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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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For the fiscal year ended December 31, 2020

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For the transition period from to

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Commission file number 001-16317

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CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

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111 E. 5^th Street, Suite 300

Fort Worth, Texas 76102

(Address of principal executive offices)

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(817) 529-0059

(Registrant’s telephone number, including area code)

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

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

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

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

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes ⌧  No  ◻

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Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ⌧  No  ◻

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ◻

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Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ◻

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

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At June 30, 2020, the aggregate market value of the registrant’s common stock held by non-affiliates (based upon the closing sale price of shares of such common stock as reported on the NYSE American) was $159.2 million. As of March 5, 2021, there were 199,146,980 shares of the registrant’s common stock outstanding.

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Documents Incorporated by Reference

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Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report since the registrant will file with the Securities and Exchange Commission, not later than 120 days after the close of its fiscal year, a definitive proxy statement, pursuant to Regulation 14A. The information required by Items 10, 11, 12, 13 and 14 of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form 10-K.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2020

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Certain statements contained in this report may contain “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. The words and phrases “should”, “could”, “may”, “will”, “believe”, “plan”, “intend”, “expect”, “potential”, “possible”, “anticipate”, “estimate”, “forecast”, “view”, “efforts”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in this report and those factors summarized below:    

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Any of these factors and other factors described in this report could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and assumptions to be reasonable when made, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. Our assumptions about future events may prove to be inaccurate. Moreover, the effects of the COVID-19 pandemic may give rise to risks that are currently unknown or amplify the risks associated with many of the factors summarized above. We caution you that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur. You should not place undue reliance on forward-looking statements in this report as they speak only as of the date of this report.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered.

All forward-looking statements, expressed or implied, in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or any person acting on our behalf may issue.

Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

All references in this Form 10-K to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and its wholly-owned subsidiaries. Unless otherwise noted, all information in this Form 10-K relating to oil and natural gas reserves and the estimated future net cash flows attributable to those reserves, is based on estimates prepared by independent, third-party engineers, and is net to our interest.

Summary of Risks Associated with our Business

An investment in the Company is subject to risks inherent to our business. In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the risks and uncertainties described in in the section entitled

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“Risk Factors” included in this report when evaluating the Company. Below is a summary of some of the risks we face, all of which are more fully described in Part I, Item 1A. “Risk Factors” below.

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PART I

Item 1. Business

Overview

We are a Fort Worth, Texas based independent oil and natural gas company. Our business is to maximize production and cash flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties primarily located in Oklahoma, Texas, Wyoming and Louisiana and use that cash flow to explore, develop, exploit and acquire oil and natural gas properties across the United States. We were originally formed in 1999 as a Nevada corporation and changed our state of incorporation to the State of Delaware in 2000, and, following approval by our stockholders in 2019, we changed our state of incorporation from the State of Delaware to the State of Texas.

The following table lists our primary producing areas as of December 31, 2020:

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Impact of the COVID-19 Pandemic

A novel strain of the coronavirus (“COVID-19”) surfaced in late 2019 and has spread, and continues to spread, around the world, including to the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for oil throughout the world and, when combined with the oil supply increase attributable to the battle for market share among OPEC, Russia and other oil producing nations, resulted in oil prices declining significantly beginning in late February 2020. While there has been a modest recovery in oil prices, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which has negatively impacted the Company’s results of operations and planned 2020 capital activities. Due to the extreme volatility in oil prices and the impact of the COVID-19 pandemic on the financial condition of our upstream peers, we suspended our drilling program in the Southern Delaware Basin in the first quarter of 2020 and focused on certain measures that included, but were not limited to, the following:

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From our initial entry into the Southern Delaware Basin in 2016 and through early 2019, we focused on the development of our initial 6,500 net acre position in Pecos County, Texas (“Bullseye”), and in December 2018, we purchased an additional 4,200 gross operated (1,700 net) acres and 4,000 gross non-operated (200 net) acres to the northeast of our Bullseye acreage (“NE Bullseye”) for approximately $7.5 million. We paid $3.2 million cash in

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December 2018, with the remaining cash balance paid in installments in March and October of 2019. Our 2019 drilling program in West Texas included the completion of one well previously drilled in the Bullseye area, the drilling and completion of a second Bullseye well, and the drilling and completion of three wells in the NE Bullseye area. In December 2019, we began completion operations on the fourth NE Bullseye well, which began producing in January 2020. As of December 31, 2020, we were producing from 18 wells over our approximate 16,200 gross (7,500 net) acre position in West Texas, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

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In response to low commodity prices, and a related window of opportunity to acquire producing properties on very attractive terms, we concluded our 2019 drilling program, which was designed to only preserve core areas of our West Texas play. Thereafter, we focused on identifying, evaluating and acquiring producing reserves. As a result, we were successful in closing the Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) acquisitions (“Will Energy Acquisition” and “White Star Acquisition”) in the fourth quarter of 2019. These transactions were transformative, as production from these acquisitions represented approximately 70% of the Company’s total net production for the year ended December 31, 2020. See Note 4 – “Acquisitions and Dispositions” for more information.

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In connection with the September 2019 signing of the agreement to acquire certain assets from Will Energy and a concurrent equity offering, we entered into a new revolving credit agreement with JPMorgan Chase Bank, N.A. and other lenders (the “Credit Agreement”). In connection with the entry into the Credit Agreement, we repaid all obligations outstanding on, and terminated, our previous credit agreement with Royal Bank of Canada, which matured on October 1, 2019. The Credit Agreement has since been amended to increase the number of lenders from three to nine, and among other things, to adjust the borrowing base to $130.0 million on January 21, 2021 and $120.0 million on March 31, 2021. See Note 13 – “Long-Term Debt” for more information.

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In December 2019, we entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides us the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company, located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, was determined to be unsuccessful in June 2020. We are currently evaluating for future testing a number of exploratory prospects included in the Joint Development Agreement, including our Boss Hogg prospect located in the Eugene Island 298 Area in the shallow waters off of the Louisiana coastline. Our strategy and timing on the testing of the Boss Hogg will be determined during the year based on regulatory considerations, some of which are fluid at this time, and on operational considerations, including the availability of appropriate equipment.  

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Subsequent to the reduction in our drilling program in the latter half of 2019, which then led to the suspension of onshore drilling in the first quarter of 2020, we continued to identify opportunities for cost reductions and operating efficiencies in all areas of our operations, while also searching for new producing property acquisition opportunities. Acquisition efforts have been, and we believe will continue to be, focused on PDP-heavy assets where we might also be able to leverage our geological and operational experience and expertise to reduce operating expenses, enhance production and identify and develop additional drilling opportunities that we believe will enable the Company to economically grow production and add reserves.

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On June 5, 2020, we announced the addition of a new corporate business line that includes offering a property management service (or a “fee for service”) for oil and natural gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs by engaging a contract operator of its oil and gas assets. As part of this service offering, we entered into a Management Services Agreement (“MSA”) with Mid-Con, effective July 1, 2020, to provide services as contract operator of record on Mid-Con’s oil and natural gas properties, along with certain administrative and management services, in exchange for an annual services fee of $4 million, paid ratably over the twelve month period, plus reimbursement of certain costs and expenses, a deferred fee of $166,666 per month for each month that the agreement is in effect (not to exceed $2 million), to be paid in a lump sum upon termination of the agreement, and warrants to purchase a minority equity ownership in Mid-Con. In connection with the Company’s acquisition of Mid-Con on January 21, 2021, the MSA was terminated, the deferred fee obligation was forgiven, and the warrants were cancelled. See Note 4 – “Acquisitions and Dispositions” for more information. We recorded $2.0 million in revenue during the year ended December 31, 2020 related to the MSA with Mid-Con, which is included in “Fee for services revenue” in the Company’s consolidated statements of operations.

