“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.BusinessBusiness    

Overview

We are a Houston,Fort Worth, Texas based independent oil and natural gas company, with regional offices in Oklahoma City and Stillwater, Oklahoma.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, Oklahoma,Wyoming and Louisiana and Wyoming properties 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. On June 14, 2019,2000, and, following approval by our stockholders at thein 2019, annual meeting of stockholders, we changed our state of incorporation from the State of Delaware to the State of Texas.

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. See Note 4 – “Acquisitions and Dispositions” for more information.

In September 2019, we entered into unrelated purchase agreements with Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) to purchase certain producing assets and undeveloped acreage, primarily in Oklahoma. These transactions closed during the three months ended December 31, 2019. See Note 4 – “Acquisitions and Dispositions” for more information.

The following table lists our primary producing areas as of December 31, 2019:2020:

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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

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. As of December 31, 2019, we were producing from seventeen wells over our approximate 18,600 gross (8,000 net) acre position in West Texas, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations. In December 2019, we began completion operations on the fourth NE Bullseye well, which began producing in January 2020. AlsoAs of December 31, 2020, we were producing from 18 wells over our approximate 16,200 gross (7,500 net) acre position in December 2019, we completedWest Texas, prospective for the Wolfcamp A, Wolfcamp B and brought on production a Garfield County, Oklahoma well in our Central Oklahoma region, which we acquired in connection with the White Star acquisition. See Note 4 – “Acquisitions and Dispositions” for more information. 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 finishedconcluded our 2019 drilling program, which was designed to only preserve core areas of our West Texas play, and thereafterplay. 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. ForThese 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 lowchallenging 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 cost reduction and future development of the unprovedundeveloped 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 our 2020 drillingthat program to only address leasehold commitmentsdrilling and workover projects that we believe may provide compelling returns in this current commodity price environment or where necessary to preserve corestrategic acreage in our existingcore areas, while complementing that strategy with onesimultaneously continuing to two relatively low cost, high-potential offshore exploratory wells on prospects recently acquired from Juneau. See Note 4 – “Acquisitions and Dispositions” for more information. We will continue to

make balance sheet strength a priority in 20202021 as we utilize excess cash flow to reduce debt and increase our capacity to quickly react to acquisition opportunities.

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We are also currently undertaking an extensive review of all of our producing areas in light of the commodity price environment, and where determined justified and operationally feasible, we plan to potentially shut in or curtail unhedged production. Because of our low debt profile and borrowing cost of capital, we believe we may be able to temporarily shut in or curtail higher cost production when there is a decline in the commodity markets. We are also currently re-evaluating the economic justification for proceeding with the production-enhancing workover program originally scheduled for the first half of 2020. The limited onshore development drilling we planned for 2020 is also being re-evaluated. 

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. During the year ended 2018,In 2020, we sold certain Eagle Ford Shale assetsproducing and non-producing properties located in Karnes County, Texas for $21.0 million; Gulf Coast conventional assets in Southeast Texas for $6.0 million,our Central Oklahoma and Gulf Coast conventionalWestern Anadarko regions. These non-core, marginally economic properties were a minor portion of the value of properties acquired from Will Energy and unconventional assets in South Texas for $0.9 million. In December 2018, we alsoWhite Star and were sold our offshore Vermilion 170 property in exchange for a retained overriding royalty interest (“ORRI”)approximately $0.5 million in the well, the buyer’s assumption of the pluggingcash and abandonment obligation and an ORRI in any future wells drilled by the buyer on two nearby prospects that would produce through this platform. During the year ended 2019, we sold minor, non-core operated assets located in Lavaca and Wharton counties, Texas and Frio and Zavala counties, Texas, both of which sales were in exchange for the buyers’ assumption of the plugging and abandonment liabilities of theand revenue held in suspense on those properties. WeThe Company recorded a gain of $0.6$4.4 million after removalas a result of the buyers’ assumption of the asset retirement obligations associated with these propertiesthe sold in 2019.properties.

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In November 2018, we completed an underwritten public offering of 8,596,068 shares of our common stock for net proceeds of approximately $33.0 million, which were used to reduce borrowings under our former credit facility, fund the initial purchase of the NE Bullseye acreageProduction and provide funding for our 2019 capital expenditure program.

In September 2019, we completed an underwritten public offering (the “September Public Offering”) of 51,447,368 shares of common stock (of which 5,524,498 were reissued treasury shares) for net proceeds of approximately $46.2 million, after deducting the underwriting discount and fees and expenses. Net proceeds from the September Public Offering and concurrent Series A Private Placement (as defined below) were used to fund the cash portion of the purchase price for the Will Energy acquisition and to reduce borrowings under our former revolving credit facility.

In conjunction with the September Public Offering, we also entered into a purchase agreement with affiliates of John C. Goff, a director and significant shareholder, and current chairman, of the Company, to issue and sell in a private placement (the “Series A Private Placement”) 789,474 shares of Series A contingent convertible preferred stock, which resulted in net proceeds of approximately $7.5 million.

In November 2019, we completed a private placement of 1,102,838 shares of Series B contingent convertible preferred stock, which resulted in net proceeds of approximately $21.0 million (the “Series B Private Placement”). Net proceeds from the Series B Private Placement were used to fund a portion of the purchase price and related transaction expenses for the White Star acquisition.

