credit Facility claims were paid cash in an amount sufficient to reduce the Senior Credit Facility claims to a balance of $20.0 million while the remaining $20.0 million owed was to be refinanced into a new senior secured term loan credit facility;GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS4.The Second Lien Notes claims were deemed allowed in the aggregate amount of $175.0 million of principal plus accrued and unpaid interest through the Petition Date. Except to the extent a holder of a Second Lien Note claim agreed in writing to less favorable treatment, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Second Lien Notes claim, each holder of a Second Lien Notes claim received their pro rata share of 98% of the new equity interests in the reorganized company (the “New Equity Interests”), subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million;5.Holders of unsecured notes claims received, pro rata with holders of other general unsecured claims, their pro rata share of the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million; plus its pro rata share of 2% of the New Equity Interests that are subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal of $230.0 million;6.Holders of allowed general unsecured claims had the option to elect on their ballot to (a) receive, pro rata with holders of unsecured notes claims, its pro rata share of the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million; plus its pro rata share of 2% of the New Equity Interests that are subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million, or (b) treat its allowed general unsecured claim as a convenience class claim by releasing any claims in excess of $10,000;7.Holders of convenience class claims received either: (a) cash equal to the full allowed amount of such holder’s claim or (b) such lesser treatment as may otherwise be agreed to by such holder, the Debtors, the Majority Consenting Noteholders and the New 2L Notes Purchasers;8.Equity interests in the Subsidiary were canceled and extinguished without further notice to, approval of, or action by any entity, and each holder of an equity interest in the Subsidiary did not receive any distribution or retain any property on account of such equity interest in the Subsidiary. Equity interests in the Company were canceled and extinguished without further notice to, approval of, or action by any entity, and each holder of an equity interest in the Company did not receive any distribution or retain any property on account of such equity interest in the Company.Our Plan of Reorganization was approved by the Bankruptcy Court on September 28, 2016. Subsequently, we emerged from Chapter 11 bankruptcy on October 12, 2016. Upon our bankruptcy emergence, we were subject to the requirements of FASB ASC 852, “Reorganizations”. This included evaluating our ability to adopt “Fresh Start Accounting” and determining the reorganization value of our post-emergence company.We qualified for the adoption of Fresh-Start Accounting because (1) the holders of existing voting shares of the pre-emergence debtor-in-possession, referred to herein as the “Predecessor” or “Predecessor Company” received less than 50% of the voting shares of the post-emergence successor entity, referred to herein as the “Successor” or “Successor Company”, that were outstanding after our bankruptcy emergence and (2) immediately prior to the approval of our reorganization plan, the reorganization value of the “Predecessor” Company's assets was less than the allowed claims and post-petition liabilities. Our adoption of fresh start reporting resulted in our becoming a new reporting entity for financial reporting purposes, with no beginning retained earnings or deficit. On October 13, 2016, we began to apply fresh start accounting as a new entity. Our post emergence financial statements are therefore presented on this basis. Upon our application of fresh start accounting, we allocated our reorganization value to our individual assets based on their estimated fair values. Reorganization value represents the fair value of the Successor Company's assets before considering liabilities. Application of fresh start accounting and the effects of the implementation of our Plan of Reorganization resulted in our Consolidated Financial Statements on or after October 12, 2016 not being comparable with the Consolidated Financial Statements prior to that date. All references made regarding “Successor” or “Successor Company” relate to the financial position and results of operations of our reorganized entity subsequent to October 12, 2016. References to “Predecessor” or “Predecessor Company” refer to the financial position and results of operations of our entity prior to October 12, 2016.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTSReorganization ValueReorganization value was determined at our emergence date of October 12, 2016. It represents the fair value of the Successor Company's total assets and is intended to approximate the amount a willing buyer would pay for assets immediately after restructuring. We estimated the Successor Company asset value to be approximately $115 million inclusive of the $20 million net cash effect of the proceeds from the 2nd Lien Note. The valuation analysis was prepared with standard valuation techniques, which included a development plan, pricing models and discounting methods, and various other analytics. Information pertaining to reserves, inventory, fixed assets and other financial projections and information were used in the valuation analysis.Proved ReservesThe Company determined the fair value of its proved producing oil and gas properties based upon the discounted cash flows expected to be generated from the properties. The valuation used New York Mercantile Exchange (“NYMEX”) WTI pricing for oil and Henry Hub pricing for natural gas. The after tax cash flows were discounted at 10.2%. This discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. The cash flows were not risked since the properties consisted only proved producing properties.Undeveloped AcreageThe Company owns undeveloped lease acreage in three major shale trends. The acreage is valued on a per acre basis reflecting recent acreage transactions within each trend.Materials InventoryThe Company maintains an inventory of mostly tubular which is valued by market quote.Asset Retirement ObligationThe Company has asset retirement obligations to plug and abandon wells at the end of their life. The company determines the Fair value of the obligation from quotes obtained from vendors for plug and abandonment cost which is escalated using 2.4% inflation factor and discounted using a credit adjusted risk free rate of 7.5%. The fair value is initially recorded as an asset and liability.Tangible Personal and Real PropertyThe company owns furniture, fixtures, computer equipment, software and fee land which is valued using the direct cost approach.Current AssetsThe company valued the current assets at book value due to their short term nature and includes the net cash effect of the 2nd Lien Note proceeds.The following table reconciles the estimated fair value of the Successors Company assets at October 12, 2016 (in thousands):GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS October 12, 2016 Current assets $ 28,216 Oil & gas properties Proved Reserves 37,200 Undeveloped acreage 41,570 Asset Retirement Obligation 2,896 Materials inventory 4,125 Tangible personal & real property 984 Goodwill 9 Total asset value $ 115,000 Balance sheet reclass (current assets) 18,201 Total successor assets $ 96,799 Consolidated Balance SheetThe information and adjustments set forth in the following consolidated balance sheet reflect our recent financial progression, beginning with that of our pre-emergence (Predecessor Company) and concluding with our current entity position (Successor Company). The completion of transactions as provided in our Plan of Reorganization are presented as “Reorganization Adjustments” and the fair value adjustments which resulted from our application of Fresh Start Accounting are specified as being “Fresh Start Adjustments”. The explanatory notes emphasize methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions.The following table reflects the reorganization and application of ASC 852 on our consolidated Balance Sheet as of October 12, 2016 (in thousands):GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS Predecessor Company
October 12,