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On June 8, 2020, the stockholders of the Company, at the Company’s 2020 Annual Meeting of Stockholders, approved an amendment (the “Charter Amendment”) to the Company’s Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized shares of common stock, par value of $0.04 per share, of the Company from 200,000,000 shares to 400,000,000 shares, and also approved the conversion of the 2,700,000 shares of the Series C contingent convertible preferred stock, par value $0.04 per share into 2,700,000 shares of the Company’s common stock. On June 10, 2020, we filed the Charter Amendment with the Secretary of State of the State of Texas.

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On June 24, 2020, we entered into an Open Market Sale Agreement (the “Sale Agreement”) among the Company and Jefferies LLC (the “Sales Agent”). Pursuant to the terms of the Sale Agreement, we may sell, from time to time through the Sales Agent in the open market, subject to satisfaction of certain conditions, shares of the Company’s common stock, having an aggregate public offering price of up to $100,000,000 (the “Shares”) (the “ATM Program”). We intend to use the net proceeds from any sales through the ATM Program, after deducting the Sales Agent’s commission and any offering expenses, to repay borrowings under our Credit Agreement and for general corporate purposes, including, but not limited to, acquisitions and exploratory drilling. Under the ATM Program, we sold 163,929 shares during the year ended December 31, 2020 for net proceeds of $0.5 million.

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On October 25, 2020, we entered into an agreement and plan of merger with Mid-Con providing for the acquisition by the Company of Mid-Con in an all-stock merger transaction in which Mid-Con would become a direct, wholly owned subsidiary of Contango. The Mid-Con Acquisition closed on January 21, 2021, at which time the MSA between Contango and Mid-Con was terminated. On October 30, 2020, we entered into the Third Amendment (the “Third Amendment”) to our Credit Agreement which, among other things, increased the Company’s borrowing base  from $75 million to $130 million, effective upon the closing of the Mid-Con Acquisition, with an automatic $10.0 million reduction in the borrowing base on March 31, 2021. A total of 25,409,164 shares of Contango common stock were issued at the closing of the Mid-Con Acquisition. See Note 4 – “Acquisitions and Dispositions” for more information.

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Concurrently with the announcement of the Mid-Con Acquisition, on October 27, 2020, we completed a private placement of 26,451,988 shares of common stock with a select group of institutional and accredited investors for net proceeds of approximately $38.8 million, after deducting the underwriting discount and fees and expenses. The use of those proceeds was in connection with the Mid-Con Acquisition and for general corporate purposes, including the repayment of debt outstanding under our Credit Agreement.

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On November 27, 2020, we entered into a purchase and sale agreement with an undisclosed seller to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in Texas and New Mexico (collectively the “Silvertip Acquisition”) for aggregate consideration of approximately $58 million. The Silvertip Acquisition closed on February 1, 2021, for a net consideration of approximately $53.2 million in cash after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date. See Note 4 – “Acquisitions and Dispositions” for more information.

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On December 1, 2020, we completed a private placement of 14,193,903 shares of common stock for net proceeds of approximately $21.7 million, after deducting the underwriting discount and fees and expenses. The net proceeds were used to fund the Silvertip Acquisition and for general corporate purposes, including the repayment of debt outstanding under our Credit Agreement.

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For 2021, we believe that a continuing challenging commodity price environment, and a shortage of capital available to the energy industry, may present more opportunities to acquire additional producing properties that could provide strong production, cash flow and future development potential at attractive rates of return. We plan to be active in pursuing such acquisition opportunities and then allowing our technical teams to leverage our experience and expertise to work on increasing returns through cost reduction, production enhancement and future development of the undeveloped drilling locations that come with the production acquired. We can provide no assurances that we will acquire any producing property opportunities on attractive terms, or at all, or that we will realize the expected benefits of any acquisition. We currently have a conservative capital expenditure program planned for 2021 and plan to limit that program to drilling and workover projects that we believe may provide compelling returns in this current commodity price environment or where necessary to preserve strategic acreage in our core areas, while simultaneously continuing to

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make balance sheet strength a priority in 2021 as we utilize excess cash flow to reduce debt and increase our capacity to quickly react to acquisition opportunities.

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As we focus on the above stated initiatives, we also plan to continue to sell non-core assets to improve overall margins, to provide incremental liquidity, to reduce future asset retirement obligations and to improve our balance sheet. In 2020, we sold certain producing and non-producing properties located in our Central Oklahoma and Western Anadarko regions. These non-core, marginally economic properties were a minor portion of the value of properties acquired from Will Energy and White Star and were sold in exchange for approximately $0.5 million in cash and the buyers’ assumption of the plugging and abandonment liabilities and revenue held in suspense on those properties. The Company recorded a gain of $4.4 million as a result of the buyers’ assumption of the asset retirement obligations associated with the sold properties.

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Production and Reserve Overview

Our production sales for the year ended December 31, 2020 were approximately 6.1 MMBoe (or 16.7 MBoe/d), comprised of 27% oil, 52% natural gas and 21% NGLs. Our production sales for the three months ended December 31, 2020 were approximately 1.3 MMBoe (or 14.4 MBoe/d), comprised of 28% oil, 49% natural gas and 23% NGLs. Our onshore properties contributed approximately 82% and 84% of our total production sales for the three and twelve months ended December 31, 2020, respectively.

As of December 31, 2020, our proved reserves, as estimated by William M. Cobb and Associates (“Cobb”), our independent petroleum engineering firm, in accordance with reserve reporting guidelines required by the Securities and Exchange Commission (“SEC”), were approximately 34.2 MMBoe, consisting of 13.0 MMBbl of oil and condensate, 84.5 Bcf of natural gas and 7.2 MMBbl of natural gas liquids (“NGLs”). As of December 31, 2020, our proved reserves were approximately 80% proved developed (volumetrically), approximately 88% were onshore properties, and approximately 98% of total volumes were attributed to wells and properties operated by us.

As of December 31, 2020, our proved reserves had a present value, discounted at a 10% rate based on year-end SEC pricing guidelines (“PV-10”), of $126.4 million. PV-10 as of December 31, 2020 was based on SEC prices of $39.57 per barrel of oil and $2.14 per MMBtu of natural gas. Resulting realized prices, after adjustments and differentials across all assets, were $36.57 per barrel of oil, $1.86 per MMBtu of natural gas and $12.43 per barrel of NGL. As of December 31, 2020, our proved reserves were approximately 89% of total PV-10 proved developed, approximately 92% of total PV-10 onshore and approximately 98% of total PV-10 attributed to wells and properties operated by us. PV-10 is not an accounting principle generally accepted in the United States of America (“GAAP”) and is therefore classified as a non-GAAP financial measure. A reconciliation of our Standardized Measure to PV-10 is provided under “Item 2. Properties - PV-10”. As of December 31, 2020, our proved reserves had a Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) of $115.6 million, in comparison to a Standardized Measure of $257.8 million as of December 31, 2019.