In the fourth quarter of 2019, we obtained approval from the holders of a majority of the voting power of the Company’s capital stock to increase the number of common shares authorized for issuance from 100 million to 200 million common shares, at which timethe Series A preferred shares automatically converted into 7,894,740 shares of

The following summary table sets forth certain information with respect to the proved reserves attributable to our equity methodequity-method investment in Exaro, as of December 31, 2019,2020, 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, 2019:2020:

Properties

Offshore Gulf of Mexico

As of December 31, 2019,2020, 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 five producing federal and two producing state of Louisianaseven company-operated wells in the shallow waters of the GOM.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, 20192020 and average daily offshore production sales for the year ended December 31, 2019:2020:

Acquisition. As of December 31, 2019,2020, the Central Oklahoma region included approximately 743,800629,100 gross (286,700(257,700 net) acres, proved reserves of 133.5 Bcfe (58%15.4 MMBoe (54% oil/liquids) and 778674 gross (449.6(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 acquisitionsAcquisition 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, 2019,2020, the Western Anadarko region included approximately 303,200274,600 gross (167,200(144,500 net) acres, proved reserves of 47.1 Bcfe (61% gas)4.9 MMBoe (47% oil/liquids) and 592400 gross (348.7(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

Since July 2016, weWe and our 50% non-operated working interest partner in the Southern Delaware Basin have increased our leasehold footprint fromown approximately 5,000 undeveloped16,200 gross acres (7,500 net acres to Contango, to approximately 8,000 acres, net to Contango.Contango). As of December 31, 2019,2020, we estimate that we have net proved reserves of 43.3 Bcfe (75%8.3 MMBoe (87% oil, 90%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 the potential drilling locations on this acreagewhich we believe can accommodate 10,000 foot laterals.

During the three months ended December 31, 2019, we brought three wells onlinelaterals that could provide a basis for future development and reserve growth in a more favorable and stable oil price environment. Included in the Southern Delaware Basin,68 gross locations are 32 proved undeveloped locations and 36 unbooked locations. If the Iron Snake #1H,recent improvement in oil prices is sustained, some capital could be allocated to the Breakthrough State #1 H and the Old Ironside #1H, alldrilling of which are locatedproved undeveloped locations in NE Bullseye. In January 2020, we brought one additional NE Bullseye well online, the State Spearhead #1H. NE Bullseye is expected to be a more productive and higher oil cutthis area that our Bullseye area and will be the focus of future capital spending in the area when we decide to become more aggressive in allocating capital to our drilling program.

Our South Texas area includes properties in the Dimmitt and Zavala counties, part of this area, which we believeinclude approximately 16,100 gross (6,600 net) acres ofthat we believe to be prospective for the Buda, Georgetown and Eagle Ford Shale plays.plays in an improved price environment. Our South Texas area also includes approximately 17,50014,300 gross (8,400(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 5.9 Bcfe (54% gas)1.3 MMBoe (44% oil/liquids) with 5139 gross (23.2(17.6 net) producing wells, as of December 31, 2019.2020.

Our East Texas area includedincludes approximately 5,900 gross (3,600 net) acres primarily in San Augustine County, with proved reserves of 0.9 Bcfe (84% gas)0.2 MMBoe (26% oil/liquids) and 8 gross (4.7 net) wells producing wells. We believe that the further exploitation of our acreage in the Haynesville, Mid-Bossier andand/or James Lime formations may provide long-term natural gas reserve and production growth potential in the future.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 lowchallenging 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.

In 2018, we commenced a program to rationalize our minor, non-core assets located in South and Southeast Texas. We sold Eagle Ford Shale assets in Karnes County, Texas for $21.0 million; Gulf Coast conventional assets in Southeast Texas for $6.0 million, and Gulf Coast conventional and unconventional assets in South Texas for $0.9 million. In 2019, we sold certain non-core operated assets located in Lavaca and Wharton counties, Texas and Frio and Zavala counties, Texas, respectively, in exchange for the buyers’ assumption of the plugging and abandonment liabilities of the sold properties. In addition to the cash proceeds received for the divestitures noted, we also were successful in reducing our responsibility for asset retirement obligations by a total of $0.8 million and $8.6 million (undiscounted net) in 2019 and 2018, respectively.

Louisiana

As of December 31, 2019,2020, the estimated proved reserves for our Louisiana properties were 6.7 Bcfe (40% oil)0.5 MMBoe (56% oil/liquids) primarily related to the properties we acquired in the Will Energy acquisition.Acquisition.

Wyoming

In 2015, we drilled the first of three successful wells in this area targeting the Muddy Sandstone formation. As a result of drilling these wells, we have satisfied the right to earn 35,000 net acres, of which approximately 27,800 net acres we still control. However, approximately 70% of such acreage will expire within the next three years if no drilling activity is conducted. 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, 2019, the2020, our Wyoming area includes approximately 33,200 gross (23,000 net) net acres with estimated proved reserves for this area were 1.7 Bcfe (100%of 0.1 MMBoe (91% oil). as of December 31, 2020.

Under US GAAP, an impairment charge is required when the unamortized capital cost of a field within the Company’s proved property base exceeds the risked estimated future net cash flows from the proved, probable and possible reserves for that field. In 2019, we recognized non-cash unproved impairment expense of approximately $9.2 million related primarily to lease expirations, and near-term expirations, in the Bullseye area of our West Texas region.

If oil or natural gas prices continue to decline further from those prices in effect at December 31, 2019, we may be required to record additional non-cash impairment in the future, thereby impacting our financial results for that period.

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, 2019,2020, 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, 2019,2020, Exaro had 648645 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 18 Mmcfe/2.5 MBoe/d, net to Contango.Contango, during the three months ended December 31, 2020. For the year ended December 31, 2019, the Company2020, we recognized a net investment gain of approximately $1.0 million,$27,000, net of zero tax expense, as a result of itsour equity investment in Exaro. As of December 31, 2019,2020, reserves attributable to our investment in Exaro were 23.0 Bcfe.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 partythird-party attorney, are typically made before commencement of drilling operations.

We have granted mortgage liens on substantially all of our oil and natural gas and oil 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.

As of December 31, 2019,2020, we had the following derivative contracts in place:

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