2016 Reorganization Adjustments Fresh Start Adjustments Successor Company October 13, 2016 ASSETS Current assets: Cash and cash equivalents $ 3,680 $ — $ — $ 3,680 Accounts receivable, trade and other, net of allowance 590 — — 590 Accrued oil and gas revenue 4,207 — — 4,207 Inventory 4,178 — — 4,178 Prepaid expenses and other 1,161 — — 1,161 Total current assets 13,816 — — 13,816 Property and equipment Unevaluated oil & gas properties (Full Cost Method) — — 41,570 (5) 41,570 Evaluated oil & gas properties (Full Cost Method) — — 40,104 (5) 40,104 Oil and gas properties (successful efforts method) 976,021 — (976,021 ) (5) — Furniture, fixtures and equipment 7,302 — (6,318 ) (5) 984 983,323 — (900,665 ) 82,658 Less: Accumulated depletion, depreciation and amortization (919,121 ) 919,121 (5) — Net property and equipment 64,202 — 18,456 82,658 Other 325 — — 325 325 — — 325 Total Assets $ 78,343 $ — $ 18,456 $ 96,799 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable 12,761 — — 12,761 Accrued liabilities 10,368 — — 10,368 Accrued abandonment costs 83 — (83 ) (6) — Current portion of debt 40,393 — — 40,393 Total current liabilities 63,605 — (83 ) 63,522 Long-term debt — — — — Accrued abandonment cost 3,861 — (965 ) (6) 2,896 Liabilities subject to compromise 426,249 (426,249 ) (1) — — Total liabilities 493,715 (426,249 ) (1,048 ) 66,418 Stockholders' equity: Preferred stock, Series E 3 (3 ) (2) — — Preferred stock, Series D 4 (4 ) (2) — — Preferred stock, Series C 3 (3 ) (2) — — Preferred stock, Series B 1,483 (1,483 ) (2) — — Common stock (Predecessor) 15,995 (15,995 ) (2) — — Common stock (Successor) — 68 (3) — 68 Treasury Stock (46 ) 46 (2) — — Additional paid in capital (Predeccessor) 1,100,504 (1,100,504 ) (2) — — Additional paid in capital (Successor) 30,313 (3) — 30,313 Retained earnings (Accumulated deficit) (1,533,318 ) 1,513,814 (4) 19,504 (7) — Accumulated other comprehensive loss — — — — Unamortized restricted stock awards — — — — Total stockholders' equity (deficit) (415,372 ) 426,249 19,504 30,381 Total Liabilities and Stockholders' Equity $ 78,343 $ — $ 18,456 $ 96,799 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS1. Liabilities subject to compromise were settled as follows in accordance with the Plan of Reorganization (in thousands):8.0% Second Lien Senior Secured Notes due 2018 $ 100,000 8.875% Second Lien Senior Secured Notes due 2018 75,000 8.875% Senior Notes due 2019 116,828 3.25% Convertible Senior Notes due 2026 429 5.0% Convertible Senior Notes due 2029 6,692 5.0% Convertible Senior Notes due 2032 99,238 5.0% Convertible Exchange Senior Notes due 2032 6,305 Accrued interest 17,161 Accounts payable and accrued liabilities 4,596 Liabilities Subject to compromise at October 12, 2016 426,249 Fair value of equity in Successor Company 30,381 Gain on settlement of Liabilities subject to compromise $ 395,868 2.Reflects the cancellation of the Predecessor Company Preferred and Common Stock and associated Additional Paid in Capital.3.Reflects the issuance of 5.8 million shares of common stock to the Second Lien Noteholders, 0.1 million shares of common stock to the unsecured debt holders, and an issued 1.0 million common shares under the Management Incentive Plan. Additionally, the unsecured debt holders were issued warrants to purchase 1.3 million shares of common stock valued at $2.5 million.4. Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):Gain on settlement of Liabilities subject to compromise $ 395,868 Cancellation of Predecessor Company equity (1,513,814 ) Net impact to accumulated deficit $ (1,117,946 ) 5. The following table summarizes the fair value adjustment on our oil and gas properties and accumulated depletion, depreciation and amortization (in thousands): Predecessor
Company
October 12
2016 Fresh Start Adjustments Successor Company October 13, 2016 Oil and Gas Properties Oil & gas properties (successful efforts method) $ 868,703 $ (868,703 ) $ — Unproved properties (successful efforts method) 107,318 (107,318 ) — Proved properties (Full Cost Method) — 40,104 40,104 Unproved properties ( Full Cost Method) — 41,570 41,570 Total Oil and Gas Properties 976,021 (894,347 ) 81,674 Less: Accumulated depletion and impairments (912,252 ) 912,252 — Net Oil and Gas Properties 63,769 17,905 81,674 Furniture, Fixtures and other equipment 7,302 (6,318 ) 984 Less: Accumulated depreciation (6,869 ) 6,869 — Net Furniture, Fixtures and other equipment 433 551 984 Net Oil and Gas Properties, Furniture, and fixtures and accumulated depreciation $ 64,202 $ 18,456 $ 82,658 6. Reflects the adjustment of Asset Retirement Obligation to fair value at the effective date.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS7.Reorganization Items represent items directly related to the Chapter 11 bankruptcy filing and implementation of the Plan of Reorganization and are classified as Gain on reorganization, net in the Consolidated Statement of Operations. The following table summarizes the reorganization items (in thousands): Successor Predecessor Period from October 13, 2016 through
December 31, 2016 Period from January 1, 2016 through
October 12, 2016Gain on settlement of liabilities subject to compromise $ — $ (395,868 ) Gain on Fresh start adjustments — (19,504 ) Professional fees and adjustments to debt (130 ) 15,950 Gain on Reorganization items, net $ (130 ) $ (399,422 ) GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS20172019 and 2016,December 31, 2018, which is the 2016 Long Term Incentive Plan, discussed further below. We emerged from bankruptcy on the Effective Date, at which time we also canceled our 2006 Long Term Incentive Plan, as amended in 2015. The 2006 Long Term Incentive Plan provided for grants to officers, employees and non-employee directors of compensation in the form of restricted stock and options. Upon cancellation of the 2006 Long Term Incentive Plan, no awarded options were outstanding, while 2.2 million non-vested restricted stock awards remained outstanding with a related $2.8 million in unamortized expense. All outstanding awards were canceled with the unamortized expense recorded to Gain on reorganization items, net on the Predecessor period Consolidated Statements of Operations. (Successor Company)The Confirmation Order related to our Chapter 11 Reorganization Plan approved the (the “MIP”) which provides for awards of restricted stock, options, performance awards, phantom shares and stock appreciation rights to directors, officers, employees, and consultants. The LTIP initially provided for the issuance of 1.0 million shares, which were all granted on October 12, 2016 as restricted stock units (“RSU's”) at a grant date fair value of $4.05 and vest over 3 years. In December 2016, our Board of Directors approved an additional 1.0 million shares under our LTIP. In December 2016, 0.9 million RSU's, with a grant date fair value of $12.00, were awarded which vest over a service period of up to 3 years, except for grants to Directors which vested in 12 months.In May 2017, an additional 1.5 million shares under the LTIP were approved by our shareholders. During 2017, 0.5 million RSU's were granted which will vest over a service period of up to 3 years, except for grants to Directors which vest in 12 months. Additionally, 0.4 million performance stock units (“PSU's”) were granted in December 2017 which will cliff vest at the end of 3 years. The Company had 0.2 million shares under the LTIP approved and available for future issuance as of December 31, 2017, assuming that the PSU's awarded will vest at the maximum payout of 250%.2016 Long Term Incentive PlanLTIP 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.Performance Share Awards December 2017,2019, the Company granted 402,679 market-basedapproximately (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 awards (the PSU's).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 will generally cliff vest in 12 months following the date of grant, subject to continued service. In 2018, there were no material issuances of RSUs granted to employees and the only issuances to employees under the LTIP were 201,969 shares of common stock issued in settlement for performance bonuses earned in 2017. In December 2018, 45,160 RSUs were granted to non-employee directors which vested in 12 months following the date of grant. As of December 31, 2019, the Company had no further shares available for future issuance under the LTIP, assuming that the PSUs awarded in 2017 and 2019 will vest at the maximum payouts of 250% and 200%, respectively.performancePSU awards have a service period of 3 years and contain predetermined market conditions established by the Compensation Committee, and, if the market and service conditions are met, will cliff vest 3 yearsafter a three-year performance period from the date of grant. The actual number of sharesshares to be earned and that will cliff vest is subject to a market condition, which is based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by the Russell 2000 Energy Index at the end of the performance period as well as company stock price performance. The range of shares of common stock shares which may be earned by an award recipient ranges from zero to 250%200% of the initial performance unitsPSUs granted. The grant date fair value of the PSU'sPSUs was determined using a Monte Carlo simulation model. The assumptions used in the Monte Carlo simulation model are described below:Volatility factor - The volatility factor represents the extent to which the market price59Dividend yield - The dividend yield on the Company's common stock is assumed to be zero since the Company does not currently pay dividends and does not anticipate paying dividends in the future.Risk-free interest rate - The risk-free interest rate is based upon the yield of US Treasuries with a three year term.Expected term - The expected term represents the period of time that the PSU's will be outstanding, which is the grant date to the end of the performance period, or three years.