The following summary table sets forth certain information with respect to our proved reserves as of December 31, 2020 (excluding proved reserves attributable to our 37% equity investment in Exaro), as estimated by Cobb, and our net average daily production for the year ended December 31, 2020:

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The following summary table sets forth certain information with respect to the proved reserves attributable to our equity-method investment in Exaro, as of December 31, 2020, as estimated by W.D. Von Gonten and Associates (“Von Gonten”), and our net share of Exaro’s average daily production for the year ended December 31, 2020:

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Our Strategy

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Our long-term business strategy is:

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• Pursuing accretive, opportunistic acquisitions that meet our short-term and long-term strategic and financial objectives. We believe that there is currently a window of opportunity for us to acquire PDP-heavy assets that also possess sizable undeveloped acreage positions from distressed and/or motivated sellers at an attractive discount to PDP PV-10 valuations. Consequently, we currently intend to focus our future growth efforts on identifying, evaluating and pursuing the acquisition of such oil and natural gas properties in areas where we currently have a presence and/or specific operating expertise that will position us to enhance our expected acquisition returns through leveraging our operational experience and expertise in order to provide productivity and cost-reduction improvements, and where appropriate, increase reserves through development drilling. We may acquire individual properties or private or publicly traded companies, in each case for cash, common stock, preferred stock or a combination thereof. We believe that the ongoing challenging commodity price environment, and very limited sources of debt and/or equity capital available to our industry, should provide significant reserve and cash flow growth opportunity for us through potential corporate combinations that provide an attractive mix of significant cash flow and undeveloped growth potential.

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• Enhancing our existing portfolio by dedicating the majority of our capital expenditures to our existing portfolio of oil and liquids-rich opportunities. A key element of our long-term strategy is to continue to develop the oil and natural gas liquids resource potential that we believe exists in numerous formations within our various oil/liquids weighted resource plays, and where possible, to expand our presence in those plays. Due to the current superior economics of oil production, as compared to natural gas, we expect to focus on oil and liquids-weighted opportunities as we believe that liquids-heavy assets currently provide the potential for more attractive investment economics, although we will not rule out the acquisition of gas weighted properties if we believe the acquisition is accretive to our shareholders. In response to the continuing challenging commodity price environment, and the current opportunity to be an asset consolidator in the industry, we plan to limit near-term drilling capital for the foreseeable future to that necessary to fulfill leasehold commitments, and preserve core acreage when appropriate, and where the opportunity exists, to drill on acquired acreage where we can add production and cash flow at attractive rates of return. We will, however, continue to evaluate high quality drilling opportunities that have the potential to add significant reserves and cash flow to our portfolio at low finding and development cost, such as our shallow water Gulf of Mexico exploratory prospects.

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• 2021 business strategy. During 2021, we intend to continue to minimize our drilling program, pursue additional “fee for service” opportunities similar to the now terminated Management Services Agreement entered into with Mid-Con, as well as pursue growth through the acquisition of PDP-heavy assets and use excess cash flow for the reduction in borrowings outstanding under our Credit Agreement. We will also be keenly focused on continuing to reduce lease operating costs and general and administrative expenses, and on improving cash margins and lowering our exposure to asset retirement obligations through the possible sale of additional non-core properties. We will continue to make balance sheet strength a priority in 2021 and will continue to evaluate certain acquisition opportunities that may arise in this challenging commodity price environment. We will retain the flexibility to be more aggressive in our drilling plans should planned results exceed expectations, commodity prices improve or we reduce drilling and completion costs in certain areas, thereby making an expansion of our drilling program an appropriate business decision. Our 2021 capital expenditure budget is currently planned to be between $13 - $16 million for capital workovers, facility upgrades, waterflood development and selected new well drills; however, due to our ongoing evaluation of future development for our recently acquired properties from the Mid-Con Acquisition and the Silvertip Acquisition, and the regulatory and operational considerations to consider in our GOM program, our capital expenditure program will continue to be evaluated for revision during the year. We believe that we will have the financial resources to increase the currently planned 2021 capital expenditure budget, when and if deemed appropriate, including as a result of changes in commodity prices, economic conditions or operational factors.

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Properties

As of December 31, 2020, our properties were located in the following regions: Offshore GOM, Central Oklahoma, Western Anadarko, West Texas and Other Onshore.

Offshore Gulf of Mexico

As of December 31, 2020, our offshore assets consisted of seven company-operated wells in the shallow waters of the GOM off of the coast of Louisiana. The following summary table sets forth certain information with respect to our offshore reserves as of December 31, 2020 and average daily offshore production sales for the year ended December 31, 2020:

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Dutch and Mary Rose Field

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We currently operate five producing wells located in federal waters at Eugene Island 10 (“Dutch”), and two producing wells located in adjacent Louisiana state waters (“Mary Rose”). Our offshore average daily production sales for three months ended December 31, 2020 were approximately 2.5 MBoe per day (20% liquids). All Dutch and Mary Rose wells flow to a Company-owned and operated production platform at Eugene Island 11. While we do not own the lease for the Eugene Island 11 block, this does not impact our ability to operate our facilities located on that block. Operators in the GOM may place platforms and facilities on any location without having to own the lease, provided that permission and proper permits from the Bureau of Safety and Environmental Enforcement (“BSEE”) have been obtained. We have obtained such permission and permits. We installed our facilities at Eugene Island 11 because that was the optimal gathering location in proximity to our wells and marketing pipelines.

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From our production platform we are able to access two separate oil and natural gas markets thereby minimizing downtime risk and providing the ability to select the best sales price for our oil and natural gas production. Oil and natural gas production can flow through our 20” gas pipeline to third-party owned and operated onshore processing facilities near Patterson, Louisiana. Alternatively, natural gas can flow via our 8” pipeline to a third-party owned and operated onshore processing facility southwest of Abbeville, Louisiana, and oil can flow via a 6” oil pipeline to third-party owned and operated onshore processing facilities in St. Mary Parish, Louisiana. Production facilities include a turbine type compressor capable of servicing all Dutch and Mary Rose wells at the Eugene Island 11 platform. Condensate can also flow to onshore markets and multiple refineries.    

Gulf of Mexico Exploratory Prospects

In December 2019, we entered into a Joint Development Agreement with Juneau, that provides the Company the right to acquire an interest in up to six of Juneau’s prospects located in the Gulf of Mexico. The first such prospect acquired by the Company was the Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, which was determined to be unsuccessful in June 2020. The Company is currently evaluating for future testing a number of exploratory prospects included in the Joint Development Agreement, including the Boss Hogg prospect located in the Eugene Island 298 Area in the shallow waters off of the Louisiana coastline. Management considers this Boss Hogg prospect to be an excellent complement to its PDP-oriented acquisition strategy and believes it could provide a very compelling economic value proposition, even in the current low oil price environment. We are currently working through regulatory considerations and operational factors, including the availability of appropriate equipment, in determining the ultimate strategy for, and timing on, the testing of that prospect.  