$15.29,$10.43, which was based on the following assumptions: 2019 250,000 $ 10.43 49.3 % — 2 % 2017 Number of simulations 100,000 Grant date price $ 9.82 Volatility factor 57 % Dividend yield — Risk-free interest rate 1.92 % Expected term (in years) 3 PSU'sPSUs granted in 2019 of $6.2$2.1 million will beis amortized on a straight-line basis and recognized as share-based compensation expense, net of amounts capitalized, over the requisite service period of 3 years. All compensation cost related to the PSU'sPSUs will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. As of December 31, 2017,2019, unrecognized compensation costs related to the 402,679 unvested PSU'sPSUs granted in 2019 was $6.1$2.1 million and will be recognized as share-based compensation expense, net of amounts capitalized, over a weighted-average period of 2.962.95 years.2016 Long Term Incentive Plan,LTIP, recognized as a component of general and administrative expenses in the Consolidated Statements of Operations (in thousands), for the years ended December 31, 20172019 and 2016: $ 4,521 $ 4,702 1,952 1,893 664 595 $ 7,137 $ 7,190 Capitalized and lease operating expense share-based compensation (835 ) (747 ) Net share-based compensation - general and administrative expense $ 6,302 $ 6,443 Year Ended December 31, 2016 Long Term Incentive Plan 2017 2016 RSU expense - employees $ 3,636 $ 187 PSU expense 84 — RSU expense - directors 738 53 Total share-based compensation: $ 4,458 $ 240 RSU'sPSU'sPSUs awarded under the LTIP typicallygenerally have a vesting period ofbetween one to three years. During the vesting period, ownership of RSU'sRSUs and PSU'sPSUs 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 RSU'sRSUs and PSU'sPSUs provide for accelerated vesting. Restricted shares issued subsequent to October 12, 2016vesting in certain limited circumstances. RSUs and PSUs are not considered to be currently issued and outstanding until the restrictions lapse and/or they vest.Restricted stockyearyears ended December 31, 20172019 and for the period from October 12, 2016 to December 31, 20162018 are as follows: 1,171,353 402,679 1,574,032 $ 9.91 $ 15.29 $ 11.29 $ 11,647 $ 6,157 $ 17,804 249,751 - 249,751 11.54 - 11.54 2,882 - 2,882 (742,607 ) - (742,607 ) 10.20 - 10.20 (9,681 ) - (9,681 ) (17,360 ) (3,291 ) (20,651 ) 11.25 15.29 11.90 (195 ) (50 ) (245 ) 661,137 399,388 1,060,525 10.16 15.29 12.09 4,653 6,107 10,760 294,871 204,755 499,626 9.96 10.43 10.16 2,938 2,136 5,074 (530,446 ) - (530,446 ) 10.18 - 10.18 (5,138 ) - (5,138 ) (9,032 ) - (9,032 ) 13.84 - 13.84 (125 ) - (125 ) 416,530 604,143 1,020,673 $ 9.92 $ 13.64 $ 12.12 $ 2,328 $ 8,243 $ 10,571 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS2016 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 October 12, 2016 — — — $ — $ — $ — $ — $ — $ — Granted 1,859,570 — 1,859,570 7.72 — 7.72 14,365 — 14,365 Vested (726,904 ) — (726,904 ) 4.05 — 4.05 (2,944 ) — (2,944 ) Forfeited — — — — — — — — — Unvested at December 31, 2016 1,132,666 — 1,132,666 $ 10.08 $ — $ 10.08 $ 11,421 $ — $ 11,421 Granted 476,054 402,679 878,733 9.93 15.29 12.38 4,726 6,157 10,882 Vested (413,436 ) — (413,436 ) 10.28 — 10.28 (4,213 ) — (4,213 ) Forfeited (23,931 ) — (23,931 ) 12.00 — 12.00 (287 ) — (287 ) Unvested at December 31, 2017 1,171,353 402,679 1,574,032 $ 9.91 $ 15.29 $ 11.29 $ 11,646 $ 6,157 $ 17,803 20172019 and 2016,2018, total unrecognized compensation cost and weighted average years to recognition related to RSU'sRSUs and PSU'sPSUs under the LTIP are as follows: $ 3,969 $ 4,283 $ 8,252 1.95 1.93 1.94 $ 6,340 $ 4,100 $ 10,440 1.35 1.96 1.59 2016 Long Term Incentive Plan Unrecognized compensation costs Weighted Average years to recognition (thousands) (years) RSU PSU Total RSU PSU Total December 31, 2017 $ 11,248 $ 6,070 $ 17,318 2.23 2.96 2.47 December 31, 2016 11,181 — 11,181 2.77 — 2.77 2006 Long Term Incentive Plan (Predecessor Company)Upon our emergence from bankruptcy on the Effective Date, the 2006 Long Term Incentive Plan was canceled.The following tables summarizes the components of our share-based compensation programs recorded under the 2006 Long Term Incentive Plan, which was recognized as a component of general and administrative expenses in the Consolidated Statements of Operations (in thousands) for the period January 1, 2016 through the Effective Date: 2006 Long Term Incentive Plan 2016 Restricted stock expense $ 3,307 Stock option expense — Director stock expense — Total share-based compensation: $ 3,307 $ 3,791 $ 3,367 224 303 63 47 (4 ) (13 ) 297 262 (202 ) (175 ) $ 4,169 $ 3,791 $ - $ - $ 4,169 $ 3,791 Successor Successor Predecessor Year Ended December 31, 2017 October 13, 2016 to December 31, 2016 January 1, 2016 to October 12, 2016 Beginning balance $ 2,933 $ 2,897 $ 3,728 Liabilities incurred 132 — — Revisions in estimated liabilities (1) 71 — — Liabilities settled — — — Accretion expense 231 36 216 Dispositions — — — Ending balance $ 3,367 $ 2,933 $ 3,944 Current liability $ — $ — $ 83 Long term liability $ 3,367 $ 2,933 $ 3,861 EstimatedChanges in estimated costs and timing of plugging and abandoning increased givinggave rise to the revision in estimated liabilities. 2017 Senior Credit Facility (1) $ - $ - $ - $ 27,000 $ 27,000 $ 27,000 92,900 92,900 92,900 - - - Convertible Second Lien Notes (2) - - - 53,691 49,820 60,857 12,969 11,535 12,952 - - - $ 105,869 $ 104,435 $ 105,852 $ 80,691 $ 76,820 $ 87,857 December 31, 2017 December 31, 2016 Principal Carrying
Amount Fair
Value Principal Carrying
Amount (5) Fair
Value (1)Exit Credit Facility (1) $ — $ — $ — $ 16,651 $ 16,651 $ 16,651 2017 Senior Credit Facility (1) 16,723 16,723 16,723 — — — Convertible Second Lien Notes (2) 47,015 39,002 62,026 41,170 30,554 29,036 Total debt $ 63,738 $ 55,725 $ 78,749 $ 57,821 $ 47,205 $ 45,687 (1)Exit Credit and 2017 Senior Credit Facility representsand the 2019 Senior Credit Facility represent fair value as it wasthey were fully secured.(2)(3)The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019.May 31, 2021. The principal includes $1.2 millionpaid-in-kind interest of paid-in-kind (PIK) interest as of December 31, 2016 and $7.0$1.0 million as of December 31, 2017.2019. The carrying value includes $10.6 million and $8.0$1.1 million of unamortized debt discount and $0.3 million of unamortized issuance cost at December 31, 2016 and 2017, respectively.2019. The fair value of the notesNew 2L Notes, a Level 2 fair value estimate, was obtained by using a Binomial Lattice Model within Level 3 of the fair value hierarchy for the value on December 31, 2016 and utilized the last known sale price for the value on December 31, 2017.2019. 2017 Senior Credit Facility $ 872 7.2 % $ 1,130 8.9 % 3,409 6.0 % - - 5,304 24.1 % 10,814 23.9 % New 2L Notes (2) 1,416 21.6 % - - $ 11,001 $ 11,944 (1) The Convertible 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) and 23.9% for the year ended December 31, 2018. 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. Interest expense for the year ended December 31, 2018 included $4.1 million of debt discount amortization and $6.7 million of paid-in-kind interest. (2) The New 2L 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 21.6% for the year ended December 31, 2019. Interest expense for the year ended December 31, 2019 included $0.3 million of debt discount amortization and $1.0 million of accrued interest to be paid in-kind. Successor Successor Predecessor Year Ended December 31, 2017 Period from October 12, 2016 through December 31, 2016 Period from January 1, 2016 through October 12, 2016 $ — — % $ — — % $ 3,342 * Exit Credit Facility 947 7.1 % 306 7.3 % — — % 2017 Senior Credit Facility 244 7.2 % — — % — — % 8,534 24.1 % 1,518 24.7 % — — % Obligations Canceled on the Effective Date — — % — — % 8,010 * Other — — % — — % 46 * Total $ 9,725 $ 1,824 $ 11,398 * - Not comparative as the Company was in bankruptcy during portions of the 2016 periods shown and did not pay interest on its debt while in bankruptcy.(1) Interest expense for the year ended December 31, 2017 includes $2.6 million of debt discount amortization and $5.8 million of paid in-kind interest.The Chapter 11 Cases constituted an event of default that accelerated the Company’s obligations under all of its outstanding debt instruments. The agreements governing the Company’s debt instruments provided that as a result of the Bankruptcy Petitions, the principal and interest due thereunder was immediately due and payable. However, any efforts to enforce such payment obligations under the Company’s debt instruments were automatically stayed as a result of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments were subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. On the Effective Date, upon the Company’s emergence from bankruptcy, the Second Lien Notes were exchanged for 98% of the common stock of the reorganized Company and the unsecured senior notes along with certain other unsecured claims were exchanged for 2% of the common stock of the reorganized company. The $40.4 million amount outstanding amounts under the Senior Credit Facility was paid down to $20.0 million with proceeds from the sale of the Convertible Second Lien Notes and cash on hand at closing.Senior Credit FacilityAs of the Effective Date, we had $40.4 million outstanding under the Senior Credit Facility inclusive of the accrued default penalty. Following the reduction of the borrowing base to $20.0 million after the April 1, 2016 borrowing base redetermination, the Company had a borrowing base deficiency of $20.2 million. Pursuant to the terms of a cash collateral order entered in the bankruptcy proceeding on the Petition Date, interest was accrued and paid monthly based on a 2.25% margin which calculated to 5.75% per annum. Additionally, a post-default rate of 2.00% is accreted on the outstanding balance. Substantially all of our assets were pledged as collateral to secure the Senior Credit Facility. The Senior Credit Facility had a maturity date of February 24, 2017.The commencement of the Chapter 11 Cases on the Petition Date constituted an event of default that accelerated the Company’s obligations under the Senior Credit Facility. On the Effective Date, in connection with the consummation of the Plan of Reorganization, the Senior Credit Facility was terminated.Exit Credit FacilityOn the Effective Date, upon consummation of the Plan of Reorganization, the Company entered into an Exit Credit Agreement (the “Exit Credit Agreement”) with the Subsidiary, as borrower (the “Borrower”), and Wells Fargo Bank, National Association, as administrative agent (“the Administrative Agent”), and certain other lenders party thereto. Pursuant to the Exit Credit Agreement, the lenders party thereto provided the Borrower with a $20.0 million senior secured term loan credit facility. Amounts outstanding under the Exit Credit Agreement were guaranteed by the Company and secured by a security interest in substantially all of the assets of the Company and the Borrower.The maturity date of the Exit Credit Agreement was September 30, 2018, unless the Borrower notified the Administrative Agent that it intended to extend the maturity date to September 30, 2019, subject to certain conditions and the payment of a fee.Until such maturity date, the Loans (as defined in the Exit Credit