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Central Oklahoma

During the three months ended December 31, 2019, we acquired producing properties in the Will Energy Acquisition and White Star Acquisition that are located in the Central Oklahoma region and are primarily in the Woodford, Meramec, Mississippian, Chester, Oswego and Hunton formations. In December 2019, we completed and brought on production a Garfield County, Oklahoma well, which we acquired in connection with the White Star

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Acquisition. As of December 31, 2020, the Central Oklahoma region included approximately 629,100 gross (257,700 net) acres, proved reserves of 15.4 MMBoe (54% oil/liquids) and 674 gross (342.3 net) producing wells. Our average daily production sales for the year ended December 31, 2020 were approximately 9,500 Boe per day, and we operated 63% of our Central Oklahoma producing properties as of December 31, 2020. Our focus in this area in 2020 was on the reduction in lease operating expenses to enhance economic returns. We made progress through that program and were able to lower forecasted operating expenses for 2020 year-end reserves by 43% compared to the 2019 year-end reserves. This improvement in lease operating expenses during 2020 was the basis of a $38.5 million improvement in the present value of the 2020 year-end proved reserves for this region. We did not drill in this region during 2020, and while no drilling is currently planned for this region in 2021, we do plan to pursue an active production-enhancing workover program in the area during 2021.

Western Anadarko

During the three months ended December 31, 2019, we acquired producing properties in the Will Energy Acquisition and White Star Acquisition that are located in the Western Anadarko region and are primarily in the Chester, Tonkawa, Morrow, Marmaton, Cottage Grove, Red Fork and Cleveland formations. We did not drill in this region during the year ended December 31, 2020, as our focus in this area, similar to the Central Oklahoma region, was on the reduction in lease operating costs to enhance economic returns. We made progress through that program and were able to lower forecasted operating expenses for 2020 year-end reserves by 47% compared to the 2019 year-end reserves. This improvement in costs was the basis of a $3.1 million improvement in the present value of the 2020 year-end proved reserves for this region. As of December 31, 2020, the Western Anadarko region included approximately 274,600 gross (144,500 net) acres, proved reserves of 4.9 MMBoe (47% oil/liquids) and 400 gross (196.9 net) producing wells. Our average daily production sales for the year ended December 31, 2020 were approximately 2,400 Boe per day, and we operated 50% of our Western Anadarko producing properties as of December 31, 2020. No drilling is currently planned for this region in 2021.

West Texas

Southern Delaware Basin

We and our 50% non-operated working interest partner in the Southern Delaware Basin own approximately 16,200 gross acres (7,500 net acres to Contango). As of December 31, 2020, we estimate that we have net proved reserves of 8.3 MMBoe (87% oil, 96% total liquids) in our West Texas region.

In the first quarter of 2020, and in response to low commodity prices and a related window of opportunity to acquire producing properties on attractive terms, we suspended our drilling program in the Southern Delaware Basin. We believe we have 68 gross (27.5 net) potential drilling locations in the Wolfcamp A and B areas of our acreage, substantially all of which we believe can accommodate 10,000 foot laterals that could provide a basis for future development and reserve growth in a more favorable and stable oil price environment. Included in the 68 gross locations are 32 proved undeveloped locations and 36 unbooked locations. If the recent improvement in oil prices is sustained, some capital could be allocated to the drilling of proved undeveloped locations in this area during 2021. As of December 31, 2020, we had 13 wells producing from Wolfcamp A and five wells producing from Wolfcamp B, that produced at an average rate of approximately 1,000 Boe per day during the year ended December 31, 2020.

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Other Onshore

Our Other Onshore region is comprised of various smaller non-core producing areas in Texas, Louisiana, Wyoming and Mississippi. As of December 31, 2020, our estimated net proved reserves for the properties in this region are 1.4 MMBoe.

Texas

Our Southeast Texas area includes approximately 19,500 gross (11,700 net) acres in Madison and Grimes counties, with the potential for a multi-year inventory of drilling locations encompassing the Woodbine, Eagle Ford Shale and/or Georgetown/Buda formations in an improved oil price environment. We had proved reserves of 0.7 MMBoe (73% oil/liquids) and 37 gross (20.0 net) producing wells in Southeast Texas as of December 31, 2020.

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Our South Texas area includes properties in Dimmitt and Zavala counties, which include approximately 16,100 gross (6,600 net) acres that we believe to be prospective for the Buda, Georgetown and Eagle Ford Shale plays in an improved price environment. Our South Texas area also includes approximately 14,300 gross (7,300 net) acres located in conventional fields that produce primarily from the Wilcox, Frio, and Vicksburg sands. Our estimated net proved reserves in this area were 1.3 MMBoe (44% oil/liquids) with 39 gross (17.6 net) producing wells, as of December 31, 2020.

Our East Texas area includes approximately 5,900 gross (3,600 net) acres primarily in San Augustine County, with proved reserves of 0.2 MMBoe (26% oil/liquids) and 8 gross (4.7 net) wells producing in the Haynesville, Mid-Bossier and/or James Lime formations. There has been renewed interest in this area by offset operators as they experiment with new frac techniques and refracing of previously drilled wells.

No drilling capital has been allocated to these Texas areas since 2015 due to the challenging commodity price environment and our focus on our West Texas region properties, with the exception of four successful non-operated Georgetown wells in which we participated in drilling from 2017 through 2019.

Louisiana

As of December 31, 2020, the estimated proved reserves for our Louisiana properties were 0.5 MMBoe (56% oil/liquids) primarily related to the properties we acquired in the Will Energy Acquisition.

Wyoming

In 2015, we drilled the first of three successful wells in this area targeting the Muddy Sandstone formation. Based on prior drilling results, a sustained improvement in oil prices will be needed to justify allocation of drilling capital to this area at the expense of other areas in our portfolio that provide higher returns. As of December 31, 2020, our Wyoming area includes approximately 33,200 gross (23,000 net) net acres with estimated proved reserves of 0.1 MMBoe (91% oil) as of December 31, 2020.

Mississippi

As of December 31, 2020, we held approximately 1,300 gross (300 net) mostly undeveloped acres in Mississippi.

Impairment of Long-Lived Assets

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Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field-by-field basis to the unamortized capitalized cost of the assets in that field. In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by OPEC and Russia to reach an agreement on lower production quotas until April 2020, caused a dramatic increase in the supply of oil, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. Consequently, during the first quarter of 2020, we recorded a $143.3 million non-cash charge for proved property impairment of our onshore properties related to the dramatic decline in commodity prices, the PV-10 of our proved reserves, and the associated change in our current development plans for proved, undeveloped locations. In the fourth quarter of 2020, we recorded an additional $21.1 million non-cash charge for proved property impairment, of which $15.6 million related to our offshore properties as a result of performance revisions in reserves and the decline in gas prices and production yield. The total non-cash proved property impairment recorded during the year ended December 31, 2020 was $164.4 million.

Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, with any such impairment charged to expense in the period. During the year ended December 31, 2020, we recorded a $4.3 million non-cash charge for unproved impairment expense related to undeveloped leases in our Central Oklahoma, Western Anadarko and Other Onshore regions. We recorded $2.6 million of this impairment expense in the first quarter of 2020, primarily related to leases we acquired from White Star and Will Energy in the fourth quarter of 2019, which were expiring in 2020, and we recorded $1.7 million of this impairment expense in the fourth quarter of 2020, due to leases expiring in 2021, all of which we have no plans to extend or develop as a result of the current commodity price environment and our continued focus on cost saving and production enhancing initiatives.

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Onshore Investments

Jonah Field – Sublette County, Wyoming

Our wholly-owned subsidiary, Contaro Company (“Contaro”), owns a 37% ownership interest in Exaro. As of December 31, 2020, we had invested approximately $46.9 million in Exaro, with no requirement to make any additional equity contributions, as our commitment to invest additional capital in Exaro expired on March 31, 2017. We account for Contaro’s ownership in Exaro using the equity method of accounting, and therefore, do not include its share of individual operating results, reserves or production in those reported in our consolidated results.