Agreement) under the Exit Credit Agreement beared interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 4.50% or (ii) adjusted LIBOR plus an applicable margin of 5.50%. As of the payoff of the Exit Credit Facility on October 17, 2017, the interest rate on the Exit Credit Facility was 8.75%.The Borrower could have elected, at its option, to prepay any borrowing outstanding under the Exit Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Exit Credit Agreement).On October 17, 2017, the Exit Credit Facility was paid off in full and replaced with a $250.0 million senior secured revolving facility (“2017 Senior Credit Facility”) with an initial borrowing base of $40.0 million with $16.7 million outstanding.JP MorganJPMorgan Chase Bank, N.A., as administrative agent, and certain lenders that are party thereto, which providesprovided for revolving loans of up to the borrowing base then in effect (the(as amended, the “2017 Senior Credit Facility”). The 2017 Senior Credit Facility amends, restates and refinances the obligations under the Exit Credit Facility. The 2017 Senior Credit Facility matureswas set to mature on (a) October 17, 2021 or (b) December 30, 2019, if the Convertible Second Lien Notes (as defined below) havehad not been voluntarily redeemed, repurchased, refinanced or otherwise retired by September 30, 2019, SeptemberDecember 30, 2019. The maximum credit amount under the 2017 Senior Credit Facility is currentlywhen it was paid off in full on May 14, 2019 was $250.0 million with an initiala borrowing base of $40.0$75.0 million. The borrowing base is scheduled to be redetermined in March and September of each calendar year, commencing on or about March 1, 2018, 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 Subsidiary 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 in their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the 2017 SeniorGOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTSCredit Facility in an aggregate amount up to $10.0 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.shall bearbore 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.2.75%2.50% to 3.75%3.50%, depending on the percentage of the borrowing base that is utilized. Undrawn amounts under the 20172019 Senior Credit Facility are subject to a 0.50% commitment fee.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 20172019 Senior Credit Facility will bear interest at 2.00%2.0% per annum above the rate and margin otherwise applicable thereto. As of December 31, 2017,2019, the weighted average interest rate on the 2017borrowings from the 2019 Senior Credit Facility was 6.50%5.039%.2017obligations 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.(i) the maintenance of (i) a ratio of TotalNet Funded Debt (as defined in the 2017 Senior Credit Facility) to EBITDAX not to exceed 4.00 to 1.00 as of the last day of any fiscal quarter, (ii) the maintenance of a current ratio (based on the ratio of current assets to current liabilities)liabilities as defined in the 2019 Credit Agreement) not to be less than 1.00 to 1.00 and (iii) until no Convertible Second LienNew 2L Notes remain outstanding, (A) the maintenance of a ratio of Total Proved PV10%PV-10 attributable to the Company’s and Borrower’s Proved Reserves (as defined in the 2017 Senior Credit Facility) to Total Secured Debt (net of any Unrestricted Cash not to exceed $10.0$10 million) not to be less than 1.50 to 1.00 (B) limitations on cash general and administrative expenses through 2017 of $10.1 million and (C) minimum liquidity requirements.The On May 14, 2019, the Company utilized borrowings under the 2019 Senior Credit Facility to refinance its obligations under the 2017 Senior Credit Facility are secured by a first lien security interest in substantially alland to fund the Redemption (as defined below) of the assets of the Company.2017,2019, the Company had a borrowing base of $40.0$125.0 million with $16.7$92.9 million of borrowings outstanding. The CompanyCompany also had $0.6$2.2 million of unamortizedunamortized debt issuance costs recorded as of December 31, 20172019 related to the 20172019 Senior Credit Facility.2017, we were2019, the Company was in compliance with all covenants within the 20172019 Senior Credit Facility.13.50% Senior Secured Notes Due 2019On the Effective Date,and the Subsidiary, entered into a purchase agreement (the “Purchase Agreement”) with each entity identified as a Shenkman Purchaser on Appendix A to the Purchase Agreement (collectively, the “Shenkman Purchasers”), CVC Capital Partners (acting through such of its affiliates to managed funds as it deems appropriate), J.P. Morgan Securities LLC (acting through such of its affiliates or managed funds as it deems appropriate), Franklin Advisers, Inc. (as investment manager on behalf of certain funds and accounts), O’Connor Global Multi-Strategy Alpha Master Limited and Nineteen 77 Global Multi-Strategy Alpha (Levered) Master Limited (collectively, and together with each of their successors and assigns, the “Purchasers”), in connection with the issuance ofissued $40.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2019 (the “Convertible Second Lien Notes”).The aggregate principal amount of the Convertible Second Lien Notes is convertible at the option of the Purchasers at any time prior to the scheduled maturity date at $21.33 per share, subject to adjustments. At closing, the Purchasers were issued along with 10-year costless warrants equal to acquire 2.5 million shares of common stock. Holders of the Convertible Second Lien Notes havehad a second priority lien on all assets of the Company, and haveholders of such warrants had a continuing right to appoint two members to our Board of Directors (the “Board”) as long as the Convertible Second Lien Notes aresuch warrants were outstanding.willwere scheduled to mature on August 30, 2019 or such later date as set forth insix months after the Convertible Second Lien Notes,maturity of our current revolving credit facility but in no event later than March 30, 2020. The Convertible Second Lien Notes bearbore 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 electalso had the option under certain circumstances to pay all or any portion of interest in kindin-kind on the then outstanding principal amount of the Convertible Second Lien Notes by increasing the principal amount of the outstanding Convertible Second Lien Notes or by issuing additional Second Lien Notes (“PIK Interest Notes”). The PIK Interest Notes are not convertible. During such time as the Exit Credit Agreement (but not any refinancing or replacement thereof) is in effect, interest on the Convertible Second Lien Notes must be paid in-kind; provided however, that after the quarter ending March 31, 2018, if (i) there is no default, event of default or borrowing base deficiency that has occurred and is continuing, (ii) the ratio of total debt to EBITDAX as defined under the 2017 Senior Credit Facility is less than 1.75 to 1.0 and (iii) the unused borrowing base is at least 25%, then the Company can pay the interest on the Convertible Second Lien Notes in cash, at its election.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe Indenture governing the Second Lien Notes 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 sale of assets and stock; business activities; transactions with affiliates; and changes of control.The Indenture also contains certain financial covenants, including the maintenance of (i) a Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.35 to 1.00 for any test date on or before September 30, 2017 and 1.50 to 1.00 after September 31, 2017, to be determined as of January 1 and July 1 of each year; (ii) limitations on cash general and administrative expenses through 2017 of $10.1 million and (iii) minimum liquidity requirements.iswas amortized using the effective interest rate method based upon an original term through August 30, 2019. $8.0The Convertible 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 Convertible 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.remainsand $0.3 million of debt issuance costs remained to be amortized on the Convertible Second Lien Notes asNew 2L Notes.2017.As of December 31, 2017, we were2019, the Company was in compliance with all covenants within the Indenture that governs the Second Lien Notes.New 2L Notes Indenture.Obligations Canceled on the Effective DateThe following represents indebtedness for which, on the Effective Date, the obligationsTable of the Company were canceled and have received or have the right to receive common stock of the reorganized company pursuant to the Plan of Reorganization:8.0% Second Lien Senior Secured Notes due 2018 in the principal amount of $100.0 millionContents8.875% Second Lien Senior Secured Notes due 2018 in the principal amount of $75.0 million8.875% Senior Notes due 2019 in the principal amount of $116.8 million5.0% Convertible Senior Notes due 2029 in the principal amount of $6.7 million5.0% Convertible Senior Notes due 2032 in the principal amount of $94.2 million5.0% Convertible Senior Exchange Notes due 2032 in the principal amount of $6.3 million3.25% Convertible Senior Notes Due 2026 in the principal amount of $0.4 millionLossNet Income (Loss) Per Common ShareUpon the our emergence from bankruptcy on the Effective Date, as discussed in Note 2, the Predecessor company outstanding common and preferred stock was canceled. New common stock and warrants were then issued.lossnet 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 lossnet income (loss) per common share: Year Ended December 31, 2019 Year Ended December 31, 2018 $ 13,288 $ 1,750 12,233 11,622 $ 1.09 $ 0.15 $ 13,288 $ 1,750 12,233 11,622 - 150 1,314 1,418 348 475 13,895 13,665 $ 0.96 $ 0.13 608 1,875 Successor Successor Predecessor Year Ended December 31, 2017 Period from October 13, 2016 through December 31, 2016 Period from January 1, 2016 through October 12, 2016 (Amounts in thousands, except per share data) Basic and Diluted loss per share: Net loss applicable to common stock $ (7,996 ) $ (4,307 ) $ 358,707 Weighted-average shares of common stock outstanding 9,975 7,184 77,236 Basic income (loss) per share $ (0.80 ) $ (0.60 ) $ 4.64 Diluted income (loss) per share Net income (loss) applicable to common stock $ (7,996 ) $ (4,307 ) $ 358,707 Dividends on convertible preferred stock — — 2,990 Interest, discount, accretion and amortization of loan cost on 5% 2029 senior convertible notes, net of tax — — 63 Interest, discount, accretion and amortization of loan cost on 5% 2032 senior convertible notes, net of tax — — 1,548 Interest, discount, accretion and amortization of loan cost on 5% 2032 Exchange Notes due 2032, net of tax — — 28 Interest, discount, accretion and amortization of loan cost on 3.25% senior convertible notes, net of tax — — 3 Diluted net income (loss) $ (7,996 ) $ (4,307 ) $ 363,339 Weighted-average shares of common stock outstanding 9,975 7,184 77,236 Common shares issuable upon assumed conversion of convertible preferred stock or dividends paid. — — 14,966 Common shares issuable upon assumed conversion of the 2026 Notes, 2029 Notes, 2032 Notes and 2032 Exchange Notes or interest paid. — — 5,911 Common shares issuable on assumed conversion of restricted stock, stock warrants and employee stock options were not included in the computation of diluted loss per common share. — — 256 Weighted-average diluted shares outstanding 9,975 7,184 98,369 Diluted income (loss) per share (1) (2) (3) (4) $ (0.80 ) $ (0.60 ) $ 3.69 (1) Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. 1,875 1,875 — (2) Common shares issuable upon conversion of the Convertible Second Lien Notes associated warrants and unsecured claim holders were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. 2,459 3,789 — (3) Common shares issuable on assumed conversion of restricted stock were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. 243 24 — Year Ended December 31, 2019 Year Ended December 31, 2018 $ (393 ) $ (208 ) - - (393 ) (208 ) 393 151 - - 393 151 $ - $ (57 ) Successor Successor Predecessor Year Ended December 31, 2017 October 13, 2016
to December 31,
2016 January 1, 2016
to October 12,
2016Current tax expense (benefit) Federal $ (41 ) $ — $ — State — — — Total current tax expense (benefit) (41 ) — — Deferred tax expense (benefit) Federal (937 ) — — State — — — Total deferred tax expense (benefit) (937 ) — — Total tax expense (benefit) $ (978 ) $ — $ — 35%21% to our lossincome before income taxes (in thousands): Year Ended December 31, 2019 Year Ended December 31, 2018 $ 2,790 $ 356 Disallowed executive compensation 821 841 (5,499 ) (2,530 ) 718 1,194 1,170 82 $ - $ (57 ) Successor Successor Predecessor Year Ended December 31, 2017 October 13, 2016
to December 31,
2016 January 1, 2016
to October 12,
2016Income tax expense (benefit) Tax at U.S. statutory income tax $ (3,141 ) $ (1,508 ) $ 129,481 Book restructuring gain — — (146,770 ) Remeasurement due to Tax Cuts and Jobs Act 41,175 — — Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act (42,112 ) — — Other valuation allowance 5,474 1,055 (5,003 ) State income taxes-net of federal benefit (861 ) (111 ) 16,985 Nondeductible expenses and other (1,513 ) 564 5,307 Total income tax expense (benefit) $ (978 ) $ — $ — 20172019 and 2016:2018: $ 45,280 $ 38,958 11,611 10,278 - 4,221 393 786 1,461 1,426 378 784 465 - - 54 16,813 28,530 76,401 85,037 (74,150 ) (84,181 ) 2,251 856 (1,214 ) (70 ) Right of use asset (350 ) Other (97 ) Debt discount (197 ) - (1,858 ) (70 ) $ 393 $ 786 December 31, 2017 2016 Non-current deferred tax assets: Operating loss carry-forwards $ 27,136 $ 3,033 State Tax NOL and Credits 8,060 1,320 Statutory depletion carry-forward 4,221 7,035 AMT tax credit carry-forward 1,008 1,052 Compensation 1,170 244 Contingent liabilities and other 298 508 Derivative financial instruments — — Debt discount 173 — Property and equipment 45,809 112,274 Total gross noncurrent deferred tax assets 87,875 125,466 Less valuation allowance (86,711 ) (125,164 ) Net noncurrent deferred tax assets 1,164 302 Noncurrent deferred tax liabilities: Bond discount — (302 ) Derivatives (227 ) — Total non-current deferred tax liabilities (227 ) (302 ) Net non-current deferred tax asset $ 937 $ — On December 22, 2017, the United States enacted tax reform legislation known as the H.R.1, commonly referred to as the “Tax Cuts and Jobs Act” (the “Act”), resulting in significant modifications to existing law. Company has completed the accounting for the effects of the Act during 2017. Our financial statements for the year ended December 31, 2017 reflect certain effects of the Act which includes a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018, as well as other changes. Due to the Company’s valuation allowance positionfor deferred tax assets decreased by $10.0 million to $74.2 million in 2019. The valuation allowance decreased by $5.5 million related to current year activity. Additionally, we determined that $4.5 million of our deferred tax asset, which carried a full valuation allowance, would never be recognized and as a resulttherefore, we reduced both the deferred tax asset and the related valuation allowance for this in 2019. In determining the carrying value of changes to tax laws and rates under the Act, the Company recorded a net $1.0 million tax benefit due primarily to the remeasurement ofour deferred tax assets and liabilities, from 35% to 21% and the removal of the valuation allowance on the estimated refundable Alternative Minimum Tax (“AMT”) credits. The valuation allowance decreased by $42.1 million in 2017 due to the changes to tax laws and rates under the Act and increased by $5.5 million for normal operations.The Company follows the guidance in SEC Staff Accounting Bulletin 118 (“SAB 118”), which provides additional clarification regarding the application of ASC Topic 740 in situations where the Company does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Act for the reporting period in which the Act was enacted. SAB 118 provides for a measurement period beginning in the reporting period that includes the Act’s enactment date and ending when the Company has obtained, prepared, and analyzed the information needed in order to complete the accounting requirements but in no circumstances should the measurement period extend beyond one year from the enactment date. We have calculated the impact of the Act in our year end income tax provision in accordance with our understanding of the Act and guidance available as of the date of this filing. We will continue to gather and evaluate the income tax impact of the Act. The ultimate impact of the Act on our reported results in 2018 and beyond may differ, possibly materially, due to, among other things, changes in interpretations and assumptions we have made, guidance that may be issued, and other actions we may take as a result of the Act.We have recorded a valuation allowance of $86.7 million at December 31, 2017, which resulted in a net non-current deferred tax asset of $0.9 million appearing on our statement of financial position. We recorded this valuation allowance at this date after an evaluation ofevaluated all available evidence (including commodity prices and our recent history of tax net operating losses in 20172018 and prior years) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets and liabilities were unrecoverable. The carrying value of our deferred tax asset of $0.4 million represents the remaining Alternative Minimum Tax (“AMT”) credits that are expected to be monetized. The tax benefit recorded for 2017 is2018 was due to adjustment of the AMT credits that arewere expected to be recognized by the Company which have been reduced foras sequestration was removed from the anticipated sequestration.estimate. AMT credits were partially monetized in 2016.2016 through 2018 with the Company receiving $0.4 million in 2019. The remaining $0.9$0.4 million of AMT credits which is less anticipated sequestration, are expected to be fully refundable in tax years 20182019 - 2021 regardless of the Company's regular tax liability as a result of the repeal of the Corporate AMT under the Tax Cuts and Jobs Act. The Company no longer has a valuation recorded against our estimate of refundable AMT credits.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS2017,2019, we have federal net operating loss carry-forwards of approximately $759.9 million which have been reduced for the realized cancellation of indebtedness income (“CODI”) of $353.7 million resulting from the Chapter 11 Cases.$846.6 million. These carryforwardscarry-forwards are subject to limitation by IRC Section 382 and it is estimated $129.2$215.6 million will be available to offset future U.S taxable income.the Chapter 11 Cases was consideredbankruptcy 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 as of the Effective Date.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 will be subject to limitation due to the ownership change. The Company estimates state net operating losses (“NOLs”)NOLs available for use of $63.3$77.0 million in Louisiana and $83.5$151.5 million in Mississippi after the reduction for unusable NOLs due to the ownership change.2017.2019. 