As of December 31, 2020, Exaro had 645 wells on production over its 5,760 gross acres (1,040 net acres), with a working interest between 14.6% and 32.5%. These wells were producing at a rate of approximately 2.5 MBoe/d, net to Contango, during the three months ended December 31, 2020. For the year ended December 31, 2020, we recognized a net investment gain of approximately $27,000, net of zero tax expense, as a result of our equity investment in Exaro. As of December 31, 2020, reserves attributable to our investment in Exaro were 2.6 MMBoe. See Note 11 - “Investment in Exaro Energy III LLC” for additional details related to this equity investment.

Title to Properties

From time to time, we are involved in legal proceedings relating to claims associated with ownership interests in our properties. We believe we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, and liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Detailed investigations, including a title opinion rendered by a licensed independent third-party attorney, are typically made before commencement of drilling operations.

We have granted mortgage liens on substantially all of our oil and natural gas properties to secure our Credit Agreement. These mortgages and the related Credit Agreement contain substantial restrictions and operating covenants that are customarily found in credit agreements of this type. See Note 13 to our Financial Statements - “Long-Term Debt” for further information.

Marketing and Pricing

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We derive our revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing oil and natural gas prices. We sell a portion of oil and condensate production to purchasers under sales agreements with primary terms of up to one year and our natural gas production to purchasers pursuant to sales agreements which contain a primary term of up to three years. The sale prices for oil are tied to industry standard posted prices, subject to negotiated price adjustments, while the sales prices for natural gas are tied to industry standard published index prices, subject to negotiated price adjustments

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We typically utilize commodity price hedge instruments to minimize exposure to declining prices on our oil, natural gas and natural gas liquids production, by using a series of swaps and/or costless collars. Unrealized gains or losses associated with hedges vary period to period, and will be a function of hedges in place, the strike prices of those hedges and the forward curve pricing for the commodities being hedged.

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We currently have derivative contracts in place to cover production periods through the first quarter of 2023, which include the hedges novated from Mid-Con and the additional hedges entered into in the first quarter of 2021, as discussed below. These contracts include oil hedges for 2.1 MMBbls of 2021 production with average floor prices of $54.85 per barrel and 1.4 MMBbls of 2022 production with average floor prices of $50.24 per barrel. For natural gas, our derivative contracts include 12.4 Bcf of 2021 production with average floor prices of $2.62 per MMBtu and 10.1 Bcf of 2022 production with average floor prices of $2.60 per MMBtu. Approximately 97% of our hedges are swaps, and we have no three-way collars or short puts.

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As of December 31, 2020, we had the following derivative contracts in place:

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In conjunction with the closing of the Mid-Con Acquisition in January 2021, we acquired the following additional derivative contracts via novation from Mid-Con:

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In the first quarter of 2021, we entered into the following additional derivative contracts:

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Historically, we have been dependent upon a few purchasers for a significant portion of our revenue. Our three largest purchasers contributed approximately 36% of our total production revenues for the year ended December 31, 2020. This concentration may increase our overall exposure to credit risk, and our purchasers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations could be materially adversely affected if one or more of our significant purchasers fails to pay us or ceases to acquire our production on terms that are favorable to us. However, we believe our current purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Competition

The oil and natural gas industry is highly competitive, and we compete with numerous other companies. Our competitors in the exploration, development, acquisition and production business include major integrated oil and natural gas companies as well as numerous independent companies, including many that have significantly greater financial resources.

The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties and obtaining purchasers and transporters for the oil and natural gas we produce. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by federal, state and local governments; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Governmental Regulations and Industry Matters

Industry Regulations

The availability of a ready market for oil, natural gas and natural gas liquids production depends upon numerous factors beyond our control. These factors include regulation of oil, natural gas and natural gas liquids production, federal, state and local regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, the amount of oil, natural gas and natural gas liquids 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 lack of an available natural gas pipeline in the area in which the well is located. State and federal regulations generally are intended to prevent waste of oil, natural gas and natural gas liquids, protect rights to produce oil, natural gas and natural gas liquids between owners in a common reservoir, control the amount of oil, natural gas and natural gas liquids produced by assigning allowable rates of production, and protect the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.

The following discussion summarizes the regulation of the U.S. oil and natural gas industry. Such statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not materially adversely affect our results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our operations may be subject.

Regulation of Oil, Natural Gas and Natural Gas Liquids Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in and the unitization

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or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project, if the operator owns less than 100% of the leasehold. In addition, state conservation laws, which establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil, natural gas and natural gas liquids we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and natural gas industry increases our costs of doing business and, consequently, affects our profitability. Inasmuch as such laws and regulations are frequently expanded, amended and interpreted, we are unable to predict the future cost or impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas

Federal legislation and regulatory controls have historically affected the price of natural gas produced by us, and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938 (the “NGA”), the Federal Energy Regulatory Commission (the “FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas, including all sales by us of our own production. As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. However, the Decontrol Act did not affect the FERC’s jurisdiction over natural gas transportation.

Section 1(b) of the NGA exempts gas gathering facilities from the FERC’s jurisdiction. We believe that the gas gathering facilities we own meet the traditional tests the FERC has used to establish a pipeline system's status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts. While we own some gas gathering facilities, we also depend on gathering facilities owned and operated by third parties to gather production from our properties, and therefore, we are affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates charged for gathering services, we also may be affected by these changes. Accordingly, we do not anticipate that we would be affected any differently than similarly situated gas producers.

Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit market manipulation by any person, including marketers, in connection with the purchase or sale of natural gas, and the FERC has issued regulations to implement this prohibition. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and derivative futures commodity markets including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. FERC holds substantial enforcement authority, including the ability to potentially assess maximum civil penalties of approximately $1.29 million per day per violation, subject to annual adjustment for inflation. CFTC also holds substantial enforcement authority, including the ability to potentially assess maximum civil penalties of up to approximately $1.21 million per violation or triple the monetary gain.

Under the 2005 Act, the FERC has also established regulations that are intended to increase natural gas pricing transparency through, among other things, new reporting requirements and expanded dissemination of information about the availability and prices of gas sold. For example, on December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit on May 1 of each year an annual report to FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704 as clarified in orders on clarification and rehearing. In addition, to the extent that we transport gas on interstate pipelines that are subject to FERC regulation, we are subject to FERC

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requirements related to use of such interstate capacity. Any failure on our part to comply with the FERC’s regulations could result in the imposition of civil and criminal penalties.

Our natural gas sales are affected by intrastate and interstate gas transportation regulation. Following the Congressional passage of the Natural Gas Policy Act of 1978 (the “NGPA”), the FERC adopted a series of regulatory changes that have significantly altered the transportation and marketing of natural gas. Beginning with the adoption of Order No. 436, issued in October 1985, the FERC has implemented a series of major restructuring orders that have required interstate pipelines, among other things, to perform “open access” transportation of gas for others, “unbundle” their sales and transportation functions, and allow shippers to release their unneeded capacity temporarily and permanently to other shippers. As a result of these changes, sellers and buyers of gas have gained direct access to the particular interstate pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. FERC’s policies regarding the interstate transportation of natural gas are subject to change from time to time, and such changes could impact access to markets, competition and the cost of doing business. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. We do not believe that we will be affected by any such new or different regulations materially differently than any other seller of natural gas with which we compete.