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 2010.2017.20172019 there were 10,770,96212,532,550 shares of our Company common stock outstanding and 75,000,000 shares authorized at $0.01 par value per share.On the Effective Date, in connection with our emergence from bankruptcy and according to the Plan of Reorganization, all existing shares of the Predecessor Company's common stock were canceled and the holders did not receive a distribution or retain any property in the reorganized company.The Successor Company then issued a) 5,757,500 shares of the Company's new common stock par value $0.01, pro rata, to the Predecessor Company's former second lien note holders; b) 1,000,002 shares, awarded under the 2016 Long Term Incentive Plan, of which 455,163 were vested immediately, 271,741 were vested immediately but restricted, and 273,098 which vest over three years (91,028 of which vested in 2017); and c) 117,500 shares of common stock, pro rata, to the Predecessor Company's former unsecured note holders and former holders of general unsecured claims; of which 78,597 shares has been issued as of December 31, 2017. In addition to the 6,875,002 shares of common stock issued on the Effective Date discussed above, 1,000,000 warrants were issued pro rata, to the Predecessor Company's former unsecured note holders and holders of general unsecured claims of which 668,926 are outstanding.On the Effective Date, the Successor Company issued 2,499,999 warrants pro rata to the purchasers of the Convertible Second Lien Notes. We valued the warrants and convert feature in the notes separately using a Binomial Lattice Model. The warrants and the conversion feature were valued at $10.2 million and $0.8 million respectively. We recorded the combined $11.0 million value of the warrants and conversion feature in additional paid-in capital and reduced the carry amount of the notes as debt discount. The debt discount is being amortized through August 30, 2019, the maturity date of the notes.2017, certain holders2019, the final 150,000 of the 10 years10-year costless warrants associated with the Convertible Second Lien Notes discussedwere 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 paragraph above,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 were retired prior to December 31, 2019.1,429,687920,312 warrants for the issuance of an equal amount of our one cent par value common stock. The Company received cash for the one cent par value for the issuance of 679,687373,437 common shares. As of December 31, 2018, 150,000 of such warrants remain un-exercised. During the year ended December 31, 2018, the Company issued 201,969 common shares andunder utilization of the remaining common shares were issued cashless, which resultedLTIP for the portion of the 2017 performance bonus paid in 564 shares repurchased bystock. Also during the year ended December 31, 2018, the Company paid $3.1 million in cash for the purchase of 230,013 Treasury shares withheld from employees upon the vesting of restricted stock awards and performance bonus shares for the payments of taxes. The shares held in treasury stock. The 564 shares held in Treasury stock were retired before December 31, 2017. As2018.Private Placement of Common StockOn December 19, 2016, we sold 2,272,727 shares of our common stock at $11.00 per share in a private placement. The shares were sold to selected institutional and accredited investors. We used the net proceeds of $23.8 million from the offering to fund our 2017 Haynesville Shale Trend development drilling program and for general corporate purposes, including working capital.Predecessor Company5.375% Series B Cumulative Convertible Preferred StockAs of the Effective Date there were $2.0 million of Series B Preferred Stock dividends in arrears. On the Effective Date, the obligations of the Company with respect to the 1,483,441 shares of outstanding 5.375% Series B Cumulative Convertible Preferred Stock were canceled and the holders did not receive a distribution or retain any property in the reorganized company pursuant to the Plan of Reorganization.10% Series C Cumulative Preferred StockAs of the Effective Date there were $3.9 million of Series C Preferred Stock dividends in arrears. On the Effective Date, the obligations of the Company with respect to the 3,060 shares of outstanding 10% Series C Cumulative Preferred Stock were canceled and the holders did not receive a distribution or retain any property in the reorganized company pursuant to the Plan of Reorganization.9.75% Series D Cumulative Preferred StockAs of the Effective Date there were $4.6 million of Series D Preferred Stock dividends in arrears. On the Effective Date, the obligations of the Company with respect to the 3,621 shares of outstanding 9.75% Series D Cumulative Preferred Stock were canceled and the holders did not receive a distribution or retain any property in the reorganized company pursuant to the Plan of Reorganization.10% Series E Cumulative Convertible Preferred StockOn the Effective Date, the obligations of the Company with respect to the 2,521 outstanding shares of 10% Series E Cumulative Convertible Preferred Stock were canceled and the holders did not receive a distribution or retain any property in the reorganized company pursuant to the Plan of Reorganization.Preferred Stock DividendsWe reported dividend gains from preferred stock exchange transactions of $4.1 million on our Consolidated Statements of Stockholders' Equity (Deficit) for the period January 1, 2016 to the Effective Date, while we reported preferred stock, net of $11.2 million on our Consolidated Statement of Operations for the same period. The difference represents the $15.3 million of preferred stock dividends in arrears.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS20172019 and 20162018 are from our oil and natural gas derivative contracts and have been recognized in “Other income (expense)” on our Consolidated Statements of Operations.The embedded derivative associated with the 8.0% Second Lien Notes was extinguished upon cancellation of the Notes upon our bankruptcy emergence on the Effective Date. For additional information see Note 5, “Debt” of these Consolidated Financial Statements. Year Ended December 31, 2019 Year Ended December 31, 2018 $ 9,560 $ (3,236 ) 5,450 (750 ) $ 15,010 $ (3,986 ) Successor Successor Predecessor Oil and Natural Gas Derivatives (in thousands) Year Ended December 31, 2017 October 13, 2016 to December 31, 2016 January 1, 2016 to October 12, 2016 Gain on commodity derivatives not designated as hedges, settled $ 471 $ — $ — Gain on commodity derivatives not designated as hedges, not settled 1,081 — 30 Total gain on commodity derivatives not designated as hedges $ 1,552 $ — $ 30 of Directors, and reviewed periodically by the Board of Directors.WeWe routinely exercise our contractual right to net realized gains against realized losses when settling with our$1.3$8.2 million had BP Energy CompanySunTrust Bank and RBC Capital been unable to fulfill their obligations as of December 31, 2017.2017,2019, the open positions on our outstanding commodity derivative contracts, all of which were with JPMorgan ChaseSunTrust Bank, N.A.RBC Capital and BPARM Energy, Company,and the associated fair values (in thousands) were as follows: December 31, 2019 221 80,945 $ 59.02 $ 35 2021 220 18,000 $56.58 24 Total oil 59 Natural gas swaps (MMBtu) 51,631 18,897,000 $ 2.67 $ 7,502 42,656 3,839,000 11 Natural gas collars (MMBtu) 2020 18,287 6,693,000 $2.40-$2.625 901 2021 27,000 2,430,000 $2.40-$2.625 (314 ) Total natural gas 8,100 2020 50,000 18,300,000 NYMEX - $0.209 $ 99 2021 50,000 18,250,000 NYMEX - $0.209 (239 ) 2022 50,000 18,250,000 NYMEX - $0.209 (518 ) 2023 50,000 18,250,000 NYMEX - $0.209 (679 ) 2024 50,000 18,300,000 NYMEX - $0.209 (1,040 ) Total natural gas basis (2,377 ) Total $ 5,782 Contract Type Daily
Volume Total
Volume Fixed Price December 31, 2017 Crude Oil swaps (Bbls) 2019 312 114,025 $ 51.80 $ (517 ) 2018 375 136,800 $ 51.80 (1,002 ) Total Oil (1,519 ) Natural gas swaps and calls (MMBtu) 2019 14,034 5,122,500 $ 3.03 566 2018 30,641 11,184,000 $2.985-$3.033 2,034 Total Natural Gas 2,600 Total Oil and Natural Gas $ 1,081 At December 31, 2016, we did not have any outstanding commodity derivative contracts.20172019 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See “Description of Business and Summary of Significant Accounting Policies” for our discussion regarding fair value, including inputs used and valuation techniques for determining fair values. $ - $ 8,537 $ - $ 8,537 - 31 - 31 - - - - - (2,786 ) - (2,786 ) $ - $ 5,782 $ - $ 5,782 December 31, 2017 Fair Value Measurements Using Description Level 1 Level 2 Level 3 Total Current Assets Commodity Derivatives $ — $ 2,034 $ — $ 2,034 Non-current Assets Commodity Derivatives — 566 — 566 Current Liabilities Commodity Derivatives — (1,002 ) — (1,002 ) Non-current Liabilities Commodity Derivatives — (517 ) — (517 ) Total $ — $ 1,081 $ — $ 1,081 counterparty.counter-party. The following table discloses and reconciles the gross amounts to the amounts as presented on the Consolidated Balance2017:2019: $ 9,401 $ (864 ) $ 8,537 847 (816 ) 31 (864 ) 864 - (3,602 ) 816 (2,786 ) $ 5,782 $ - $ 5,782 December 31, 2017 Fair Value of Oil and Natural Gas Derivatives (in thousands) Gross Amount Amount Offset As Presented Current Assets Commodity Derivatives $ 2,035 $ (1 ) $ 2,034 Non-current Assets Commodity Derivatives 633 (67 ) 566 Current Liabilities Commodity Derivatives (1,002 ) — (1,002 ) Non-current Liabilities Commodity Derivatives (585 ) 68 (517 ) Total $ 1,081 $ — $ 1,081 20172019 (in thousands): 5 $ 105,869 $ - $ 12,969 $ - $ - $ 92,900 Office space leases 11 2,353 $ 1,540 $ 813 $ - $ - $ - 2,491 $ 2,491 $ - $ - $ - $ - $ 110,713 $ 4,031 $ 13,782 $ - $ - $ 92,900 Payment due by Period Note Total 2018 2019 2020 2021 2022
and AfterDebt 5 $ 75,387 $ — $ 58,664 $ — $ 16,723 $ — Office space leases 5,103 1,510 1,540 1,540 513 — Operations contracts 871 836 20 15 — — Total contractual obligations (1) $ 81,361 $ 2,346 $ 60,224 $ 1,555 $ 17,236 $ — (1)$3.4$4.2 million as of December 31, 2017.2019. We recordrecord a separate liability for the asset retirement obligations. See Note 4.4.2017,2019, and 20162018 was approximatelyapproximately $1.7 million and $1.5$1.6 million, respectively.Defined Contribution Plan – Year Ended December 31, 2019 $ 1,540 118 $ 1,658 $ 2,922 (1,252 ) $ 1,670 $ 1,414 800 $ 2,214 1,540 813 - - - $ 2,353 $ 139 $ 2,214 defined contribution plan (“DCP”) which matchesweighted-average remaining lease term of 1.3 years and a portionweighted-average discount rate of employees’ contributions. Participation8.0 percent. Cash paid for amounts included in the DCP is voluntarymeasurement of operating lease liabilities was $1.6 million for the year ended December 31, 2019.all regular employees ofAcquisitionsare eligible to participate. We charged to expense plan contributions of zero, zero and $0.1 million in 2017, the successor period of 2016 and the predecessor period of 2016, respectively. We suspended the Company's portion of the match in April 2016.NOTE 11—Dispositions and AcquisitionsDuring 2017, we closed on various salesthe sale of undevelopedworking interests in certain non-core mineral interest which resultedHaynesville Shale Trend oil and gas leases and related facilities in $0.6Caddo Parish, Louisiana for total consideration of $1.3 million, in cash receipts that weresubject to customary post-closing adjustments. The disposition was recorded as a reduction ofto our oil and natural gas properties (full cost method) on our Consolidated Balance Sheets.Full Cost Pool.On December 13, 2016 weCompany closed on the sale of our shallow rights and the associatedworking interests in certain oil and gas reservesleases, including wells, facilities and leasehold acres in our Longwood propertiesTuscaloosa Marine Shale Trend operating area located in CaddoEast and West Feliciana Parish, in Louisiana for $1.0 million. We received net proceedstotal consideration of $0.8approximately $3.3 million after closing adjustments based onwith an effective date of NovemberMay 1, 2016. We2018. The disposition was subject to customary post-closing adjustments. The disposition was recorded the cash receipts as a reduction ofto our Full Cost Pool.NOTE 12—Subsequent EventsDuring 2018, certain holders of the 10 years costless warrants associated with the Convertible Second Lien Notes exercised 589,375 warrants for the issuance of an equal amount ofoil and natural gas properties (full cost method) on our one cent par value common stock. The Company received cash for the one cent par value for issuance of 42,500 common shares and the remaining common shares were issued cashless.(the “Disposition”) and certain net leasehold interests in a portion of its undeveloped acreage in the Angelina River Trend in Angelina and Nacogdoches Counties, Texas to BP America Production Company for total consideration of approximately $23.0 million, with an effective date of January 1, 2018. The Disposition isdisposition was subject to customary post-closing adjustments. The disposition was recorded as a reduction to our oil and natural gas properties (full cost method) on our Consolidated Balance Sheets. The Company utilized the proceeds from these dispositions to pay down the outstanding balance of the 2017 Senior Credit Facility on March 2, 2018 and to fund our capital expenditures program.SUPPLEMENTAL INFORMATION(Unaudited)3035 years of experience in the oil and natural gas industry, including over 2530 years as a reserve evaluator, trainer or manager. Further professional qualifications of our principal engineer include a degree in petroleum engineering, extensive internal and external reserve training, and experience in asset evaluation and management. In addition, the principal engineer is an activea participant in professional industry groups and has been a member of the Society of Petroleum Engineers for over 3035 years. 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, as of December 31, 2017 and 2016.firms. All of our proved reserves estimates shown herein at December 31, 20162019 and 2018 have been independently prepared by NSAI and RSC, respectively.RSC. NSAI prepared the estimates on all our proved reserves as of December 31, 20172019 and 2018 on our properties other than in the TMS. RSC prepared the estimate of proved reserves as of December 31, 20172019 and 2018 for our TMS properties. Copies of the summary reserve reports of NSAI and RSC for 20172019 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.2017.2019. For oil volumes, the average price of $51.34$55.69 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For natural gas volumes, the average price of $2.98$2.58 per MMBtu is adjusted by lease for energy content, transportation fees, and regional price differentials.20172019 and 20162018 (in thousands): Year Ended December 31, 2019 Year Ended December 31, 2018 $ 302,859 $ 206,097 123 180 302,982 206,277 (91,958 ) (41,886 ) $ 211,024 $ 164,391 Full Cost Accounting Method Full Cost Accounting Method Successful Efforts Accounting Method Successor Successor Predecessor Year Ended December 31, 2017 October 13, 2016 through December 31, 2016 January 1, 2016 to October 12, 2016 Proved properties $ 120,333 $ 61,040 $ 868,703 Unproved properties 5,984 24,102 107,318 126,317 85,142 976,021 Less: accumulated depreciation, depletion and amortization (15,632 ) (3,954 ) (912,252 ) Net oil and natural gas properties $ 110,685 $ 81,188 $ 63,769 20172019 and 2016,2018, respectively. Year Ended December 31, 2019 Year Ended December 31, 2018 $ 269 $ 178 - - - - 97,972 106,583 $ 98,241 $ 106,761 Full Cost Accounting Method Full Cost Accounting Method Successful Efforts Accounting Method Successor Successor Predecessor Year Ended December 31, 2017 October 13, 2016 through December 31, 2016 January 1, 2016 to October 12, 2016 Property Acquisition Unproved $ 527 $ 33 $ 450 Proved — — — Exploration — — 498 Development (1) $ 41,148 $ 4,284 $ 1,560 Total (2) $ 41,675 $ 4,317 $ 2,508 (1)$0.2$0.1 million in 20172019 and zeroless than $0.1 million in 2016.2018.(2)in the Successor periods related to the Haynesville Shale Trend and the majority of the cost incurred in the 2016 Predecessor period related the Tuscaloosa Marine Shale Trend.2017, 20162019, 2018 and 20152017 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: 470,937 415,224 286,038 1,441 2,130 2,815 (132,005 ) (16,993 ) 106,639 (166 ) (388 ) (381 ) 218,015 100,499 32,871 - - - - - - - - - (169 ) (3,349 ) - - (84 ) - (46,712 ) (24,444 ) (10,324 ) (171 ) (217 ) (304 ) 510,066 470,937 415,224 1,104 1,441 2,130 92,118 52,861 21,872 1,441 2,130 2,815 End of period 138,607 92,118 52,861 1,104 1,441 2,130 378,819 362,363 264,166 - - - End of period 371,459 378,819 362,363 - - - Natural Gas (Mmcf) Oil, Condensate and NGLs (MBbls) 2017 2016 2015 2017 2016 2015 Net proved reserves at beginning of period 286,038 31,851 104,832 2,815 3,834 28,143 479,583 428,002 302,927 Revisions of previous estimates (1) 106,639 (4,426 ) (62,437 ) (381 ) (543 ) (15,737 ) (133,001 ) (19,320 ) 104,354 Extensions, discoveries and improved recovery (2) 32,871 264,166 6,196 — — 1,207 218,016 100,499 32,871 Purchases of minerals in place — — — — — — - - - Sales of minerals in place — 2 (8,073 ) — — (8,551 ) (169 ) (3,852 ) - Production (10,324 ) (5,555 ) (8,667 ) (304 ) (476 ) (1,228 ) (47,738 ) (25,746 ) (12,150 ) Net proved reserves at end of period 415,224 286,038 31,851 2,130 2,815 3,834 516,691 479,583 428,002 Net proved developed reserves: Beginning of period 21,872 31,851 60,708 2,815 3,834 10,719 100,764 65,639 44,432 End of period 52,861 21,872 31,851 2,130 2,815 3,834 145,232 100,764 65,639 Net proved undeveloped reserves: Beginning of period 264,166 — 44,124 — — 17,424 378,819 362,363 258,495 End of period 362,363 264,166 — — — — 371,459 378,819 362,363 Natural Gas Equivalents (Mmcfe) 2017 2016 2015 Net proved reserves at beginning of period 302,927 54,852 273,690 Revisions of previous estimates (1) 104,354 (7,683 ) (156,858 ) Extensions, discoveries and improved recovery (2) 32,871 264,166 13,440 Purchases of minerals in place — — — Sales of minerals in place (3) — 2 (59,382 ) Production (12,150 ) (8,410 ) (16,038 ) Net proved reserves at end of period 428,002 302,927 54,852 Net proved developed reserves: Beginning of period 44,432 54,852 125,022 End of period 65,639 44,432 54,852 Net proved undeveloped reserves: Beginning of period 258,495 — 148,668 End of period 362,363 258,495 — (1)Revision Revisions of previous estimates in 2016 were negative, primarily due to increases in our operating expenditures and other tax rates. Revisions of previous estimates in 2015 were negative, primarily due to the transfer of undeveloped volumes out of the proved category.(2)related to our drilling activity on in the TMS in 2015. In 2016 we recognized a 264.2 Mmcfe gain reflecting our successful drilling results on our Haynesville Shale Trend Properties which continued into 2017.properties.(3)2015,2019, we sold approximately 59.4 MMBoe55 Mmcfe and in 2018, we sold approximately 2,500 Mmcfe, attributed to the sale of producing properties in the Eagle Ford Shale Trend located in south Texas.TMS and Haynesville Shale. $ 1,272,504 $ 1,494,557 $ 1,260,490 (377,851 ) (410,957 ) (430,048 ) (338,116 ) (349,552 ) (329,938 ) (13,945 ) (56,784 ) (17,113 ) 542,592 677,264 483,391 (248,269 ) (279,679 ) (223,081 ) $ 294,323 $ 397,585 $ 260,310 $ 2.58 $ 3.10 $ 2.98 $ 55.69 $ 65.56 $ 51.34 2017 2016 2015 Future revenues $ 1,260,490 $ 595,745 $ 245,411 Future lease operating expenses and production taxes (430,048 ) (213,030 ) (130,455 ) Future development costs (1) (329,938 ) (222,892 ) (20,146 ) Future income tax expense (17,113 ) (456 ) — Future net cash flows 483,391 159,367 94,810 10% annual discount for estimated timing of cash flows (223,081 ) (102,445 ) (24,915 ) Standardized measure of discounted future net cash flows $ 260,310 $ 56,922 $ 69,895 Index price used to calculate reserves (2) Natural gas (per Mcf) $2.98 $2.48 $2.58 Oil (per Bbl) $51.34 $42.75 $50.28 (1)$7.2$7.4 million and $10.3$7.3 million in 20172019 and 2016,2018, respectively.(2) $ 397,585 $ 260,310 $ 56,922 (146,806 ) 95,927 113,319 (82,706 ) (63,846 ) (32,012 ) (130,244 ) (25,595 ) 107,499 101,012 129,207 8,970 10 (3,382 ) - 125,172 (4,608 ) (59,560 ) 31,340 7,923 8,114 17,555 (16,336 ) (3,686 ) 41,777 26,416 5,709 (60,372 ) (8,431 ) 55,035 (103,262 ) 137,275 203,388 $ 294,323 $ 397,585 $ 260,310 Year Ended December 31, 2017 2016 2015 Balance, beginning of year $ 56,922 $ 69,895 $ 644,736 Net changes in prices and production costs related to future production 113,319 (20,442 ) (535,696 ) Sales and transfers of oil and natural gas produced, net of production costs (32,012 ) (15,826 ) (58,917 ) Net change due to revisions in quantity estimates 107,499 (8,630 ) (132,832 ) Net change due to extensions, discoveries and improved recovery 8,970 25,638 24,895 Net change due to purchases and sales of minerals in place — 648 (158,391 ) Changes in future development costs (59,560 ) 2,102 324,624 Previously estimated development cost incurred in period 8,114 — — Net change in income taxes (3,686 ) (164 ) 5,848 Accretion of discount 5,709 6,990 65,058 Change in production rates (timing) and other 55,035 (3,289 ) (109,430 ) Net increase (decrease) in standardized measures 203,388 (12,973 ) (574,841 ) Balance, end of year $ 260,310 $ 56,922 $ 69,895 On November 16, 2017, Hein & Associates LLP (“Hein”), our independent registered public accounting firm combined with Moss Adams LLP (“Moss Adams”). As a result of this transaction, on November 16, 2017, Hein resigned as our independent registered public accounting firm. Concurrent with such resignation, our audit committee approved the engagement of Moss Adams as our new independent registered public accounting firm for the Company.The audit report of Hein on the Company’s financial statements for the periods from October 13, 2016 through December 31, 2016 (Successor) and January 1, 2016 through October 12, 2016 (Predecessor) did not contain an adverse opinion or a disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles.During the most recent fiscal year ended December 31, 2016 and through the subsequent interim period preceding Hein’s resignation, there were no disagreements between the Company and Hein on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of Hein would have caused them to make reference thereto in their report on the Company’s financial statements for such years.During the most recent fiscal year ended December 31, 2016 and through the subsequent interim period preceding Hein’s resignation, there were no reportable events within the meaning set forth in Item 304(a)(1)(v) of Regulation S-K.During the two most recent fiscal years and through the subsequent interim period preceding Moss Adam’s engagement, we did not consult with Moss Adams on either (1) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that may be rendered on our financial statements, and Moss Adams did not provide us with either a written report or oral advise that Moss Adams concluded was an important factor considered by us in reaching a decision as to the accounting, auditing or financial reporting issue; or (2) any matter that was either the subject of a disagreement, as defined in Item 304(a)(1)(iv) of Regulation S-K, or a reportable event, as defined in Item 304(a)(1)(v) of Regulation S-K.2017,2019, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.None.Table of Contents2, 2018,5, 2020, are as follows: 59 60 63 55 67 63 Steven J. Pully58DirectorK. Adam Leight61DirectorTimothy D. Leuliette 6870 Jeffrey S. Serota 54 Edward J. Sondey 54 Thomas M. Souers 6466 Director Senioras Vice President, Controller and Principal AccountingChief Financial Officer. HeIn January 2018, he was named Interim Chief Financial Officer in April 2016, and was named CFO in January 2017.Senior Vice President. Mr. Barker has over 3530 years of experience in the energy industry. Prior to joining the Company, Mr. Barker was Controller for Cygnus Oil and Gas Corporation. Mr. Barker is a Certified Public Accountant and holds an MBA from the University of Houston.operations.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 byfor CSL Energy Opportunities Fund II, LP, and Matador Resources Company. He was appointed to the Company’s Board of Directors in 2016.Mark E. Ferchau became Executive Vice President of the Company in 2004. He had previously served as the Company’s Senior Vice President, Engineering and Operations, after initially joining the Company as a vice President in 2001. Mr. Ferchau previously served as Production manager for Forcenergy Inc. from 1997 to 2001 and as Vice President, Engineering of Convest Energy Corporation from 1993 to 1997. Prior thereto, Mr. Ferchau held various positions with Wagner & Brown, Ltd. and other independent oil and natural gas companies.Walter G. Goodrich became chairman of the board of Goodrich Petroleum Corporation in May 2015. Mr. Goodrich served as vice chairman of the board since 2003 and has served as 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. Mr. Goodrich 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 1995.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 almost 30 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 law department at CMS Energy Corporation from 1988 to 2000, including Chief Counsel at CMS Oil & Gas Company from 1995 to 2000.3735 years building and managing investment research departments, covering the energy industry for major financial institutions, and advising energy companyinvestors and managements. Mr. Leight is thepresently 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, andindustry. He is also a senior advisor toSenior Advisor with Al Petrie Advisors, which providesproviding capital markets and investor relations and strategicand capital markets advice to energy companies. Prior to that,industry managements. Previously, Mr. Leight served as a managing director and Head of US Credit Research at RBC Capital Markets from 2008 to 2016, managing director at Credit Suisse from 2000 to 2007 and managing director and Co-Head of Global Leveraged Finance Research 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. Mr. LeightHe currently serves on the board of Warren Resources, a privatean independent oil &and gas company, andproduction company. Mr. Leight has also served on the advisory boards of Falcon Capital Management, University of Wisconsin ASAP, and on the boards of trustees of severalvarious non-profit institutions.boards. Mr. Leight is a Chartered Financial Analyst and holds an A.B. in economics from Washington University, and an M.S. in investment finance from the University of Wisconsin.Wisconsin and is a Chartered Financial Analyst. He was appointed to the Company’s Board of Directors in 2016.it’sits 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.StevenJeffrey S. Serota J. Pully provides consultingserves as Vice Chairman and investment banking services for companies and investors focused on the oil and gas sector. From 2008 until 2014, Mr. Pully served as General Counsel and a PartnerChief Investment Officer of theCorbel Capital Partners, an independent investment firm Carlson Capital, L.P.that makes non-control investments in debt or equity securities in lower middle-market businesses. Mr. Pully was also previously a Senior Managing Director at Bear Stearns and a Managing Director at Bank of America Securities focused on energy investment banking. Mr. Pully is on three other public company boards, Bellatrix Exploration, Titan Energy and VAALCO Energy andSerota has also served on numerous other boards of public and private companies in the oil and gas and other industries, including as a director of EPL Oil & Gas and Energy XXI within the past five years. Mr. Pully is a Chartered Financial Analyst, a Certified Public Accountant in the State of Texas and a member of the State Bar of Texas. Mr. Pully earned his undergraduate degree in Accounting from Georgetown University and is also a graduate of The University of Texas School of Law. He was appointed to the Company’s Board in March, 2017. Mr. Pully brings his manyover 30 years of experience as a successful businessmanprincipal investor, financial services professional and operating executive. Independent of his responsibilities at Corbel, Mr. Serota currently serves as wellthe 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.servingin 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 boardexecution of numerous oilM&A, capital markets and gas companies, including other publicly traded companies. For these reasons,structured commodity transactions. Prior to BofA Merrill, Mr. Pully has beenSondey 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 invaluableearly member of our Board.n umbernumber 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.Robert C. Turnham, Jr. has served as the chief operating officer of Goodrich Petroleum Corporation since 1995 and became president and chief operating officer in 2003. Mr. Turnham 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 served as president of Liberty Production Company, an oil and natural gas exploration and production company. He has served as a director since 2006.20182020 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 20182020 annual meeting of stockholders to be filed within 120 days from December 31, 2017.2019. Additional information regarding our corporate governance20182020 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2017.20182020 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2017.20182020 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2017.20182020 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2017.2019.Statements”Statements” on page 56.10.610.710.810.910.1010.1110.1210.1310.14†10.15†10.16†10.17†10.18†10.19†10.20†10.21†10.22†10.23†10.24†10.25†12.1*12.2*21 23.3*23.4*31.1*24.1**Filed herewith.**Furnished herewith.†2, 2018. GOODRICH PETROLEUM CORPORATION By: ofon Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.2, 2018. S/s/ ROBERT C. TURNHAM, JR. S/s/ ROBERT T. BARKER /S/ RONALD COLEMANDirectorRonald Coleman S/ ADAM LEIGHTs/ RONALD COLEMAN Adam Leight /S/ TIM LEULIETTEDirectorTim Leuliette S/ STEVEN J. PULLYs/ ADAM LEIGHT Steven J. Pully /S/ TOM SOUERS DirectorTom Souers 106