In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation, or “lighter handed” regulation, and the promotion of competition in the gas industry. There regularly are other legislative proposals pending in the federal and state legislatures that, if enacted, would significantly affect the natural gas industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. We do not believe that we will be affected by any such new legislative proposals materially differently than any other seller of natural gas with which we compete.

Oil Price Controls and Transportation Rates

Sales prices of oil, condensate and gas liquids by us are not currently regulated and are made at market prices. Our sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission (the “FTC”) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these regulations, including the ability to potentially assess maximum civil penalties of approximately $1.23 million per day per violation, subject to annual adjustment for inflation. Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.

The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of the transportation is through interstate common carrier pipelines whose transportation rates are subject to FERC regulation. FERC allows common carrier pipelines to establish rates via contract, traditional rate regulation, market rates or “index.” Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC’s regulation of oil and natural gas liquids transportation rates may tend to increase the cost of transporting oil and natural gas liquids by interstate pipelines, although the annual index rate adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with oil production from our oil producing operations.

There regularly are other legislative proposals pending in the federal and state legislatures that, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. We do not believe that we will be affected by any such new legislative proposals materially differently than any other seller of petroleum with which we compete.

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Environmental and Occupational Health and Safety Matters

Our oil and natural gas exploration, development and production operations are subject to stringent federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment, or otherwise relating to environmental protection. Numerous governmental authorities, including the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, which may cause us to incur significant capital expenditures or costly actions to achieve and maintain compliance. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the occurrence of delays, cancellations or restrictions in permitting or performance of projects and the issuance of orders enjoining some or all of our operations in affected areas. The public continues to have a significant interest in the protection of the environment. The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment, and thus any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly exploration, production and development activities, or waste handling, storage transport, disposal or remediation requirements could result in increased costs of our doing business and consequently affect our profitability. 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 or that such future compliance will not have a material adverse effect on our business and operating results.

The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund Law”, and similar state laws, impose strict joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These potentially responsible persons include the current or past owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property or natural resource damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate wastes that are subject to the federal Resource Conservation and Recovery Act, as amended (the “RCRA”), and comparable state statutes. The RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of nonhazardous and hazardous wastes, and the EPA and analogous state agencies stringently enforce the approved methods of management and disposal of these wastes. While the RCRA currently exempts certain drilling fluids, produced waters, and other wastes associated with exploration, development and production of oil and natural gas from regulation as hazardous wastes, allowing us to manage these wastes under RCRA’s less stringent non-hazardous waste requirements, we can provide no assurance that this exemption will be preserved in the future. Any removal of this exclusion could increase the amount of waste we are required to manage and dispose of as hazardous waste rather than non-hazardous waste, and could cause us to incur increased operating costs, which could have a significant impact on us as well as the oil and natural gas industry in general.

The federal Clean Air Act, as amended (the “CAA”), and comparable state laws restrict the emission of air pollutants from many sources and also impose various pre-construction, operating, monitoring and reporting requirements. These laws and 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. Obtaining permits has the potential to delay the development of oil and natural gas projects. 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.

There remains continued public, governmental and scientific attention regarding climate change, with the EPA having determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment. As a result, the EPA has adopted regulations under existing provisions of the CAA that, among other things, impose permit reviews and restrict emissions of GHGs from certain large stationary sources. These EPA regulations could adversely affect our operations and restrict, delay or halt our

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ability to obtain air permits for new or modified sources. Additionally, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including certain onshore and offshore production facilities, which include the majority of our operations. We are monitoring and annually reporting on GHG emissions from certain of our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that include consideration of cap-and-trade programs whereby major sources of GHG emissions are required to acquire and surrender emission allowances in return for emitting those GHGs, as well as carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. Although the United States formally withdrew from the Paris Agreement in 2020, the Biden Administration officially reentered the United States into the agreement in February 2021.  

Additionally, President Biden and the Democratic Party, which now controls Congress, have identified climate change as a priority, and it is likely that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, delaying or restricting oil and natural gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. For example, the acting Secretary of the Department of the Interior recently issued an order preventing staff from producing any new fossil fuel leases or permits without sign-off from a top political appointee, and President Biden recently announced a moratorium on new oil and natural gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. President Biden’s order also establishes climate change as a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms President Biden’s desire to establish the United States as a leader in addressing climate change, generally further integrates climate change and environmental justice considerations into government agencies’ decision making, and eliminates fossil fuel subsidies, among other measures.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future international, federal or state laws or regulations that impose reporting obligations on us with respect to, or require the elimination of GHG emissions from, our equipment or operations could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

The Federal Water Pollution Control Act, as amended (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. Any such discharge of pollutants into regulated waters is prohibited except in accordance with the terms of an issued permit. Spill prevention, control and countermeasure plan requirements under federal law 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. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The EPA and the U.S. Army Corps of Engineers released a rule to revise the definition of “waters of the United States,” or WOTUS, for all Clean Water Act programs, which went into effect in August 2015. However, in September 2019, the EPA repealed the 2015 rule, and in January 2020 finalized the Navigable Waters Protection Rule, which has generally been viewed as narrowing the scope of the WOTUS definition. Litigation in multiple federal district courts is currently challenging the repeal of the 2015 rule and the promulgation of the Navigable Waters Protection Rule.

The disposal of oil and natural gas wastes into underground injection wells are subject to the federal Safe Drinking Water Act, as amended (the “SDWA”), and analogous state laws. Our oil and natural gas exploration and production operations generate produced water, drilling muds and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations, and thus, those activities are subject to the SWDA. The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or analogous state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts

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the types and quantities that may be injected, and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. 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 alternative water supplies, property and natural resource damages and personal injuries. Furthermore, in response to a growing concern that the injection of produced water and other fluids into belowground disposal wells triggers seismic activity in certain areas, some states, including Texas and Oklahoma, where we operate, have imposed, and other states are considering imposing, additional requirements in the permitting or operation of produced water injection wells. In Texas, the Texas Railroad Commission (“TRC”) has adopted a final rule governing the permitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. In Oklahoma, the Oklahoma Corporation Commission issued various orders and regulations applicable to disposal operations in specific counties in Oklahoma in 2016. These rules require that disposal well operators, among other things, conduct additional mechanical integrity testing, make sure that their wells are not injecting wastes into targeted formations, and/or reduce the volumes of wastes disposed in such wells. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for produced water disposal. These existing and any new seismic requirements applicable to disposal wells that impose more stringent permitting or operational requirements could result in added costs to comply or, perhaps, may require alternative methods of disposing of produced water and other fluids, which could delay production schedules and also result in increased costs.

The federal Oil Pollution Act of 1990, as amended (the “OPA”), and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. The OPA applies to vessels, onshore facilities and offshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities and lessees and permittees of offshore leases may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. In January 2018, the federal Bureau of Ocean Energy Management raised the OPA’s damages liability cap to $137.7 million; however, while liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. The OPA requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill, and to prepare and submit for approval oil spill response plans. These oil spill response plans must detail the action to be taken in the event of a spill; identify contracted spill response equipment, materials, and trained personnel; and identify the time necessary to deploy these resources in the event of a spill. The OPA currently requires a minimum financial responsibility demonstration of between $35 million and $150 million for companies operating on the federal Outer Continental Shelf (“OCS”) waters, including the Gulf of Mexico. We are currently required to demonstrate, on an annual basis, that we have ready access to $35 million that can be used to respond to an oil spill from our facilities on the OCS. In addition, to the extent our offshore lease operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws.

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. We routinely use hydraulic fracturing techniques in many of our completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, or other similar state agencies, but several federal agencies have also asserted regulatory authority over, or conducted investigations that focus upon, certain aspects of the process, including a suite of proposed rulemakings and final rules issued by the EPA and the federal Bureau of Land Management (the “BLM”), which legal requirements, to the extent finalized and implemented by the agencies, may impose more stringent requirements relating to the composition of fracturing fluids, emissions and discharges from hydraulic fracturing, chemical disclosures, and performances of fracturing activities on federal and Indian lands. Congress has from time to time considered, but not enacted, legislation to provide for federal regulation or the banning of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process while, at the state level, several states, including Texas and Wyoming, 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. States could elect to

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prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local government may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If 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 restrictions, delays or cancellations in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling or completing wells. At various times during the past year, politicians have also proposed a ban of new leases for production of oil and gas on federal properties.

The National Environmental Policy Act, as amended (“NEPA”) is applicable to oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands administered by the BLM. NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Governmental permits or authorizations that are subject to the requirements of NEPA are required for exploration and development projects on federal and Indian lands. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

The federal Endangered Species Act, as amended (“ESA”), provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States and prohibits taking of endangered species. The ESA may impact exploration, development and production activities on public or private lands. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act, as amended. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of one or more settlements entered into by the U.S. Fish and Wildlife Service (the “FWS”), the agency is required to make a determination on listing of numerous species as endangered or threatened under the ESA by specified timelines. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures as well as time delays or limitations on or cancellations of our drilling program activities, which costs, delays, limitations or cancellations could have an adverse impact on our ability to develop and produce reserves.

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

The BOEM and the BSEE, each agencies of the U.S. Department of the Interior, have, over time, imposed more stringent permitting procedures and regulatory safety and performance requirements for wells in federal waters. For example, in 2016, the BOEM issued a Notice to Lessees and Operators (the “NTL #2016-N01”) that became effective in September 2016 and bolsters supplemental financial assurance requirements for the decommissioning of offshore wells, platforms, pipelines and other facilities whereas the BSEE has issued various regulations relating to the safe and environmentally responsible development of energy and mineral resources on the OCS that have resulted in more stringent requirements including, for example, well and blowout preventer design, workplace safety and corporate accountability. Additionally, states may adopt and implement similar or more stringent legal requirements applicable to exploration and production activities in state waters. Compliance with these more stringent regulatory restrictions, together with any uncertainties or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect, delay or cancel new drilling and ongoing development efforts. If the BOEM determines that increased financial assurance is required in connection with our offshore facilities but we are unable to provide the necessary supplemental bonds or other forms of financial assurance, the BOEM could impose monetary penalties or require our operations on federal leases to be suspended or cancelled. Also, if material spill incidents were to occur, the United States could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further

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safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which developments could have a material adverse effect on our business. Any of the offshore-related matters described above could have a material adverse effect on our business, financial condition and results of operations.

These regulatory actions, or any new rules, regulations or legal initiatives that may be adopted or enforced by the BOEM or the BSEE in the future could delay or disrupt our oil and natural gas exploration and production operations conducted offshore, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, and limit or cancel activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities or result in the suspension or cancellation of leases.

Moreover, under existing BOEM rules relating to assignment of offshore leases and other legal interests on the OCS, assignors of such interest may be held jointly and severally liable for decommissioning of OCS facilities existing at the time the assignment was approved by the BOEM, in the event that the assignee, or any subsequent assignee, is unable or unwilling to conduct required decommissioning. In the event that we, in the role of assignor, receive orders from the BOEM to decommission OCS facilities that one of our assignees, or any subsequent assignee, of offshore facilities is unwilling or unable to perform, we could incur costs to perform decommissioning, which costs could be material. If the BOEM determines that increased financial assurance is required in connection with our or any previously assigned offshore facilities but we are unable to provide the necessary supplemental bonds or other forms of financial assurance, the BOEM could impose monetary penalties or require our operations on federal leases to be suspended or cancelled.

See “Item 1A. Risk Factors” for further discussion on hydraulic fracturing; ozone standards; climate change, including methane or other GHG emissions; releases of regulated substances; offshore regulatory safety and environmental development requirements, and other aspects of compliance with legal or financial assurance requirements or relating to environmental protection, including with respect to offshore leases. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards or more stringent enforcement programs continue to evolve.

Other Laws and Regulations

Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of oil and natural gas including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.

Whereas the BLM administers oil and natural gas leases held by the Company on federal onshore lands, the BOEM administers the oil and natural gas leases held by the Company on federal offshore tracts on the OCS. The Office of Natural Resources Revenue (the “ONRR”) collects a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the ONRR changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers.

To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells, decommission or remove platforms and pipelines, and clear the seafloor of obstructions at the end of production (collectively, “decommissioning obligations”), the BOEM generally requires that lessees post supplemental bonds or other acceptable financial assurances that such obligations will be met. Historically, our financial assurance costs to satisfy decommissioning obligations have not had a material adverse effect on our results of operations; however, the BOEM continues to consider imposing more stringent financial assurance requirements on offshore operators on the OCS. For example, the BOEM issued NTL #2016-N01 that went into effect in September 2016 and augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to satisfy decommissioning obligations on the OCS. If the BOEM determines under this new NTL that a company does not satisfy the minimum requirements to qualify for providing self-insurance to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance. In June 2017, the BOEM extended indefinitely the start date for implementation of NTL #2016-N01. This extension

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currently remains in effect; however, the BOEM reserved the right to re-issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning obligations.  

The BOEM may elect to retain NTL #2016-N01 in its current form or may make revisions thereto and, thus, until the BOEM determines whether and to what extent any additional financial assurance may be required by us with respect to our offshore operations, we cannot provide assurance that such financial assurance coverage can be obtained. Moreover, the BOEM could in the future make other demands for additional financial assurances covering our obligations under sole liability properties and/or non-sole liability properties. In the event that we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require certain of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties. See “Item 1A. Risk Factors” for a further discussion on BOEM and its implementation of NTL #2016-N01.

Risk and Insurance Program

In accordance with industry practice, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from significant losses resulting from damages to, or the loss of, physical assets or loss of human life, and liability claims of third parties, including such occurrences as well blowouts and weather events that result in oil spills and damage to our wells and/or platforms. Our goal is to balance the cost of insurance with our assessment of the potential risk of an adverse event. We maintain insurance at levels that we believe are appropriate and consistent with industry practice, and we regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.

We continuously monitor regulatory changes and regulatory responses and their impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection at a level that we can afford considering the cost of insurance, against the potential and magnitude of disruption to our operations and cash flows. Changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico could lead to tighter underwriting standards, limitations on scope and amount of coverage and higher premiums, including possible increases in liability caps for claims of damages from oil spills.

Environmental, Health and Safety Program

Our Health, Safety and Environmental (“EHS”) Program is supervised by senior management to ensure compliance with all state and federal regulations. In support of the operating committee, we have contracted with J. Connor Consulting (“JCC”) to coordinate the regulatory process relative to our offshore assets. JCC is a regulatory consulting firm specializing in the offshore Gulf of Mexico. They provide preparation of incident response plans, safety and environmental services and facilitation of comprehensive oil spill response training and drills on behalf of oil and natural gas companies and pipeline operators.

Additionally, in support of our Gulf of Mexico operations, we have established a Regional Oil Spill Response Plan which has been approved by the BSEE. Our response team is trained annually and is tested through in-house spill drills. We have also contracted with O’Brien’s Response Management (“O’Brien’s”), who maintains an incident command center on 24 hour alert in Houston, Texas. In the event of an oil spill, the Company’s response program is initiated by notifying O’Brien’s of any reportable incident. While the Company response team is mobilized to focus on source control and containment of the spill, O’Brien’s coordinates communications with state and federal agencies and provides subject matter expertise in support of the response team.

We also have contracted with Clean Gulf Associates (“CGA”) to assist with equipment and personnel needs in the event of a spill. CGA specializes in onsite control and cleanup and is on 24-hour alert with equipment currently stored at eight bases along the gulf coast, from South Texas to East Louisiana. The CGA equipment stockpile is available to serve member oil spill response needs and includes open seas skimmers, shoreline protection boom, communications equipment, dispersants with application systems, wildlife rehabilitation and a forward command center. CGA has retainers with aerial dispersant and mechanical recovery equipment contractors for spill response.

In addition to our membership in CGA, the Company has contracted with Wild Well Control for source control at the wellhead, if required. Wild Well Control is one of the world’s leading providers of firefighting and well control services.

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We also have a full-time health, safety and environmental professional who supports our operations and oversees the implementation of our onshore EHS policies.

Safety and Environmental Management System

We have developed and implemented a Safety and Environmental Management System (“SEMS”) to address oil and natural gas operations in the OCS, as required by the BSEE. Our SEMS identifies and mitigates safety and environmental hazards and the impacts of these hazards on design, construction, start-up, operation, inspection and maintenance of all new and existing facilities. The Company has established goals, performance measures, training and accountability for SEMS implementation. We also provide the necessary resources to maintain an effective SEMS, and we review the adequacy and effectiveness of the SEMS program annually. Company facilities are designed, constructed, maintained, monitored and operated in a manner compatible with industry codes, consensus standards and all applicable governmental regulations. We have contracted with Island Technologies Inc. to coordinate our SEMS program and to track compliance for production operations.

The BSEE enforces the SEMS requirements through regular audits. Failure of an audit may result in an Incident of Non-Compliance and could ultimately result in the assessment of civil penalties and/or require a shut-in of our Gulf of Mexico operations if not resolved within the required time.

Employees

On December 31, 2020, we had 205 full-time employees, of which 133 were field personnel. We have been able to attract and retain a talented team of industry professionals that have been successful in achieving significant growth and success in the past. Our employees play an important role in positioning the Company to adequately manage and develop our existing assets and also to increase our proved reserves and production through exploitation of our existing asset base, as well as the continuing identification, acquisition and development of new growth opportunities. Safety is one of our greatest priorities, and we have a dedicated internal group that has implemented safety management systems, procedures and tools to help protect our employees, contractors and environment. None of our employees are covered by collective bargaining agreements. We believe our relationship with our employees is good.

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In addition to our employees, we use the services of independent consultants and contractors to perform various professional services. As a working interest owner, we rely on certain outside operators to drill, produce and market our oil and natural gas where we are a non-operator. In prospects where we are the operator, we rely on drilling contractors to drill and sometimes rely on independent contractors to produce and market our oil and natural gas. In addition, we frequently utilize the services of independent contractors to perform field and on-site drilling and production operation services and independent third-party engineering firms to evaluate our reserves.

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Corporate Offices

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Our corporate headquarters office is located at 111 E. 5^th Street, Suite 300 in Fort Worth, Texas. The Fort Worth lease was entered into effective February 1, 2021 and expires on July 31, 2023. We also have corporate offices at 717 Texas Avenue in downtown Houston, Texas, under a lease that expires on March 31, 2023 and at 301 NW 63rd Street in Oklahoma City, Oklahoma, which we acquired through the White Star Acquisition, under a lease that expires on January 31, 2022. Rent, including parking, related to these office spaces was approximately $0.5 million for the year ended December 31, 2020.

Available Information

We file or furnish annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us. Filings made with the SEC electronically are publicly available through the SEC's website at http://www.sec.gov, and we make these documents available free of charge at our website at http://www.contango.com as soon as reasonably practicable after they are filed or furnished with the SEC. This report on Form 10-K, including all exhibits and amendments, has been filed electronically with the SEC. We intend to use our website as a Regulation FD compliant means of making public disclosures. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this report.

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Seasonal Nature of Business

The demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mild winters or cooler summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand.

Item 1A. Risk Factors

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating the Company, as well as all other information presented in this Form 10-K. An investment in the Company is subject to risks inherent in our business, and the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we may currently deem immaterial, may become important factors that harm our business, results of operations and financial condition in the future. The trading price of the shares of the Company is affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in the Company may decrease, resulting in a loss.

Risks Related to Our Business

The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our business, financial position, results of operations, and/or cash flows will depend on future developments, which are highly uncertain and cannot be predicted.

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The COVID-19 pandemic has resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world and has created significant volatility, uncertainty and turmoil in the oil and gas industry. This has led to a significant global oversupply of oil and a subsequent substantial decrease in oil prices. While global oil producers, including the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing nations reached an agreement to cut oil production in April 2020, downward pressure on, and volatility in, commodity prices has remained and could continue for the foreseeable future, particularly given concerns over available storage capacity for oil, which have negatively affected and are expected to continue to negatively affect our cash flow, liquidity and financial position. In response to the decrease in commodity prices, beginning in the second quarter of 2020, we suspended any further plans for operated onshore and offshore drilling in 2020. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 pandemic, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when, or to what extent, the negative effects of COVID-19 on the world and domestic economies, and on our industry and Company, will improve, or when oil prices will improve and stabilize.

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While there has been a modest recovery in oil prices, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which will ultimately depend on various factors and consequences beyond our control, such as the duration and spread of the pandemic, including the impact of coronavirus mutations and resurgences, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, the development, availability and public acceptance of effective treatments or vaccines and the duration, timing and severity of the impact on domestic and global oil demand, the availability of personnel, equipment, and services critical to our ability to operate our properties, and how quickly, and to what extent, normal economic and operating conditions can resume. The COVID-19 pandemic may also precipitate or intensify the risks described in the risk factors disclosed in our 2020 Form 10-K.

We have no ability to control the market price for oil, natural gas and NGLs. Oil, natural gas and NGL prices fluctuate widely, and a continued substantial or extended decline in oil and natural gas prices would adversely affect our revenues, profitability and growth and could have a material adverse effect on our business, results of operations and financial condition.

Our revenues, profitability and future growth depend significantly on oil, natural gas and NGL prices. Oil prices, natural gas prices and NGL prices remained low during the past several years relative to the high prices in 2014 and have been significantly adversely impacted due to the effects of the COVID-19 pandemic, despite recent recovery. The markets for these commodities are volatile and prices received affect the amount of future cash flow available for capital expenditures, repayment of indebtedness and our ability to raise additional capital. Lower prices also affect the

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amount of oil, natural gas and NGLs that we can economically produce. Prices fluctuate and decline based on factors beyond our control. Factors that can cause price fluctuations and declines include: