UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the fiscal year ended December 31 , 2020
OR
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from to
Commission file number 001-37907
| (Exact name of registrant as specified in its charter) | ||||||||
| (State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) | ||||||||||
| (Address of principal executive offices) | (Zip Code) | ||||||||||
(Registrant’s telephone number, including area code)
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||||||||
| Title of each class | Trading Symbol(s) | Name of exchange on which registered | ||||||||||||
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of Section 15(d) of the Act. Yes ☐ No x
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 x No ☐
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 x No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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.
| Large accelerated filer | ☐ | Accelerated Filer | ☐ | Emerging growth company | |||||||||||||
| x | Smaller reporting company | ||||||||||||||||
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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of the securities under a plan confirmed by a court. Yes x No ☐
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. ☐
The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $9.7 million as of June 30, 2020, (based on the last sale price of such stock as quoted on the Pink Open Market).
The total number of shares of common stock, par value $0.01 per share, outstanding as of March 15, 2021 was 25,697,136 .
DOCUMENTS INCORPORATED BY REFERENCE
EXTRACTION OIL & GAS, INC.
TABLE OF CONTENTS
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1
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report contains “forward-looking statements.” All statements, other than statements of historical facts, included or incorporated by reference herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in this report and our other filings with the Securities and Exchange Commission for further information on risk and uncertainties that could affect our business, financial condition, results of operations and cash flows. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:
•our ability to execute on our business strategy following emergence from bankruptcy;
•the COVID-19 pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters;
•federal and state regulations and laws;
•capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;
•risks and restrictions related to our debt agreements;
•impact of political and regulatory developments in Colorado, particularly with respect to additional permit scrutiny;
•our ability to use derivative instruments to manage commodity price risk;
•realized oil, natural gas and NGL prices as well as the volatility and widening of differentials;
•a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGL and the availability of capital;
•asset impairments from commodity price declines;
•the willingness of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels;
•unsuccessful drilling and completion activities and the possibility of resulting write-downs;
•geographical concentration of our operations;
•constraints in the DJ Basin of Colorado with respect to gathering, transportation and processing facilities and marketing;
•our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in commercially viable quantities;
•seasonal weather conditions;
•shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;
•adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;
•incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of such acquired properties;
•drilling operations associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;
•limited control over non-operated properties;
•title defects to our properties and inability to retain our leases;
•our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;
•our ability to retain key members of our senior management and key technical employees;
•cost of pending or future litigation;
•risks relating to managing our growth, particularly in connection with the integration of significant acquisitions;
•impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;
•changes in tax laws;
•effects of competition; and
•the outbreak of communicable diseases such as coronavirus.
Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGL 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 NGL that are ultimately recovered.
All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Annual Report. Except as required by law, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.
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GLOSSARY OF OIL AND GAS TERMS
Unless indicated otherwise or the context otherwise requires, references in this Annual Report on Form 10-K (“Annual Report”) to the “Company,” “Extraction,” “us,” “we,” “our,” or “ours” or like terms refer to Extraction Oil & Gas, Inc., together with its consolidated subsidiaries.
The terms defined in this section are used throughout this Annual Report:
“Bankruptcy Code” means title 11 of the United States Code, 11 U.S.C. §§ 101–1532, as amended.
“Bankruptcy Court” means the United States Bankruptcy Court for the District of Delaware.
“Bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
“Bbl/d” means Bbl per day.
“BOE” means barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
“BOE/d” means BOE per day.
“Btu” means one British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.
“Chapter 11 Cases” means when used with reference to a particular Debtor, the case for that Debtor filed under chapter 11 of the Bankruptcy Code in the Bankruptcy Court and when used with reference to all the Debtors, the procedurally consolidated chapter 11 cases filed by the Debtors in the Bankruptcy Court.
“CIG” means Colorado Interstate Gas, which is calculated as NYMEX Henry Hub index price less the Rocky Mountains (CIGC) Inside FERC fixed price.
“Completion” means the installation of permanent equipment for the production of oil or natural gas.
“Confirmation Order” means the order confirming the Sixth Amended Joint Chapter 11 Plan of Reorganization of Extraction Oil & Gas, Inc. and its Debtor Affiliates, [Docket No. 1509] entered by the Bankruptcy Court on December 23, 2020.
“Debtors” means the Company, together with all of its direct and indirect subsidiaries that have filed the Chapter 11 Cases.
“Dekatherms” means a unit of energy used primarily to measure natural gas equal to 1,000,000 Btus (MMBtu).
“Developed acreage” means the number of acres that are allocated or assignable to producing wells or wells capable of production.
“Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.
“Emergence Date” the first date, January 20, 2021, upon which all conditions precedent to the effectiveness of the Plan have been satisfied or waived in accordance with the Plan and no stay of the Confirmation Order is in effect.
“Exploratory well” means a well drilled either (a) in search of a new and as yet undiscovered pool of oil or gas or (b) with the hope of significantly extending the limits of a pool already developed (also known as a “wildcat well”).
“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
“Fracturing” or “hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases effective permeability and porosity.
“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.
“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working interest.
“Henry Hub” means Henry Hub index. Natural gas distribution point where prices are set for natural gas futures contracts traded on the NYMEX.
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“Horizontal drilling” or “horizontal well” means a wellbore that is drilled laterally.
“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.
“MBbl” One thousand barrels of oil, condensate or NGL.
“MBoe” One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
“Mcf” is an abbreviation for “1,000 cubic feet,” which is a unit of measurement of volume for natural gas.
“MMBtu” One million Btus.
“MMcf” is an abbreviation for “1,000,000 cubic feet,” which is a unit of measurement of volume for natural gas.
“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.
“Net revenue interest” means all of the working interests less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.
“NGL” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.
“Overriding royalty” means an interest in the gross revenues or production over and above the landowner’s royalty carved out of the working interest and also unencumbered with any expenses of operation, development, or maintenance.
“Petition Date” means June 14, 2020, the date on which the Debtors commenced the Chapter 11 Cases.
“Plan” means the Sixth Amended Joint Chapter 11 Plan of Reorganization of Extraction Oil & Gas, Inc. and its Debtor Affiliates, attached as Exhibit A to the Confirmation Order.
“Productive well” means a well that is producing oil or natural gas or that is capable of production.
“Prospect” means a geological area which is believed to have the potential for oil and natural gas production.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved reserves” means those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“Proved undeveloped reserves” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“PV-10 value” means the present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-
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property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.
“Reasonable certainty” means a high degree of confidence that the reserves quantities will be recovered, when a deterministic method is used. A high degree of confidence exists if the reserves quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.
“Reserve life” represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Restructuring” means the financial restructuring of our debt and equity interests as of the date of the Plan, and certain other obligations pursuant to the Plan.
“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.
“SEC” means the Securities and Exchange Commission.
“SEC pricing” means the price per Bbl for oil or per MMBtu for natural gas as calculated from the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months.
“Seismic data” means an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation.
“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves.
“Undeveloped leasehold acreage” means the leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains estimated net proved reserves.
“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wattenberg Field” means the Greater Wattenberg Area within the Denver-Julesburg Basin of Colorado as defined by the Colorado Oil and Gas Conservation Commission, which are the lands from and including Townships 2 South to 7 North and Ranges 61 West to 69 West, Six Principal Median.
“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.
“WTI” means the price of West Texas Intermediate oil on the NYMEX.
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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Company Overview
We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. The Wattenberg Field has been producing since the 1970s and is a premier North American oil and natural gas basin characterized by high recoveries relative to drilling and completion costs, high initial production rates, long reserve life and multiple stacked producing horizons. We have assembled, as of December 31, 2020, approximately 140,000 net acres of large, contiguous acreage blocks in some of the most productive areas of the DJ Basin, indicated by the results of our horizontal drilling program and the results of offset operators, which we refer to as the “Core DJ Basin.” We believe our acreage in the Core DJ Basin has been significantly delineated by our own drilling success and by the success of offset operators, providing confidence that our inventory is operationally relatively repeatable and will continue to generate economic returns.
We were founded in November 2012 with the objective of becoming a Wattenberg focused company with acreage that has (i) low geologic development risk as a result of being within the vicinity of other successful wells drilled by other oil and gas companies, (ii) limited vertical well drainage relative to offset operators in a field with significant historical vertical activity, and (iii) higher oil content than was traditionally targeted when many operators first established their position in the field seeking natural gas production. We believe these characteristics enhance our horizontal production capabilities, recoveries and economic results. Our drilling economics are further enhanced by our ability to drill longer laterals due to our large contiguous acreage position, which our management team built through organic leasing and a series of strategic acquisitions. We operated 99% of our horizontal production for the year ended December 31, 2020 and maintain control of a large majority of our drilling inventory.
For the year ended December 31, 2020, we drilled 37 gross wells with an average lateral length of 2.3 miles and completed 45 gross wells with an average lateral length of 2.4 miles, all of which were horizontal wells in the DJ Basin. During 2020, we laid down both or our rigs. During 2021, we began using a rig again and are currently running a one-rig program. Our 2021 capital budget anticipates a one-rig drilling program we expect to operate most of the year. Our average net daily production during the fourth quarter and year ended December 31, 2020 was 82,944 BOE/d and 88,907 BOE/d, respectively.
The following table provides summary information regarding our proved reserves as of December 31, 2020, and our average net daily production for the year ended December 31, 2020.
Estimated Total Proved Reserves (1) | Average Net | |||||||||||||||||||||||||||||||||||||||||||||||||
| Oil | Natural Gas | NGL | Total | % | % | % | Production | R/P Ratio | ||||||||||||||||||||||||||||||||||||||||||
| (MBbls) | (MMcf) | (MBbls) | (MBoe) | Oil | Liquids (2) | Developed | (BOE/d) (1)(3) | (Years) (4) | ||||||||||||||||||||||||||||||||||||||||||
| 45,392 | 369,534 | 38,895 | 145,875 | 31 | % | 58 | % | 77 | % | 88,907 | 4.5 | |||||||||||||||||||||||||||||||||||||||
(1) Includes de minimis reserves and production attributable to properties in our Other Rockies Area. Please see “—Other Properties.”
(2) Includes both oil and NGL.
(3) Average net daily production. Consisted of approximately 39% oil, 37% natural gas and 24% NGL.
(4) Represents the number of years proved reserves would last assuming production continued at the average rate for the year ended December 31, 2020. Because production rates naturally decline over time, the R/P Ratio is not a useful estimate of how long properties should economically produce.
Our Properties
Core DJ Basin
Our current operations are located in the DJ Basin, primarily in the Wattenberg Field where we target the oil and liquids-weighted Niobrara and Codell formations. As of December 31, 2020, our position in the Core DJ Basin consisted of approximately 140,000 net acres.
Our estimated proved reserves at December 31, 2020 were 145.9 MMBoe. As of December 31, 2020, we had a total of 1,322 gross wells capable of producing, of which 841 were horizontal wells. The vertical wells we operate primarily serve to hold leases until we can drill more efficient horizontal wells on acreage we lease. Therefore, production from vertical wells
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does not represent a material amount of our current production and is anticipated to decline as a percentage of total production in the future as we drill more horizontal wells. Our working interest for all wells capable of producing averages approximately 79% and our net revenue interest is approximately 65%.
As of December 31, 2020, we had an identified drilling inventory of approximately 65 gross (48 net) proved undeveloped horizontal drilling locations with varying lateral lengths on our acreage with average gross drill and complete well costs of $4.2 million. During 2020, we drilled 37 gross operated horizontal wells and completed 45 gross operated horizontal wells.
Other Properties
We hold approximately 96,700 net acres outside of the Core DJ Basin, which we refer to as our “Other Rockies Area,” that we believe is prospective for many of the same formations as our properties in the Core DJ Basin. As of December 31, 2020, there were de minimis proved reserves associated with this acreage.
2021 Capital Budget
Our 2021 capital budget for the drilling and completion of operated and non-operated wells is approximately $140 million to $180 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 34 gross operated wells, complete 49 gross operated wells and turn-in-line 44 gross operated wells with estimated lateral lengths of 2.2 miles. Our 2021 capital budget anticipates a one-rig drilling program we expect to operate most of the year.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer or accelerate a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.
Recent Developments
Emergence from Chapter 11 Bankruptcy
On June 14, 2020, we commenced voluntary cases under chapter 11 of title 11 (“Chapter 11”) of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors’ Chapter 11 cases are being jointly administered under the caption In re Extraction Oil & Gas, Inc., et al. (the “Chapter 11 Cases”). On December 23, 2020, we filed the Sixth Amended Joint Plan of Reorganization of Extraction Oil & Gas, Inc. (the “Plan”) pursuant to Chapter 11 of the Bankruptcy Code. The Bankruptcy Court also entered an order confirming the Plan. The Plan and the Confirmation Order were filed as Exhibits 2.1 and 99.1 to our Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission on December 30, 2020. On January 20, 2021 (the “Emergence Date”) the Plan became effective in accordance with its terms and we emerged from the Chapter 11 Cases. Please see Note 1 — Business and Organization in Part II, Item 8. Financial Information of this Annual Report for information on the Plan and emergence from Chapter 11 bankruptcy and discussion of our RBL Credit Facility and capital activity associated with emergence from the Chapter 11 Cases.
Elevation Gathering Agreements
In April 2020, pursuant to an amendment to the Elevation Gathering Agreements made in April 2019 (as discussed in Note 16 — Commitment and Contingencies in Part II, Item 8. Financial Information of this Annual Report) Elevation asserted that Extraction had missed the deadline for completion of additional gathering facilities and, therefore, that Extraction must make a payment to Elevation in the amount of 135% of all costs incurred by Elevation as of such date for the development and construction of such additional gathering facilities. On April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020.
On December 15, 2020, the Company and Elevation reached an agreement regarding amendments to the gathering agreements and the settlement of all outstanding claims. As part of the settlement, we will pay Elevation $38.4 million in cash over 24 months, and Elevation submitted an unsecured claim of $80.0 million with the Bankruptcy Court. The agreement released certain areas from future dedication, provided a reduction in certain gathering fees, a reduction in the number of wells
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subject to the drilling commitment, and an extended term in order to satisfy the drilling commitment. The Company also relinquished the nominal common interest ownership it had in Elevation. The Company had previously accrued $46.8 million and $4.2 million of accrued interest related to the aforementioned alleged breach in contract. During the third quarter of 2020, the Company accrued an additional $68.7 million within liabilities subject to compromise on the consolidated balance sheets and in reorganization items, net on the consolidated statements of operations.
Rejection and Renegotiation of Midstream Contracts
During the third and fourth quarters of 2020, the majority of our material midstream contracts were renegotiated or rejected by the Bankruptcy Court as part of the Chapter 11 Cases. As a result of these renegotiated or rejected contracts, the Company eliminated the majority of its minimum volume commitments as described in Note 16 — Commitment and Contingencies — Delivery Commitments in Part II, Item 8. Financial Information of this Annual Report and accrued $550.5 million within liabilities subject to compromise on the consolidated balance sheets as of December 31, 2020 and in reorganization items, net on the consolidated statements of operations for the year ended December 31, 2020.
NASDAQ Delisting and Relisting
Our common stock was traded on the NASDAQ Global Select Market (the “NASDAQ”) under the symbol “XOG” prior to June 25, 2020. On June 16, 2020, we received a letter from the NASDAQ notifying us that, as a result of the Chapter 11 Cases and in accordance with NASDAQ rules, our securities would be delisted at the opening of business on June 25, 2020. On June 25, 2020, our common stock began to be quoted on the Pink Open Market under the symbol “XOGAQ”. In connection with our emergence from bankruptcy, our common stock was relisted on the NASDAQ Global Select Market on January 21, 2021 trading under the symbol “XOG.”
COVID-19 Outbreak and Global Industry Downturn
The recent worldwide outbreak in several countries, including the United States, of a highly transmissible and pathogenic coronavirus (“COVID-19”) and the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19 have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. Decreased demand from much of the United States being on lockdown to prevent the spread of COVID-19 caused domestic storage capacity to begin to fill up during March and April of 2020 causing further price declines and ultimately causing oil prices to plummet. More recently, however, reduction in oil and gas activity as a result of the COVID-19 pandemic has resulted in a decrease of production as fewer oil wells are drilled, which has led to a contraction in domestic oil and gas supply. Lower levels of supply have pushed current and forecasted oil and gas prices higher, which we expect to have a positive impact on our results of operations and cash flows. We expect that the reduction in drilling activity and rig counts may contribute to a shortage in the supply of oil and natural gas in the future, which could result in higher oil and gas prices. As a result, although oil and gas prices were on average lower in 2020 than 2019, oil and gas prices trended higher after the effects of the COVID-19 pandemic began to take hold and slow oil production towards the middle of 2020.
The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to such operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected) and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Center for Disease Control. In addition, most of our non-operational employees are now working remotely. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak.
Due to the decline in crude oil prices in 2020 and ongoing uncertainty regarding the oil supply-demand macro environment, we reduced our operations in order to preserve capital. Specifically, as part of the Chapter 11 Cases, we rejected our drilling rig contracts and certain equipment and compression agreements as discussed in Note 16—Commitments and Contingencies in Part II, Item 8. Financial Information of this Annual Report.
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Deconsolidation of Elevation Midstream, LLC
Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Information of this Annual Report.
Involuntary Termination Charges
During the first and second quarters of 2020, we recorded involuntary termination charges of $7.6 million primarily related to one-time involuntary termination benefits, office closure and relocation benefits communicated to our workforce in February 2020. This plan was initiated to align the size and composition of our workforce with our expected future operating and capital plans.
Divestitures
In February 2020, we completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $12.2 million, subject to customary purchase price adjustments. No gain or loss was recognized. We continue to explore divestitures as part of our ongoing initiative to divest non-strategic assets.
Senate Bill 19-181 “Protect Public Welfare Oil and Gas Operations”
In April 2019, Senate Bill 19-181 (“SB181”) became law, increasing the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development in a necessary and reasonable manner, and in October 2020, Colorado’s Air Quality Control Commission (“AQCC”) adopted new rules targeting air emissions from upstream oil and gas operation. Among other things, SB181 (i) repeals a prior law restricting local government land use authority over oil and gas mineral extraction areas to areas designated by the COGCC, (ii) directs the AQCC to review its leak detection and repair rules and to adopt rules to minimize emissions of certain air pollutants, (iii) clarifies that local governments have authority to regulate the siting of oil and gas locations in a necessary and reasonable manner, including the ability to inspect oil and gas facilities, impose fines for leaks, spills, and emissions, and impose fees on operators or owners to cover regulation and enforcement costs, (iv) allows local governments or oil and gas operators to request a technical review board to evaluate the effect of the local government’s preliminary or final determination on the operator’s application, (v) repeals an exemption for oil and gas production from counties’ authority to regulate noise, (vi) alters forced pooling requirements by increasing the threshold to compel non-consenting individuals into statutory pooling agreements and (vii) prioritizes the protection of public health, safety, and welfare, the environment, and wildlife resources in the regulation of oil and gas development. Although industry trade associations opposed SB181, Extraction has demonstrated an ability to continue to successfully operate our business. However, the enactment of SB181 and the development and implementation of related rules and regulations, which is under way, could lead to delays and additional costs to our business. Also, certain interest groups in Colorado opposed to oil and natural gas development generally have in previous years advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state.
Resulting from Colorado’s adoption of SB181 during 2019, the COGCC recently promulgated rules associated with that legislation that will, among other things, impose mandatory 2,000 foot setbacks for all schools and childcare centers, as well as new siting criteria for any oil and gas locations that are within 2,000 feet of building units. The rules additionally require local government permitting approval that could add additional timing and complexity and potentially lengthen the pace of the oil and gas permitting process. These new rules went into effect on January 15, 2021.
Though these new siting zones add a number of new criteria for permitting, at this time, the promulgation of these rules has not resulted in any significant changes to our development plans. Extraction has all necessary state and local approvals for 188 permits to drill wells over the next several years. However, due to the necessary learning process associated with the promulgation of new COGCC rules, we could experience delays and/or curtailment in the permitting or pursuit of exploration, development or production activities. Such compliance requirements may lead to delays and additional costs to our operations and reduce the area available for future development of our operations. The discretion with which these new rules are interpreted and enforced by the new COGCC could additionally have a material adverse effect on our business, financial condition, and results of operations.
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Oil, Natural Gas and NGL Data
Proved Reserves
Evaluation and Review of Proved Reserves
Our historical proved reserves estimates as of December 31, 2020, 2019 and 2018 were prepared based on reports by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineers. Within Ryder Scott, the technical person primarily responsible for preparing the estimates set forth in the Ryder Scott summary reserve reports incorporated herein for the year ended December 31, 2020 was Stephen Gardner. Mr. Gardner has been practicing consulting petroleum engineering at Ryder Scott since 2006. Mr. Gardner is a registered Professional Engineer in the State of Colorado and Texas and has over 15 years of practical experience in the estimation and evaluation of reserves. Mr. Gardner graduated from the Brigham Young University with a Bachelor of Science Degree in Mechanical Engineering. As technical principal, Mr. Gardner meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. Ryder Scott does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Ryder Scott’s report is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the DJ Basin. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. These reserve estimates are reviewed and approved by our Corporate Reserves Manager. The reserves are also reviewed by our management and a committee of the Board of Directors (the “Board”).
Our Corporate Reserves Manager is the technical person primarily responsible for overseeing the preparation of our reserves estimates and third-party report of our reserves estimates. She holds a Bachelor of Science in mathematics with a technical minor in petroleum engineering and has over 32 years of industry experience, primarily in reservoir engineering, reserve estimation, and economic evaluation and modelling across multiple conventional and unconventional basins.
Our policies and processes regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our internal controls over reserves estimates also include the review and verification of historical production data, which are based on actual production data as reported by us; preparation of reserve estimates and verification of property ownership by our land department. Additionally, 100% of our total net proved reserves are evaluated by Ryder Scott, on an annual basis.
Estimation of Proved Reserves
Under SEC rules, proved reserves are those quantities of oil, natural gas and NGL, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2020, 2019 and 2018 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil, natural gas and NGL and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil, natural gas and NGL reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed wells were estimated using production performance methods. Reserve estimates for undeveloped properties were forecast using analogy methods. These methods provide a relatively high degree of accuracy for predicting proved undeveloped reserves for our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.
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To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.
Summary of Oil, Natural Gas and NGL Reserves
The following table presents our estimated net proved oil, natural gas and NGL reserves as of December 31, 2020, 2019 and 2018.
| As of December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| Proved Developed Producing Reserves: | ||||||||||||||||||||
| Oil (MBbls) | 32,619 | 44,456 | 43,477 | |||||||||||||||||
| Natural gas (MMcf) | 283,124 | 341,905 | 292,598 | |||||||||||||||||
| NGL (MBbls) | 30,149 | 38,067 | 36,361 | |||||||||||||||||
Total (MBoe) (1) | 109,955 | 139,507 | 128,604 | |||||||||||||||||
| Proved Developed Non-Producing Reserves: | ||||||||||||||||||||
| Oil (MBbls) | 748 | 1,351 | 3,598 | |||||||||||||||||
| Natural gas (MMcf) | 5,644 | 8,403 | 23,901 | |||||||||||||||||
| NGL (MBbls) | 648 | 934 | 3,328 | |||||||||||||||||
Total (MBoe) (1) | 2,337 | 3,685 | 10,910 | |||||||||||||||||
| Proved Undeveloped Reserves: | ||||||||||||||||||||
| Oil (MBbls) | 12,025 | 45,652 | 88,771 | |||||||||||||||||
| Natural gas (MMcf) | 80,766 | 229,781 | 386,769 | |||||||||||||||||
| NGL (MBbls) | 8,098 | 27,008 | 55,162 | |||||||||||||||||
Total (MBoe) (1) | 33,583 | 110,957 | 208,395 | |||||||||||||||||
| Total Proved Reserves: | ||||||||||||||||||||
| Oil (MBbls) | 45,392 | 91,459 | 135,846 | |||||||||||||||||
| Natural gas (MMcf) | 369,534 | 580,089 | 703,268 | |||||||||||||||||
| NGL (MBbls) | 38,895 | 66,009 | 94,851 | |||||||||||||||||
Total (MBoe) (1) | 145,875 | 254,149 | 347,908 | |||||||||||||||||
(1) One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Risk Factors” appearing elsewhere in this Annual Report. Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this Annual Report.
Proved Undeveloped Reserves (“PUDs”)
Annually, management develops a five-year capital expenditure plan based on our best available data at the time the plan is developed. Our capital expenditure plan incorporates a development plan for converting PUD reserves to Proved developed reserves. The development plan includes only PUD reserves that we are reasonably certain will be drilled within five years of booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns; estimated well density; commodity prices and cost forecasts; recent drilling recompletion or re-stimulation results and well performance; anticipated availability of services, equipment, supplies and personnel; and seasonal weather. This process is intended to ensure that PUD reserves are only booked for locations where a final investment decision has been made based on current corporate strategy. In an effort to maximize value to the shareholders, the company has elected to increase the spacing between wells drilled in several areas of the Core Wattenberg, thus drilling fewer wells. The company is currently only booking two years of drilling inventory as PUD. The remainder of our drilling inventory in our capital expenditure plan is currently classified in non-proved reserve categories.
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Management will continue to review and revise the development plan throughout the year and may modify the development plan after evaluating a number of factors, including operating and drilling results; current and expected future commodity prices; estimated risk-based returns; estimated well density; advances in technology; cost and availability of services, equipment, supplies and personnel; acquisition and divestiture activity; and our current and projected financial condition and liquidity. If there are changes that result in certain PUD reserves no longer being scheduled for development within five years from the date of initial booking, we will reclassify those PUD reserves to non-proved reserve categories. In addition, PUD locations and reserves may be removed from the development plan ahead of their five-year life expiration as a result of changes in our development plan related to factors enumerated above.
As of December 31, 2020, our proved undeveloped reserves were composed of 12,025 MBbls of oil, 80,766 MMcf of natural gas and 8,098 MBbls of NGL, for a total of 33,583 MBoe. PUDs will be converted from undeveloped to developed as the necessary and required capital has been invested and the wells are capable of producing.
The following table summarizes our changes in PUDs during the years ended December 31, 2020, 2019 and 2018:
| MBoe | ||||||||
| Balance, December 31, 2017 | 190,693 | |||||||
| Conversion into proved developed reserves | (39,498) | |||||||
| Extensions and discoveries | 64,955 | |||||||
| Acquisitions | 12,325 | |||||||
| Changes in well performance, timing and other | (20,080) | |||||||
| Balance, December 31, 2018 | 208,395 | |||||||
| Conversion into proved developed reserves | (49,713) | |||||||
| Extensions and discoveries | 26,776 | |||||||
| Acquisitions | — | |||||||
| Divestitures | (2,482) | |||||||
| Changes in well performance, timing and other | (72,019) | |||||||
| Balance, December 31, 2019 | 110,957 | |||||||
| Conversion into proved developed reserves | (23,532) | |||||||
| Extensions and discoveries | 8,714 | |||||||
| Acquisitions | — | |||||||
| Divestitures | — | |||||||
| Changes in well performance, timing and other | (62,556) | |||||||
| Balance, December 31, 2020 | 33,583 | |||||||
Extensions and discoveries of 8,714 MBoe, 26,776 MBoe and 64,955 MBoe during the years ended December 31, 2020, 2019 and 2018, respectively, resulted primarily from new proved undeveloped locations added as a result of the drilling and completion of new wells. Downward revisions of previous estimates of 62,556 MBoe during the year ended December 31, 2020 under changes in well performance, timing and other includes 23,926 MBoe of downward revisions of PUD expirations due to the five year rule caused by a continued reduction in planned capital spending to generate positive cash flow. The majority of these reserves (69%) were reclassified to a non-proved reserve category (Probable). Additionally, 26,515 MBoe of the 62,556 MBoe downward revisions were due to altering the development plan to increase the spacing between wellbores, thus drilling fewer wells. Downward revisions of previous estimates of 72,019 MBoe during the year ended December 31, 2019 under changes in well performance, timing and other consists primarily of revisions of PUD expirations due to the SEC five year drilling rule caused by the change in business strategy to focus on cash flow rather than maximizing production and reserves growth. Of the 72,019 MBoe downward revision of previous estimates, 69,731 MBoe was due the reclassification of reserves to non-proved categories due to the aforementioned PUD expirations. An additional 5,483 MBoe of the downward revision of previous estimates was due to PUDs becoming uneconomic due to negative changes in SEC pricing at December 31, 2019. Downward revisions of previous estimates of 20,080 MBoe during the year ended December 31, 2018 resulted primarily from the revisions resulting from price changes and revisions resulting from production and performance.
Estimated future development costs relating to the development of PUDs at December 31, 2020 were projected to be approximately $61.7 million for the year ending December 31, 2021, $116.3 million in 2022 and none thereafter. Costs incurred relating to PUDs that were developed were $69.8 million, $326.9 million and $392.3 million during the years ended December 31, 2020, 2019 and 2018, respectively. All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. We converted 23,532 MBoe, 49,713 MBoe and 39,498 MBoe to proved developed producing reserves in the years ended December 31, 2020, 2019 and 2018, respectively. During the year ended December 31, 2020, we converted 33 PUD locations to proved developed producing reserves, which represented 21% of our PUD reserve volumes and 14% of our PUD locations as of December 31, 2019.
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Productive Wells
As of December 31, 2020, we owned an average 79% working interest in 1,322 gross (1,041 net) productive wells. As of December 31, 2019, we owned an average 72% working interest in 1,509 gross (1,086 net) productive wells. As of December 31, 2018, we owned an average 74% working interest in 1,538 gross (1,139 net) productive wells. Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2020:
| Productive Wells | |||||||||||
| Gross | Net | ||||||||||
| Oil wells | 1,165 | 899 | |||||||||
| Natural gas wells | 157 | 142 | |||||||||
| Total wells | 1,322 | 1,041 | |||||||||
Developed and Undeveloped Acreage
The following tables set forth information as of December 31, 2020 relating to our leasehold acreage. Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and/or natural gas, regardless of whether such acreage contains proved reserves.
The following table sets forth our gross and net acres of developed and undeveloped oil and gas leases as of December 31, 2020:
Developed Acreage (1) | Undeveloped Acreage (2) | Total Acreage | |||||||||||||||||||||||||||||||||||||||
| Area | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||
| Core DJ Basin | 116,000 | 92,900 | 60,400 | 47,100 | 176,400 | 140,000 | |||||||||||||||||||||||||||||||||||
| Other Rockies | 47,100 | 35,100 | 102,400 | 61,600 | 149,500 | 96,700 | |||||||||||||||||||||||||||||||||||
(1) Developed acreage is acres spaced or assigned to productive wells. | |||||||||||||||||||||||||||||||||||||||||
(2) Undeveloped acreage are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. | |||||||||||||||||||||||||||||||||||||||||
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We intend to extend our strategic leases to the extent possible and would incur approximately $39.1 million if we were to extend all of our leases set to expire in the next three years without taking into account the drilling of wells and holding leases by production. The following table sets forth the undeveloped acreage, as of December 31, 2020, that will expire in the years indicated below unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
| 2021 | 2022 | 2023 | 2024 and Beyond | |||||||||||||||||||||||||||||||||||||||||||||||
| Area | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||||||||||
| Core DJ Basin | 19,300 | 16,500 | 9,200 | 6,800 | 3,900 | 3,100 | 5,000 | 3,900 | ||||||||||||||||||||||||||||||||||||||||||
| Other Rockies | 26,400 | 12,200 | 23,500 | 13,300 | 8,200 | 3,800 | 3,400 | 3,500 | ||||||||||||||||||||||||||||||||||||||||||
Drilling Results
The following table sets forth information with respect to the number of wells completed by us during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.
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| For the Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
Development Wells: (1) | |||||||||||||||||||||||||||||||||||
Productive (2) | 45.0 | 34.1 | 119.0 | 104.3 | 160.0 | 136.4 | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
Exploratory Wells: (1) | |||||||||||||||||||||||||||||||||||
Productive (2) | — | — | — | — | 1.0 | 1.0 | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
Total Wells: (1) | |||||||||||||||||||||||||||||||||||
Productive (2) | 45.0 | 34.1 | 119.0 | 104.3 | 161.0 | 137.4 | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
(1) Includes only wells completed by us.
(2) Although a well may be classified as productive upon completion, future changes in oil, natural gas and NGL prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.
As of December 31, 2020, we had 38 gross wells with an average lateral length of 2.1 miles waiting on commencement of completion activities.
Operations
General
We operated 99% of our horizontal production for the year ended December 31, 2020. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Marketing and Customers
We sell the majority of the production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to purchasers at market prices.
During the year ended December 31, 2020, approximately 56% of our production was sold to three customers. However, we do not believe that the loss of any single purchaser would materially affect our business because there are numerous other potential purchasers in the area in which we sell our production. For the year ended December 31, 2020, Mercuria Energy Trading, Inc., Rocky Mountain Midstream, and Concord Energy represented 28%, 16%, and 12%, respectively, of our total oil, gas and NGL revenues. For the year ended December 31, 2019, Mercuria Energy Trading, Inc. represented 77% of our total oil, gas and NGL revenues. For the year ended December 31, 2018, Mercuria Energy Trading, Inc. represented 76% and DCP Midstream represented 11% of our total oil, gas and NGL revenues. During 2021, we do not currently sell to Mercuria Energy Trading, Inc. or Concord Energy. Rather, we have increased our sales to Rocky Mountain Midstream and NGL Crude Logistics LLC who has replaced Mercuria Energy Trading, Inc. as our midstream oil marketer.
Transportation and Gathering
During the initial development of our fields, we consider all gathering and delivery infrastructure in the areas of our production. Our oil is collected from the wellhead to our tank batteries and then transported by the purchaser by truck or pipeline to a tank farm, another pipeline or a refinery. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point. During the third and fourth quarters of 2020, the majority of our material midstream contracts were renegotiated or rejected by the Bankruptcy Court as part of the Chapter 11 Cases. As a result of these renegotiated or rejected contracts, the Company eliminated the majority of its minimum volume commitments as described in Note 16—Commitment and Contingencies — Delivery Commitments in Part II, Item 8. Financial Information of this Annual Report. See this section of the Annual Report for a description of our transportation and gathering agreements during 2020 and as of December 31, 2020.
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Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than we do. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil, natural gas and NGL market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
There is also competition between oil and natural gas producers and other industries producing 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 the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may 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. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.
Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained or have the ability to obtain sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil, natural gas and NGLs. Demand for oil, natural gas and NGLs is typically higher in the fourth and first quarters resulting in higher prices. For example, during February 2021, Extraction’s natural gas revenue was positively impacted by days of severe cold. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
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Oil and Gas Leases
The typical oil and gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and gas produced from any wells drilled on the leased premises. Our interest in our properties after lessor royalties and other leasehold burdens is generally approximately 82%. Our working interest for all producing wells averages approximately 79% and our net revenue interest is approximately 65%.
Regulation of the Oil and Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs have not had a material adverse effect on our results of operations; however, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the administrative agencies and the courts. We cannot predict when or whether any such proposals may become effective. However, we do not believe that we would be affected by any such action materially differently than similarly situated competitors.
Regulation Affecting Production
The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. 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, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and gas we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGL within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.
The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Local Regulation
Various local and municipal bodies in each of the states in which we operate have sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities. In Colorado, Senate Bill 19-181 ("SB 19-181"), gives local governmental authorities increased authority to regulate the siting and surface impacts of oil and gas development. We primarily operate in the rural areas of the core Wattenberg Field in Weld County, a jurisdiction in which there has historically been significant support for the oil and gas industry. In Texas, legislation enacted in 2015 generally prohibits political subdivisions from banning, limiting or otherwise regulating oil and gas operations. See Item 1A. Risk Factors-Risks Relating to the Regulatory Environment.
Regulation Affecting Sales and Transportation of Commodities
Sales prices of gas, oil, condensate and NGL are not rate-regulated and instead are made at market prices. Although prices of these energy commodities are not currently rate-regulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to actively regulate, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to certain state and federal reporting and compliance requirements.
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The rates, terms and conditions of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of oil and natural gas produced by us, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil and natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for oil and natural gas production, if any, of the drilling program and the cost of such capacity. Further state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.
The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas pipeline transportation rates and terms and conditions of service under the Natural Gas Act of 1938 (“NGA”). The FERC is continually proposing and implementing new rules and regulations affecting interstate natural gas pipeline transportation. The stated purpose of many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.
In addition to the regulation of interstate natural gas pipeline transportation, the NGA and the Natural Gas Policy Act of 1978 (“NGPA”) provide FERC jurisdiction over the sale for resale of gas in interstate commerce. In addition, the Energy Policy Act of 2005 (“EPAct 2005”) made it unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the NGA to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to FERC’s jurisdiction or the purchase or sale of transportation services subject to FERC’s jurisdiction, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties up to approximately $1.2 million per day per violation for violations of the NGA and the NGPA. The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under FERC Order No. 704 (defined below).
In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”). Under Order No. 704, certain market participants, including producers engaging in certain wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains 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. Not all types of natural gas sales are required to be reported on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 is intended to increase the transparency of wholesale gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.
The FERC also regulates rates and terms and conditions of service of interstate transportation of liquids, including oil and NGL, under the Interstate Commerce Act, as it existed on October 1, 1977 (“ICA”). Prices received from the sale of liquids may be affected by the cost of transporting those products to market. The ICA requires that certain interstate liquids pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.
The rates charged by many interstate liquids pipelines are currently adjusted pursuant to an annual indexing methodology established and regulated by FERC, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by obtaining market-based rate authority (demonstrating the pipeline lacks market
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power), by establishing rates by settlement with all existing shippers, or through a cost-of-service approach (if the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology). Increases in liquids transportation rates may result in lower revenue and cash flows for us.
In addition, due to common carrier regulatory obligations for interstate liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity or to accommodate requests for service from new shippers. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Rates for intrastate pipeline transportation of liquids are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.
In addition to FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the Federal Trade Commission (“FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to approximately $1.1 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which expanded the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets it regulates. This authority, with respect to oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to oil purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of approximately $1.1 million or triple the monetary gain to the person for each violation.
Some of our pipeline assets and third-party pipelines on which we rely are subject to safety regulation by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”). In recent years, PHMSA has been active in proposing and finalizing additional regulations for natural gas and hazardous liquids pipelines. In April 2016, PHMSA proposed a rule regarding the safety of natural gas transmission pipelines and gas gathering pipelines in April 2016. In October 2019, PHMSA issued a final rule on the natural gas transmission lines portion of the April 2016 rulemaking, and PHMSA is expected to finalize the rules with respect to gathering lines in 2020. With respect to transmission pipelines, the final rule changes integrity management requirements, expands assessment and repair requirements for pipelines in “moderate-consequence areas,” including areas of medium population density, and increases requirements for monitoring and inspection of pipeline segments not located in “high-consequence areas.” The final rule also requires that records or other data relied on to determine operating pressures must be traceable, verifiable and complete. If the pending gathering-pipeline portion of the rulemaking ultimately includes a final rule that applies similar requirements to gathering lines, some gathering pipeline operators, including us, may be forced to reduce their allowable operating pressures, which would reduce the amount of capacity available to us. As PHMSA has yet to finalize this rulemaking as applied to gathering lines, however, the contents and timing of any final rule are uncertain. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
Effective April 2017, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to up to $218,649 per violation per day and up to approximately $2.2 million for a related series of violations.
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Regulation of Environmental and Safety and Health Matters
Our operations are subject to numerous stringent and complex federal, state and local laws and regulations governing safety and health aspects of our operations, the release, disposal, or discharge of materials into the environment or otherwise relating to environmental protection. Governmental entities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies, including the COGCC, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) impose limitations on the time, place and manner on drilling and other regulated activities; (iii) restrict the types, quantities and concentration of various materials that may be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iv) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (v) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (vi) apply specific health and safety criteria addressing worker protection; and (vii) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary fines or penalties, the imposition of investigatory, remedial or corrective obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations in a particular area.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental spills or releases may occur in the course of our operations that can result in the occurrence of significant costs and liabilities, including any third-party claims for damage to property, natural resources or persons. 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.
In April 2019, SB181 became law, increasing the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development in a necessary and reasonable manner, and in October 2020, Colorado’s AQCC adopted new rules targeting air emissions from upstream oil and gas operation. Among other things, SB181 (i) repeals a prior law restricting local government land use authority over oil and gas mineral extraction areas to areas designated by the COGCC, (ii) directs the AQCC to review its leak detection and repair rules and to adopt rules to minimize emissions of certain air pollutants, (iii) clarifies that local governments have authority to regulate the siting of oil and gas locations in a necessary and reasonable manner, including the ability to inspect oil and gas facilities, impose fines for leaks, spills, and emissions, and impose fees on operators or owners to cover regulation and enforcement costs, (iv) allows local governments or oil and gas operators to request a technical review board to evaluate the effect of the local government’s preliminary or final determination on the operator’s application, (v) repeals an exemption for oil and gas production from counties’ authority to regulate noise, (vi) alters forced pooling requirements by increasing the threshold to compel non-consenting individuals into statutory pooling agreements and (vii) prioritizes the protection of public health, safety, and welfare, the environment, and wildlife resources in the regulation of oil and gas development. Although industry trade associations opposed SB181, Extraction has demonstrated an ability to continue to successfully operate our business. However, the enactment of SB181 and the implementation of related new rules and regulations, which went into effect on January 15, 2021, could lead to delays and additional costs to our business. Also, certain interest groups in Colorado opposed to oil and natural gas development generally have in previous years advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Various local and municipal bodies in Colorado have sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities.
The following is a summary of the more significant existing and proposed environmental and safety and health laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
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Hazardous Substances and Wastes
The Resource Conservation and Recovery Act (“RCRA”), and analogous state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the guidance issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. For example, in December 2016, several environmental groups and the EPA entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. In April 2019, the EPA determined in a document entitled “Management of Oil and Gas Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action” that revisions to these oil and gas waste regulations were not necessary because the main causes for uncontrolled releases of oil and gas waste are appropriately and more readily addressed within the framework of existing state regulatory programs. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. We are required to manage the disposal of hazardous and non-hazardous wastes in compliance with RCRA and analogous state laws. RCRA currently exempts many exploration and production wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas exploration and production wastes currently classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customer’s operations could result in an increase in our and our customers’, as well as the oil and natural gas exploration and production industry’, costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several 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. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property 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 currently own, lease, or operate, and in the past have owned, leased or operated, numerous properties that have been used for oil and natural gas exploration, production and processing and other operations for many years. Hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned, leased or operated by us, or on, under or from other locations where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of substances, including hazardous substances, wastes, or petroleum hydrocarbons, was not under our control. These properties and the hazardous substances, wastes or petroleum hydrocarbons disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination, the costs of which could have a material adverse effect on our business and results of operations.
Water Discharges
The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In June 2015, the EPA and the U.S. Army Corps of Engineers (“Corps”) published a final rule to revise the definition of “waters of the United States” (“WOTUS”) for all
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CWA programs, but legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015. In January 2018, the U.S. Supreme Court ruled that the rule revising the WOTUS definition must first be reviewed in the federal district courts, which resulted in a withdrawal of the stay by the Sixth Circuit. Subsequent litigation in the federal district courts resulted in patchwork application of the rule in some states (e.g., California, Oklahoma), but not others (e.g. Colorado). In July 2017, the EPA proposed to repeal the 2015 rule revising the WOTUS definition and, in December 2018, EPA and the Corps issued a proposed rule revising the WOTUS definition that would provide discrete categories of jurisdictional waters and tests for determining whether a particular water body meets any of those classifications. In October 2019, the EPA issued a final rule repealing the 2015 rule (which became effective in December 2019 and has already been challenged in federal district courts in New Mexico, New York, and South Carolina). In January 2020, the EPA announced a final rule redefining the WOTUS definition. Several groups have already announced their intentions to challenge the final revision rule. To the extent the repeal and revision rules are successfully challenged and the 2015 rule is enforced in jurisdictions in which we operate or a replacement rule expands the scope of the CWA’ jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. Federal and state regulatory agencies may impose substantial administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations, including spills and other non-authorized discharges.
The Oil Pollution Act of 1990 (“OPA”), amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore 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, 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. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.
Subsurface Injections
In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near belowground disposal wells used for the injection of oil and natural gas-related wastewaters, regulators in some states, including Colorado, have imposed more stringent permitting and operating requirements for produced water disposal wells. In Colorado, permit applications are reviewed specifically to evaluate seismic activity and, as of 2011, the state has required operators to identify potential faults near proposed wells, if earthquakes historically occurred in the area, and to accept maximum injection pressures and volumes based on fracture gradient as conditions to permit approval. Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, and increased costs of compliance, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.
Air Emissions
The Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. 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 of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be charged royalties on natural gas losses or required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in 2016, EPA designated the Denver Metro North Front Range as Marginal non-attainment for the 2008 National Ambient Air Quality Standard (“NAAQS”) for ozone. In August 2019, the EPA proposed to reclassify the Denver Metro North Front Range area as a serious non-attainment area for ozone due to high levels detected in 2016 and 2017. The proposal would set a new deadline of July 20, 2021 for the Denver area to attain the 2008 ozone standard. Reclassification of areas or imposition of more stringent standards
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(including a lowering of the major source threshold for volatile organic compounds and oxides of nitrogen and the resulting increased likelihood that a source may be subject to Non-Attainment New Source Review) may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our operations. In addition, during the fall of 2016, EPA issued final Control Techniques Guidelines (“CTGs”) for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-hour Non-Attainment area. In 2017, as part of the federal CTG process for oil and natural gas, Colorado undertook a stakeholder and rulemaking effort to compare the CTGs to existing Colorado requirements to ensure they meet applicable federal requirements, which resulted in revisions to Colorado’ Regulation Number 7. The new state regulations include more stringent air quality control requirements applicable to our operations. In another example, in June 2016, the EPA finalized a revised rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent permitting requirements. Compliance with these or other air pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could have a material adverse impact on our business and results of operations.
Regulation of Greenhouse Gas (“GHG”) Emissions
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has adopted rules under authority of the CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operations permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards for those emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among other things, onshore producing facilities, which include certain of our operations.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published the New Source Performance Standards (“NSPS”) Subpart OOOOa standards that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. However, in September 2019, under the new administration, EPA proposed to remove transmission and storage activities from the purview of the OOOOa standards, thereby rescinding the VOC and methane emissions limits applicable to those activities. The proposed rule would also rescind the methane limit emissions for production and processing sources, but would maintain emissions limits for VOCs. In the alternative, the EPA also proposed to simply rescind the methane requirements for all oil and natural gas sources, without removing any activities from the source category. Similarly, in September 2018, the federal Bureau of Land Management (“BLM”) issued a rule that relaxes or rescinds certain requirements of its November 2016 rule enacted to reduce methane emissions by regulating venting, flaring, and leaks from oil and gas operations on federal and American Indian lands. California and New Mexico have challenged the rule in ongoing litigation. In addition, in April 2018, a coalition of states filed a lawsuit aiming to force EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas section; that lawsuit is currently pending (as of October 2019, the EPA had requested a stay of the litigation pending the outcome of its proposed overhaul of the 2016 methane requirements).
On the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement and on November 4, 2019, the U.S. submitted formal notification of its withdrawal to the United Nations. However, during the first part of 2021, the United States, under a new presidential administration, rejoined the Paris Agreement.
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The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHG or otherwise limit emissions of GHG from our equipment and operations could result in increased costs to reduce emissions of GHG associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil, natural gas and NGL we produce and lower the value of our reserves, which devaluation could be significant. One or more of these developments could have a materially adverse effect on our business, financial condition and results of operations. Additionally, it should be noted that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations. Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to rise and will not peak until after 2040 and oil and gas will continue to represent a substantial percentage of global energy use over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions or similar state agencies. However, several federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, in June 2016 the EPA published final effluent limitations guidelines pursuant to its authority under the SDWA prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; asserted regulatory authority in 2014 under the SDWA over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 establishing new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands including well casing and wastewater storage requirements and an obligation for exploration and production operators to disclose what chemicals they are using in fracturing activities. Following years of litigation, the BLM rescinded the rule in December 2017; however, that rescission has been challenged by several environmental groups and states in ongoing litigation (oral arguments were heard in the case in January 2020 after a long hiatus). Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
Colorado developed significant new oil and gas related rules regulating siting of oil and gas facilities and the permitting process including, but not limited to 2,000-foot setbacks from all schools and childcare facilities, and the establishment of new siting zones, which require enhanced review criteria and other requirements for permitting. These new rules went into effect on January 15, 2021. The enactment of SB181 in April 2019 increased local control and elevated public health, safety and environmental concerns in the regulation of oil and gas development in the state. This legislation also explicitly authorized cities and counties in the state to develop and implement local-level oil and gas regulations. Also, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives (including proposed ballot initiatives for 2022 that, if approved, would make such exploration and production activities in the state more difficult in the future. In addition to state laws, local land use restrictions may restrict drilling or the hydraulic fracturing process and cities may adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities. 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 cost to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
In the event that local or state restrictions or prohibitions are adopted in areas where we conduct operations, including the DJ Basin in Colorado, that impose more stringent limitations on the production and development of oil and natural gas,
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including, among other things, the development of increased setback distances, we and similarly situated oil and natural exploration and production operators in the state may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we and similarly situated operates are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Moreover, because most of our operations are conducted in a particular area, the DJ Basin in Colorado, legal restrictions imposed in that area will have a significantly greater adverse effect than if we had our operations spread out amongst several diverse geographic areas. Consequently, in the event that local or state restrictions or prohibitions are adopted in the DJ Basin in Colorado that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
Activities on Federal Lands
Oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act (“NEPA”). 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. While we currently have minimal exploration, development and production activities on federal lands, our proposed exploration, development and production activities are expected to include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of 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. Moreover, depending on the mitigation strategies recommended in Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial. In January 2020, the White House Council on Environmental Quality (“CEQ”) proposed changes to NEPA regulations designed to overhaul the system and speed up federal agencies’ approval of projects. Among other things, the rule proposes to narrow the definition of “effects” to exclude the terms “direct,” “indirect,” and “cumulative” and redefine the term to be “reasonably foreseeable” and having “a reasonably close causal relationship to the proposed action or alternatives.” Changes to the NEPA regulations could have an effect on our operations and our ability to obtain governmental permits. We continuously evaluate the effect of new rules on our business.
Endangered Species and Migratory Birds Considerations
The federal Endangered Species Act (“ESA”), and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or that species’ habitat. Similar protections are offered to migrating birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. Moreover, as a result of one or more agreements entered into by the U.S. Fish and Wildlife Service, the agency is required to make a determination on listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. The identification or designation of previously unprotected species as threatened or endangered in areas where our operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
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Employee Safety and Health
We are subject to the requirements of the Occupational Safety and Health Act and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right-To-Know Act and comparable state statutes and any implementing regulations require that we maintain and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. For example, under a new OSHA standard limiting respirable silica exposure, the oil and gas industry must implement engineering controls and work practices to limit exposures below the new limits by June 2021. Failure to comply with OSHA requirements can lead to the imposition of penalties.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.
Employees
As of December 31, 2020, we employed 125 people. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.
Facilities
Our corporate headquarters is located in Denver, Colorado. We maintain a field office in Windsor, Colorado.
Available Information
Our common stock is listed and traded on the NASDAQ under the symbol “XOG.” Our reports, proxy statements and other information filed with the SEC can be inspected and copied at the offices of the NASDAQ, at One Liberty Plaza, 165 Broadway, New York, New York 10006.
We also make available free of charge through our website, www.extractionog.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
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ITEM 1A. RISK FACTORS
RISK FACTORS
There are many factors that may affect our business and results of operations. If any of the following risks actually occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business.
Summary of Material Risks Related to the Oil, Natural Gas and NGL Industry and Our Business
Risks Relating to Commodity Prices
•Oil and natural gas prices are volatile. An extended or further decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
Risks Relating to our Reserves and Reserve Estimation
•Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
•There is a limited amount of production data from horizontal wells completed in the DJ Basin. As a result, reserve estimates associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.
•Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
•A substantial portion of our reserves are located in urban areas, which could increase our costs of development and delay production.
Risks Related to our Operations
•Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
•Properties that we decide to drill may not yield oil, natural gas or NGL in commercially viable quantities.
•Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
•Substantially all of our producing properties are located in the DJ Basin of Colorado, making us vulnerable to risks associated with operating in one major geographic area. Specifically, as the DJ Basin is an area of high industry activity, we may be unable to hire, train or retain qualified personnel needed to manage and operate our assets.
Risks Related to the Regulatory Environment
•Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes specific to the DJ Basin of Colorado, could have a material adverse effect on our business.
Risks Related to Capital
•Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.
•A negative shift in investor sentiment of the oil and gas industry could have adverse effects on our ability to raise debt and equity capital and on our operations.
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•Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
•We may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations.
Risks Related to Debt
•The borrowing base under our RBL Credit Facility may be reduced in connection with declines in commodity prices, which could hinder or prevent us from meeting our future capital needs.
•We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.
Risks Related to Common Stock
•The market price of our securities is subject to volatility.
Risks Related to Taxes
•Recent changes in United States federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition overall.
•Certain United States federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
•Our ability to use our net operating loss carryforwards (“NOLs”) and other tax attributes may be limited.
Risks Related to Technology
•Conservation measures and technological advances could reduce demand for oil, natural gas and NGL.
Risks Related to the General Business
•Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
•We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.
•Our cash flow from operations and access to capital are subject to a number of variables.
•We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGL we produce.
•The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.
Risks Related to the COVID-19 Pandemic
•The ongoing COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries may result in transportation and storage constraints, reduced production and shut-in of our wells, any of which would adversely affect our business, financial condition and results of operations.
Risks Related to Bankruptcy
•We recently emerged from bankruptcy, which may adversely affect our business and relationships.
•We may be negatively impacted by litigation and legal proceedings, including ongoing claims in connection with the Chapter 11 Cases.
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Detailed Discussion of Risks Related to the Oil, Natural Gas and NGL Industry and Our Business
Risks Relating to Commodity Prices
Oil and natural gas prices are volatile. An extended or further decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital and future rate of growth. The commodities market has historically been and will likely continue to be volatile. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to, the following:
•worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGL;
•the price and quantity of foreign imports;
•political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
•the level of global exploration and production;
•the level of global inventories;
•prevailing prices on local price indices in the areas in which we operate;
•the proximity, capacity, cost and availability of gathering and transportation facilities;
•localized and global supply and demand fundamentals and transportation availability;
•the extent to which members of OPEC and other oil exporting nations agree to and maintain oil price and production controls;
•weather conditions;
•technological advances affecting energy consumption;
•the effect of worldwide energy conservation and environmental protection efforts;
•the price and availability of alternative fuels;
•domestic, local and foreign governmental regulation and taxes;
•shareholder activism and activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas; and
•global or national health epidemics or concerns, such as the ongoing coronavirus outbreak, which may reduce demand for oil, natural gas and related products because of reduced global or national economic activity.
Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGL that we can produce economically and may impact our ability to satisfy our obligations under firm-commitment transportation agreements. We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may be limited. The RBL Credit Agreement requires us to maintain commodity hedges covering a minimum of 65% of our anticipated oil and gas production from PDP reserves for the succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the next succeeding twelve months.
Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits. While it is difficult to project future economic conditions and whether such conditions will result in impairment of proved property costs, we consider several variables including specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
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The prices we receive for our production may be affected by local and regional factors.
The prices we receive for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process, and transport, our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and natural gas production and the actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.
The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.
OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In March 2020, members of OPEC and Russia considered extending and potentially increasing these oil production cuts. However, those negotiations were unsuccessful. As a result, Saudi Arabia announced an immediate reduction in export prices and Russia announced that all previously agreed upon oil production cuts would expire on April 1, 2020. These actions led to an immediate and steep decrease in oil prices, which reached a closing NYMEX price low of under negative $37.00 per Bbl of crude oil in April 2020. Although OPEC members subsequently agreed on certain production cuts beginning in May 2020 and continuing through April 2022, there can be no assurance that OPEC members and other oil exporting nations will continue to agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that they will not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could adversely affect our business, financial condition, results of operations and cash flows.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors such as lease expirations, changes in drilling plans and adverse drilling results, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. For the year ended December 31, 2020, we recorded non-cash impairment charges of approximately $194.3 million and $3.6 million on oil and gas properties primarily in our Core DJ Basin field and our northern field, respectively, and if market or other economic conditions deteriorate or if oil, natural gas and NGL prices continue to decline, we may incur impairment charges in 2021 or later periods, which may have a material adverse effect on our results of operations.
Risks Relating to our Reserves and Reserve Estimation
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.
In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.
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You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2020 were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $39.57/Bbl for oil and $1.99/MMBtu for natural gas, which for certain periods of 2020 were substantially above the available spot oil and natural gas prices. Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.
There is a limited amount of production data from horizontal wells completed in the DJ Basin. As a result, reserve estimates associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.
Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field. Horizontal drilling in the DJ Basin is a relatively recent development, whereas vertical drilling has been utilized by producers in this area for over 50 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small compared to that of production data from vertical wells. Until a greater number of horizontal wells have been completed in the DJ Basin, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year-over-year basis due to the transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories. We cannot assure you that any such variance would not be material and any such variance could have a material and adverse impact on our cash flows and results of operations. If our horizontal wells do not allow for the extraction of oil and natural gas in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
A substantial portion of our reserves are located in urban areas, which could increase our costs of development and delay production.
A substantial portion of our reserves are located in urban portions of the DJ Basin, which could disproportionately expose us to operational and regulatory risk in that area. Much of our operations are within the city limits of various municipalities in northeastern Colorado. In such urban and other populated areas, we may incur additional expenses, including expenses relating to mitigation of noise, odor and light that may be emitted in our operations, expenses related to the appearance of our facilities and limitations regarding when and how we can operate. The process of obtaining permits for drilling or for gathering lines to move our production to market in such areas may be more time consuming and costly than in more rural areas and such permits may not be able to be obtained at all. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our operations or facilities in such highly populated areas.
SEC rules could limit our ability to book additional PUDs in the future.
SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe. For example, for the year ended December 31, 2020, we wrote down approximately 23,926 MBoe of PUDs.
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Risks Relating to our Operations
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.
Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
•delays imposed by or resulting from compliance with environmental and other regulatory requirements including limitations on or resulting from wastewater discharge and disposal, subsurface injections, GHG emissions and hydraulic fracturing;
•pressure or irregularities in geological formations;
•shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
•lack of available capacity on interconnecting transmission pipelines;
•equipment failures or accidents, such as fires or blowouts;
•lack of available gathering facilities or delays in construction of gathering facilities;
•adverse weather conditions, such as blizzards, tornados and ice storms;
•issues related to compliance with environmental and other governmental regulations;
•environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
•declines in oil, natural gas and NGL prices;
•limited availability of financing at acceptable terms;
•title problems or legal disputes regarding leasehold rights; and
•limitations in the market for oil, natural gas and NGL.
Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained or if existing producing wells that are holding leases with other potential locations cease to continue to produce in commercial quantities, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.
In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.
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Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.
The marketing of oil and natural gas production depends in large part on the capacity and availability of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. The availability of these facilities also could be impacted by the comprehensive regulatory structure under which these facilities operate, as detailed in “Business and Properties — Regulation Affecting Sales and Transportation of Commodities.” If there is insufficient capacity available on these systems, or if these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit and sell our oil and gas production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise, especially in areas of planned expansion where such facilities do not currently exist. The amount of oil and gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. For example, recent increases in activity in the DJ Basin have contributed to bottlenecks in processing and transportation that have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Additionally, we experience constraints from time to time on the capacity available in certain pipelines that we use to transport natural gas and have been forced to shut in some production from time to time. Capacity constraints typically reduce the productivity of some of our older vertical wells and may on occasion limit incremental production from some of our newer horizontal wells. This constrains our production and reduces our revenue from the affected wells. Capacity constraints affecting natural gas production also impact the associated NGL. We are also dependent on the availability and capacity of oil purchasers for our production. Increases in the amount of oil that we transport out of the DJ Basin for sale would result in an increase in our transportation costs and would reduce the price we receive for the affected production.
Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the DJ Basin, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.
While we have undertaken initiatives to expand our access to midstream and operational infrastructure, these initiatives may be delayed or unsuccessful. As a result, our business, financial condition and results of operations could be adversely affected.
Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. During the year ended December 31, 2020, we drilled 37 gross operated horizontal wells and completed 45 gross operated horizontal wells and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. In addition, our horizontal drilling activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
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Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2020, approximately 23% of our total estimated proved reserves were classified as proved undeveloped. The development of our estimated proved undeveloped reserves of 33,583 MBoe will require an estimated $178.0 million of development capital over the next two years.
Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecast, as well as access to liquidity sources, such as the capital markets, our RBL Credit Facility and derivative contracts. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, pipeline and tank ruptures or unauthorized discharges of toxic gases or other pollutants.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
•injury or loss of life;
•damage to and destruction of property, natural resources and equipment;
•pollution and other environmental damage;
•regulatory investigations and penalties;
•suspension of our operations; and
•repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Also, pollution and other environmental risks generally are not fully insurable. The occurrence of an event that is not covered or fully covered by insurance and any delay in the payment of insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of operations.
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Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations from local sources, we may be unable to produce oil, natural gas and NGL economically, which could have an adverse effect on our financial condition, results of operations and cash flows.
Properties that we decide to drill may not yield oil, natural gas or NGL in commercially viable quantities.
Properties that we decide to drill that do not yield oil, natural gas or NGL in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
•unexpected drilling conditions;
•title problems;
•pressure or lost circulation in formations;
•equipment failure or accidents;
•adverse weather conditions;
•compliance with environmental and other governmental or contractual requirements; and
•increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, natural gas and NGL prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases is substantial and may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. For example, we would incur approximately $39.1 million if we were to extend all of our leases set to expire in the next three years without taking into account the drilling of wells and holding leases by production. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. Moreover, many of our leases require lessor consent to
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unitize, which may make it more difficult to hold our leases by production. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially and adversely affect our ability to so develop such acreage. These risks are greater at times and in areas where the pace of our exploration and development activity slows.
Substantially all of our producing properties are located in the DJ Basin of Colorado, making us vulnerable to risks associated with operating in one major geographic area. Specifically, as the DJ Basin is an area of high industry activity, we may be unable to hire, train or retain qualified personnel needed to manage and operate our assets.
Substantially all of our producing properties are geographically concentrated in the DJ Basin of Colorado, an area in which industry activity has increased rapidly. At December 31, 2020, substantially all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors or other regional events, delays or interruptions of production from wells in this area caused by governmental regulation, including at the state and local level, processing or transportation capacity constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGL. For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition, or results of operations.
Specifically, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years and may increase substantially in the future. Moreover, our competitors, including those operating in multiple basins, may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could have a negative effect on production volumes or significantly increase costs, which could have a material adverse effect on our results of operations, liquidity and financial condition.
Risks Related to the Regulatory Environment
Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes specific to the DJ Basin of Colorado, could have a material adverse effect on our business
Our business is subject to various forms of government regulation. Some local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and natural gas operations. Some local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. Since that time, local district courts have struck down the ordinances for certain of those Colorado cities, and such decisions were upheld by the Colorado Supreme Court in May 2016. Nevertheless, there is a continued risk that cities will adopt local ordinances that seek to regulate the time, place, and manner of hydraulic fracturing activities and oil and natural gas operations within their respective jurisdictions. For example, the town of Erie, Colorado first adopted a moratorium on oil and gas in July 2018, and on January 14, 2020, the City Council of Broomfield, Colorado unanimously approved an emergency noise ordinance that put the onus on a person or company to prove noise generated during restricted hours by such person or company is below Broomfield’s decibel standards.
In addition, in 2014, 2016 and 2018, opponents of hydraulic fracturing sought statewide ballot initiatives that would have restricted oil and gas development in Colorado. The 2014 initiatives were withdrawn in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and natural gas facilities, and none of the 2016 initiatives were successful. However, in 2018, the Colorado Secretary of State approved a citizen-initiated ballot measure, referred to as Prop. 112, for inclusion on the statewide voter ballot in November 2018. Although Prop. 112 was ultimately unsuccessful, similar efforts are likely to continue in the future, which, if successful, could result in dramatically reducing the area available for future oil and gas development in Colorado or outright banning oil and gas development in Colorado. We cannot predict the nature or outcome of future ballot initiatives or other similar efforts. If we are required to cease
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operating in any of the areas in which we now operate as the result of bans or moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition, and results of operations.
Additionally, we are subject to laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells we drill, among other matters. In particular, our business utilizes a methodology available in Colorado known as “forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective drilling spacing unit to apply to the COGCC for an order forcing all other holders of oil and natural gas interests in such area into a common pool for purposes of developing that drilling spacing unit. This methodology is especially important for our operations in the Greeley area, where there are many interest holders. Changes in the legal and regulatory environment governing our industry, particularly any changes to Colorado forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business, financial condition and results of operations. SB181, enacted in April 2019, changed forced pooling requirements in the state of Colorado by requiring the consent of 45% of mineral interest holders, thus making it more difficult to include non-consenting individuals into statutory pooling agreements.
The enactment of Senate Bill 19-181 “Protect Public Welfare Oil and Gas Operations” increased the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development, which could have a material adverse effect on our business.
In April 2019, SB181 became law, increasing the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development in a necessary and reasonable manner, and in October 2020, Colorado’s AQCC adopted new rules targeting air emissions from upstream oil and gas operation. Among other things, SB181 (i) repeals a prior law restricting local government land use authority over oil and gas mineral extraction areas to areas designated by the COGCC, (ii) directs the AQCC to review its leak detection and repair rules and to adopt rules to minimize emissions of certain air pollutants, (iii) clarifies that local governments have authority to regulate the siting of oil and gas locations in a necessary and reasonable manner, including the ability to inspect oil and gas facilities, impose fines for leaks, spills, and emissions, and impose fees on operators or owners to cover regulation and enforcement costs, (iv) allows local governments or oil and gas operators to request a technical review board to evaluate the effect of the local government’s preliminary or final determination on the operator’s application, (v) repeals an exemption for oil and gas production from counties’ authority to regulate noise, (vi) alters forced pooling requirements by increasing the threshold to compel non-consenting individuals into statutory pooling agreements and (vii) prioritizes the protection of public health, safety, and welfare, the environment, and wildlife resources in the regulation of oil and gas development. Although industry trade associations opposed SB181, Extraction has demonstrated an ability to continue to successfully operate our business. However, the enactment of SB181 and the development and implementation of related rules and regulations, which is under way, could lead to delays and additional costs to our business.
We cannot predict the nature or outcome of future ballot initiatives, legislative actions or other similar efforts, or the effects of implementation of SB181 by local governments in Colorado. The enactment of new regulations resulting from SB181 may lead to delays and additional costs to our operations. Furthermore, if we are required to cease operating in any of the areas in which we now operate as the result of bans, onerous regulations or moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition, and results of operations.
The adoption of new rules by the Colorado Oil & Gas Conservation Commission to require, among other things, new siting criteria for any oil and gas locations that are within 2,000 feet from building units, could reduce the area available for future oil and gas development in Colorado and have a material adverse effect on our business.
Resulting from Colorado’s adoption of SB181 during 2019, the COGCC recently promulgated rules associated with that legislation that will, among other things, impose mandatory 2,000 foot setbacks for all schools and childcare centers, as well as new siting criteria for any oil and gas locations that are within 2,000 feet of building units. The rules additionally require local government permitting approval that could add additional timing and complexity and potentially lengthen the pace of the oil and gas permitting process. These new rules went into effect on January 15, 2021. We cannot predict the ultimate impact of implementation of these new rules, including the imposition of 2,000-foot siting zones, but their enactment may lead to delays and additional costs to our operations and reduce the area available for future development of our operations.
We are subject to stringent environmental and health and safety laws and regulations that could expose us to significant costs and liabilities.
Our oil and natural gas exploration, development and production operations are subject to numerous stringent and complex federal, state and local laws and regulations governing safety and health aspects of our operations, the release, disposal or discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting drilling and
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other regulated activities; the restriction of types, quantities and concentration of materials that may be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring costly actions. For example, on May 2, 2017, following an incident in Firestone, Colorado, the COGCC issued a Notice to Operators (the “Notice”) that, among other things, required operators of oil and natural gas wells in Colorado re-inspect and/or properly abandon certain flowlines. On February 13, 2018, the COGCC approved new oil and natural gas flowline requirements, which included flowline tracking, record-keeping, integrity testing, and locking and marking requirements, as well as participation in centralized “call-before-you-dig” system. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective obligations, the occurrence of delays in permitting or development of projects and the issuance of orders limiting or prohibiting some or all of our operations in a particular area or forcing future compliance with environmental requirements.
The performance of our operations may result in significant environmental costs and liabilities due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances could expose us to material losses, expenditures and liabilities under environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition. We may not be able to recover some or any of our costs with respect to such developments from insurance. See “Business and Properties—Regulation of Environmental and Safety and Health Matters” for a further description of environmental and safety and health laws and regulations that affect us.
Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the EPAct 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC’s penalty authority is adjusted for inflation from time to time. FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the FTC has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1.0 million per day, and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business and Properties—Regulation of the Oil and Gas Industry.”
We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Additionally, citizen groups have brought and, in certain instances, may continue to bring legal proceedings against us to challenge our ability to receive environmental permits that we need to operate. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, loss of necessary environmental permits, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
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Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions or similar state agencies but several federal agencies have asserted regulatory authority over certain aspects of the process. In addition, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Also, from time to time, the U.S. Congress has considered, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. At the state level, Colorado, where we conduct operations, is among the states that has adopted, and other states are considering adopting, regulations that impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic fracturing operations. States may also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. In addition to state laws, local land use restrictions may restrict drilling or the hydraulic fracturing and cities may adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Moreover, because most of our operations are conducted in a particular area, the DJ Basin in Colorado, legal restrictions imposed in that area will have a significantly greater adverse effect than if we had our operations spread out amongst several diverse geographic areas. Consequently, in the event that local or state restrictions or prohibitions are adopted in the DJ Basin in Colorado that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing. Beginning in 2012, voters in the cities of Fort Collins, Boulder, Longmont, Broomfield and Lafayette, Colorado approved bans of varying length on hydraulic fracturing within their respective city limits. In 2014, Boulder and Larimer county lower courts overturned the bans. The cities of Longmont and Fort Collins appealed the decisions. In August 2015, the Court of Appeals requested that the Colorado Supreme Court rule on the issue. The Colorado Supreme Court struck down the Fort Collins and Longmont bans in May 2016. Nonetheless, extended moratoria, like that put in place by Boulder County in December 2016, remain a threat to oil and gas operations in Colorado.
Please read “Business and Properties—Regulation of Environmental and Safety and Health Matters—Hydraulic Fracturing Activities” for a further description of the laws and regulations relating to hydraulic fracturing that affect us.
Restrictions on drilling activities intended to protect certain species of wildlife and natural resources may adversely affect our ability to conduct drilling activities areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife and natural resources. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
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Some scientific studies have suggested that emissions of greenhouse gases may be contributing to warming of the earth’s atmosphere and other climatic changes. Such studies have resulted in increased local, state, regional, national, and international attention and actions relating to issues of climate change and the effect of GHG emissions, particularly emissions from fossil fuels. For example, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change (“UNFCCC”). The U.S. was among 195 nations that participated in the creation of an international accord in December 2015, the Paris Agreement, with the objective of limiting greenhouse gas emissions. The Paris Agreement entered into force on November 4, 2016 and, as of January 2020, had been ratified by 187 of the 197 parties to the UNFCC. The EPA has also taken action under the CAA to regulate greenhouse gas emissions. In addition, a number of states have either proposed or implemented restrictions on greenhouse gas emissions. International accords such as the Paris Agreement may result in additional regulations to control greenhouse gas emissions. Other developments focused on restricting GHG emissions include but are not limited to the Kyoto Protocol; the European Union Emission Trading System; the United Kingdom’s Carbon Reduction Commitment; and, in the U.S., the Regional Greenhouse Gas Initiative, the Western Regional Climate Action Initiative, and various state programs.
The enactment of derivatives legislation and associated regulations could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. While many rules implementing the Dodd-Frank Act have been finalized, some have not, and, as a result, the final form of the regulatory regime for commodity derivatives remains uncertain. Position limits for certain energy commodity futures and options contracts, as well as economically equivalent swaps, futures and options, are subject to ongoing rulemaking activities. With regard to position limits, in January 2020, the CFTC withdrew the 2013 proposal, the 2016 supplement, and the 2016 reproposal, and issued a new proposed rule which includes limits on positions in (1) certain “Core Referenced Futures Contracts,” including contracts for several energy commodities; (2) futures and options on futures that are directly or indirectly linked to the price of a Core Referenced Futures Contract, or to the same commodity for delivery at the same location as specified in that Core Referenced Futures Contract; and (3) economically equivalent swaps. The proposal also includes exemptions from position limits for bona fide hedging activities. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact our liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.
Risks Related to Capital
Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.
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The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development and acquisition of oil and natural gas reserves. In 2021, we plan to invest $140 million to $180 million for drilling and completion of operated and non-operated wells. We expect to fund our 2021 capital expenditures with borrowings under our RBL Credit Facility, cash flows from operations and possibly through asset sales or additional capital markets transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Item 7. in Part I of this Annual Report.
A negative shift in investor sentiment of the oil and gas industry could have adverse effects on our ability to raise debt and equity capital and on our operations.
Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
Additionally, negative public perception regarding us and/or our industry may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business. Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.
Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the United States financial market have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.
We may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations.
Declines in commodity prices may cause the financial markets to exert downward pressure on stock prices and credit capacity for companies throughout the energy industry. For example, during 2020, the market for senior unsecured notes was unfavorable for high-yield issuers such as us. Our plans for growth may require access to the capital and credit markets,
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including the ability to issue senior unsecured notes. Although the market for high-yield debt securities has experienced periods of improvement in the past, if the high-yield market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and our ability to service our indebtedness.
Risks Related to Debt
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our existing and future debt arrangements, including the RBL Credit Facility, contain or may contain a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:
•incur additional indebtedness;
•sell assets;
•make loans to others;
•make certain acquisitions and investments;
•enter into mergers, consolidations or other transactions resulting in the transfer of all or substantially all of our assets;
•make certain payments, including paying dividends or distributions in respect of our equity;
•hedge future production or interest rates;
•redeem and prepay other debt;
•incur liens; and
•engage in certain other transactions without the prior consent of the lenders.
In addition, our debt arrangements require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our debt arrangements will impose on us.
Our RBL Credit Facility limits the amount we can borrow up to the lower of our aggregate lender commitments and a borrowing base amount, which the lenders, in their sole discretion, will determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The lenders will be able to unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our RBL Credit Facility. We will be required to repay any outstanding borrowings in excess of the then current borrowing base. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders does not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such lenders. Our borrowing base is currently $500.0 million, subject to the current elected lending commitments of $500.0 million.
A breach of any covenant in our RBL Credit Facility or any other debt agreement would result in a default after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the facility and a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. In addition, our obligations under our RBL Credit Facility are secured by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 90% of the reserve value as determined by reserve reports, and if we are unable to repay our indebtedness under the RBL Credit Facility, the lenders could seek to foreclose on our assets.
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The borrowing base under our RBL Credit Facility may be reduced in connection with declines in commodity prices, which could hinder or prevent us from meeting our future capital needs.
The borrowing base under our RBL Credit Facility is currently $500.0 million, and current elected lending commitments under the RBL Credit Facility are $500.0 million. Our borrowing base is redetermined semiannually on each May 1 and November 1 (or once per year between these dates) based on certain factors, including our reserves and hedge position, with the next borrowing base redetermination scheduled to occur in May 2021. Our borrowing base may decrease as a result of declines in natural gas, NGLs, and oil prices, or as a result of operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or other reasons. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, we may be unable to meet our obligations as they come due and could be required to repay any indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and our ability to service our indebtedness.
Availability, terms and cost of capital, increases in interest rates or a reduction in credit rating could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our RBL Credit Facility, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If oil and natural gas prices exhibit weakness for an extended period of time, we may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our RBL Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
Risks Related to our Common Stock
We have restated prior financial statements, which may lead to additional risks and uncertainties, including increased possibility of legal proceedings and loss of investor confidence.
We have restated our condensed consolidated financial statements as of and for the three and nine months ended September 30, 2019 in order to correct an accounting error. As a result of the Restatement, we have become subject to possible additional costs for accounting and legal fees in connection with or related to the restatement and additional risks and uncertainties, including, among others, the increased possibility of legal proceedings, shareholder lawsuits or a review by the SEC and other regulatory bodies, which could cause investors to lose confidence in our reported financial information and could subject us to civil or criminal penalties, shareholder class actions or derivative actions. We could face monetary judgments,
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penalties or other sanctions that could have a material adverse effect on our business, financial condition and results of operations and could cause our stock price to decline.
If we fail to meet the requirements for continued listing on the NASDAQ Global Select Market, our common stock could be delisted, which would decrease the liquidity of our common stock and our ability to raise additional capital.
Our common stock was traded on the NASDAQ under the symbol “XOG” until June 25, 2020. On June 16, 2020, we received a letter from the NASDAQ notifying us that, as a result of the Chapter 11 Cases and in accordance with NASDAQ rules, our securities would be delisted at the opening of business on June 25, 2020. On June 25, 2020, our common stock began to be quoted on the Pink Open Market under the symbol “XOGAQ”. In connection with our emergence from bankruptcy, our common stock was relisted on the NASDAQ Global Select Market on January 21, 2021 trading under the symbol “XOG.”
Our common stock is currently listed for quotation on the NASDAQ Global Select Market. We are required to meet specified requirements to maintain our listing on the NASDAQ Global Select Market, including, among other things, a minimum bid price of $1.00 per share. If we fail to satisfy the NASDAQ Global Select Market’s continued listing requirements, we may be delisted and the quotation of our common stock may be transferred to the OTC Bulletin Board. Having our common stock quoted on the OTC Bulletin Board could adversely affect the liquidity of our common stock. Any such transfer could make it more difficult to dispose of, or obtain accurate quotations for the price of, our common stock, and there also would likely be a reduction in our coverage by securities analysts and the news media, which could cause the price of our common stock to decline further. We may also face other material adverse consequences in such event, such as negative publicity, a decreased ability to obtain additional financing, diminished investor and/or employee confidence, and the loss of business development opportunities, any of which may contribute to a further decline in our stock price.
Our amended and restated certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
•limitations on the removal of directors;
•limitations on the ability of our stockholders to call special meetings;
•establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and
•providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws.
When conditions are right and certain requirement have been met, we intend to begin paying dividends on our common stock. Our debt arrangements place certain restrictions on our ability to do so. Consequently, it is possible that the only opportunity to achieve a return on an investment in our common stock will be if the price of our common stock appreciates.
We plan to declare dividends on shares of our common stock in the foreseeable future if certain requirements are met as stated in the RBL Credit Agreement. However, our debt arrangements restrict our ability to pay cash dividends when certain requirements have not been met. Consequently, it is possible that the only opportunity to achieve a return on an investment in our common stock will be if shareholders sell their common stock at a price greater than they paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that such investors paid for our common stock. There is no guarantee we will ever pay dividends.
Future sales of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute the ownership in us by current shareholders.
We may sell additional shares of common stock in public or private offerings. We may also issue additional shares of common stock or convertible securities. We have 25.7 million outstanding shares of common stock as of March 15, 2021. Subject to the satisfaction of vesting conditions, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.
We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
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The market price of our securities is subject to volatility.
Upon our emergence from the Chapter 11 Cases, our Predecessor Common Stock was exchanged for New Common Stock (as defined in Note 1 — Business and Organization in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report). The market price of our New Common Stock could be subject to wide fluctuations in response to, and the level of trading that develops with our New Common Stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the lack of comparable historical financial information due to our adoption of fresh-start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A. — Risk Factors section of this Annual Report.
The exercise of all or any number of outstanding warrants, the issuance of stock-based awards or the issuance of our common stock to settle the claims of general unsecured claimants may dilute your holding of shares of our common stock.
Upon emergence from bankruptcy on January 20, 2021, we entered into a Tranche A Warrant Agreement and Tranche B Warrant Agreements (each as defined Note 8 — Long-Term Debt in Part II, Item 8. Financial Information of this Annual Report), pursuant to which, as of January 31, 2021, the Company had approximately 2.9 million and 1.5 million of Tranche A Warrants and Tranche B Warrants issued and outstanding, respectively. The exercise of equity awards, including any stock options that we may grant in the future, or the warrants and any issuance of our common stock to general unsecured claimants could dilute your holding of shares of our common stock, which could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim for a breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
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Risks Related to Taxes
Recent changes in United States federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition overall.
On March 27, 2020, the U.S. Congress enacted into U.S. federal law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), which, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. In particular, under the CARES Act, (i) NOLs arising in 2018, 2019, and 2020 taxable years may be carried back to each of the preceding five years and offset 100% of taxable income for tax years beginning before 2021, and (ii) for taxable years beginning in 2019 and 2020, the base for interest deductibility is increased. Future regulatory guidance may be forthcoming, and such guidance could ultimately increase or lessen this legislation’s impact on our business and financial condition. It is also possible that Congress will enact additional legislation in connection with COVID-19, some of which could have an impact on the Company.
Certain United States federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Future adverse changes could include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
Our ability to use our NOL carryforwards and other tax attributes may be limited.
Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income NOLs carried forward from prior years. We had U.S. federal NOLs of approximately $1.3 billion as of December 31, 2020. However, we expect that we will be required to substantially reduce or eliminate certain of our tax attributes, including NOL carryforwards, as a result of cancellation of indebtedness income realized in connection with the Chapter 11 Cases. Additionally, the consummation of the Plan on the Emergence Date resulted in an “ownership change,” under Section 382 of the Code. Absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its pre-ownership change net operating losses that may be utilized to offset future taxable income generally will be subject to an annual limitation equal to the value of its stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate, plus an additional amount calculated based on certain “built in gains” in its assets that may be deemed to be realized within a 5-year period following any ownership change. This limitation, in the case of the ownership change that occurred as a result of the consummation of the Plan, will be subject to additional rules under Sections 382(l)(5) or (l)(6) of the Code, depending upon whether we are eligible for the application of Section 382(l)(5) of the Code and, if so eligible, whether we affirmatively elect not to apply Section 382(l)(5) of the Code. As a result of such limitation, our ability to utilize any NOLs or other tax attributes that are not eliminated as a result of cancellation of indebtedness income arising from the consummation of the Plan may be materially limited in the future.
Risks Related to Technology
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
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Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.
Loss of our information and computer systems could adversely affect our business.
We are dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
Conservation measures and technological advances could reduce demand for oil, natural gas and NGL.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGL, technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGL. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Risks Related to the General Business
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.
We have grown rapidly since we began operations in late 2012. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:
•increased responsibilities for our executive level personnel;
•increased administrative burden;
•increased capital requirements; and
•increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the
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future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential liabilities, including environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of oil and gas properties or businesses that complement or expand our current business. The successful acquisition of oil and gas properties requires an assessment of several factors, including:
•recoverable reserves;
•future oil, natural gas and NGL prices and their applicable differentials;
•operating costs; and
•potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, our debt arrangements will impose certain limitations on our ability to enter into mergers or combination transactions. Our debt arrangements will also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.
We may be subject to risks in connection with divestitures
In 2020, we announced our ongoing initiative to divest of non-strategic assets in order to increase capital resources available for other core assets, create organizational and operational efficiencies or for other purposes and completed divestitures of several of our non-strategic assets and we have additional divestitures pending, as discussed in “Business and Properties —Recent Developments.” Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchases willing to acquire the assets with terms we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific further action.
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Sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
Our cash flow from operations and access to capital are subject to a number of variables, including:
•our proved reserves;
•the level of hydrocarbons we are able to produce from existing wells;
•the prices at which our production is sold;
•the availability of takeaway capacity;
•our ability to acquire, locate and produce new reserves; and
•our ability to borrow under our RBL Credit Facility.
If our revenues or the borrowing base under our RBL Credit Facility decreases as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our RBL Credit Facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and a failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our business, financial condition, results of operations or cash flows.
Our future growth prospects are dependent upon our ability to identify optimal strategies for investing our capital resources to produce rates of return. In developing our business plan, we consider allocating capital and other resources to various aspects of our business including well development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also consider our likely sources of capital, including cash generated from operations and borrowings under our credit agreement. Notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, natural gas and NGL, we enter into commodity derivative contracts for a significant portion of our production, primarily consisting of swaps, put options and call options. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Sources of Our Revenues” in Part II, Item 7. of this Annual Report. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
•production is less than the volume covered by the derivative instruments;
•the counterparty to the derivative instrument defaults on its contractual obligations;
•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
•there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas and NGL prices and
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interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGL, which could also have an adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. While we utilize multiple counterparties, if the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.
Approximately 46% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
As of December 31, 2020, approximately 46% of our net leasehold acreage was undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
We are required to pay fees to our service providers based on minimum volumes under long-term contracts regardless of actual volume throughput.
We may enter into firm transportation, gas processing, gathering and compression service, water handling and treatment, or other agreements that require minimum volume delivery commitments. If we have insufficient production to meet the minimum volumes under these agreements or any other firm commitment agreement we may enter into, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results or operations.
In February 2019, we entered into a long-term gas gathering and processing agreements with a third-party midstream provider. The agreement commenced on January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten. The agreement also includes a commitment to sell take-in-kind NGLs of 4,000 Bbl/d in year one, 7,500 Bbl/d in years two through seven with the ability to roll up to a 10% shortfall in a given month to the subsequent month. On December 23, 2020, we entered into a settlement with the counterparty and amended the agreement. As part of the settlement and amended agreement, there were no changes made to the minimum volume commitments. We may be required to pay a shortfall fee for any volume deficiencies under these commitments, calculated based on the applicable gathering and processing fees and/or, with respect to the NGL commitment, the NGL transport cost.
If we are unable to meet our commitments under the Elevation Gathering Agreements, we may incur additional costs.
If we are unable to meet our commitments under the Elevation Gathering Agreements, we may be required to incur additional costs. For example, if we fail to complete wells by the commitment deadline, we would be deemed to be in breach of the agreements and Elevation would be entitled to make a claim for damages against us and our affiliates.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.
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We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.
We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.
As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGL we produce.
The availability of a ready market for any oil, natural gas and NGL we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “Business and Properties—Operations—Marketing and Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.
The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.
We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. Three, one and two purchasers accounted for more than 10% of our revenues in the years ended December 31, 2020, 2019 and 2018, respectively. During 2021, we no longer sell to our largest and third largest purchasers in 2020. Rather, we have increased our sales to our second largest purchaser in 2020 and began selling to a new midstream oil marketer who has replaced our largest purchaser in 2020. This concentration of purchasers may impact our overall credit risk in that these entities may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or land men who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Competition in the oil and natural gas industry and from alternative energy sources is intense, making it more difficult for us to acquire properties and market oil or natural gas.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.
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We also face indirect competition from alternative energy sources, including wind, solar, nuclear and electric power. The proliferation of alternative energy sources and businesses that provide such alternative energy sources may decrease the demand for oil and natural gas products. Decreased demand for our products could adversely affect our business, financial condition, results of operations or cash flows.
Climate change legislation or regulations restricting emissions of GHG could result in increased operating costs and reduced demand for the oil, natural gas and NGL that we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. Additionally, growing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has adopted rules under authority of the CAA that, among other things, establish PSD construction and Title V permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards for those emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among other things, onshore producing facilities, which include certain of our operations. Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations, with the EPA publishing NSPS Subpart OOOOa standards in June 2016 that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions and the BLM publishing requirements in November 2016 to reduce methane emissions from venting, flaring, and leaking on public lands. Both of the EPA and BLM took steps to relax or rescind certain requirements under their respective methane rules. In September 2019, EPA published proposed amendments that would rescind the methane standards and roll back other requirements of the NSPS OOOOa standards and, in September 2018, BLM issued a rule that relaxes or rescinds requirements of its November 2016 regulations. California and New Mexico have challenged BLM’s September 2018 rule in ongoing litigation. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement and on November 4, 2019, the U.S. submitted formal notification of its withdrawal to the United Nations. However, during the first part of 2021, the United States, under a new presidential administration, rejoined the Paris Agreement.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHG or otherwise limit emissions of GHG from, our equipment and operations could result in increased costs to reduce emissions of GHG associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil, natural gas and NGL we produce and lower the value of our reserves, which devaluation could be significant. One or more of these developments could have a materially adverse effect on our business, financial condition and results of operations. Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to rise and will not peak until after 2040 and oil and gas will continue to represent a substantial percentage of global energy use over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Please read “Business and Properties—Regulation of Environmental and Safety and Health Matters—Regulation of Greenhouse Gas (“GHG”) Emissions” for a further description of the laws and regulations relating to climate change that affect us.
Adverse weather conditions may negatively affect our ability to conduct drilling activities and our operating results.
Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, lost or damaged facilities and equipment, power failures, and temporary shut-in of production. Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services,
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such as gathering, processing, compression and transportation services. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.
Risks Related to the COVID-19 Pandemic
Outbreaks of communicable diseases, including the COVID-19 pandemic, could adversely affect our business, financial condition, results of operations and cash flows.
Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products. For example, there have been recent outbreaks in many countries, including the United States, of a highly transmissible and pathogenic coronavirus, which the World Health Organization declared a pandemic in March 2020. The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact and length of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition, results of operations and cash flows.
Additionally, in response to the COVID-19 pandemic, our corporate staff has begun working remotely and many of our key vendors, service suppliers and partners have similarly begun to work remotely. As a result of such remote work arrangements, certain operational, reporting, accounting and other processes may slow, which could result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies. Also, in the event that there is an outbreak of COVID-19 at any of our operating locations, we could be forced to cease operations at such location. Any of the foregoing could adversely affect our business, financial condition, results of operations and cash flows.
The ongoing COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries may result in transportation and storage constraints, reduced production and shut-in of our wells, any of which would adversely affect our business, financial condition and results of operations.
The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. We experienced substantial decreases in our revenues beginning in the first quarter of 2020 and lasting through the end of the year, which negatively impacted our business, financial condition, results of operations, cash flows and outlook during 2020. Due to the commodity price environment, we postponed or eliminated a portion of our developmental drilling in 2020. A sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, have required us to reevaluate and further postpone or eliminate additional drilling. Such actions resulted in the reduction of our PUDs and related PV-10 and a reduction in our ability to service our debt obligations. More recently, however, reduction in oil and gas activity as a result of the COVID-19 pandemic has resulted in a decrease of production as fewer oil wells are drilled, which has led to a contraction in domestic oil and gas supply. Lower levels of supply have pushed current and forecasted oil and gas prices higher, which we expect to have a positive impact on our results of operations and cash flows. To the extent, however, that the outbreak of COVID-19 continues to negatively impact demand and we are required to further curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices remain weak, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.
Risks Related to Bankruptcy
We recently emerged from bankruptcy, which may adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our recent emergence from the voluntary cases under chapter 11 of the Bankruptcy Code may adversely affect our business and relationships with customers, vendors, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:
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•key suppliers, vendors or other contract counterparties may terminate their relationships with us, require additional financial assurances or enhanced performance from us or pursue unreasonable fee increases for their goods or services;
•our ability to renew existing contracts and compete for new business may be adversely affected;
•our ability to attract, motivate and/or retain key employees and executives may be adversely affected;
•landowners may not be willing to lease acreage to us; and
•competitors may take business away from us and our ability to attract and retain customers may be negatively impacted.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our historical financial information may not be indicative of future financial performance.
Our capital structure was significantly impacted by the Plan. Under fresh-start accounting rules that applied to us upon the Emergence Date, assets and liabilities were adjusted to fair values. Accordingly, because fresh-start accounting rules applied, our financial condition and results of operations following emergence from the Chapter 11 Cases will not be comparable to the financial condition and results of operations reflected in our historical financial statements.
Upon our emergence from the Chapter 11 Cases, the composition of our board of directors changed significantly.
Pursuant to the Plan, the composition of our board of directors changed significantly. Upon emergence, our Board consists of seven directors, none of whom served on the Board prior to our emergence from the Chapter 11 Cases. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our Board and, thus, may have different views on the issues that will determine our future. There is no guarantee that our new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and our plans may differ materially from those of the past.
The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from the Chapter 11 Cases.
The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from the Chapter 11 Cases, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.
We may be negatively impacted by litigation and legal proceedings, including ongoing claims in connection with the Chapter 11 Cases.
We are subject from time to time, and in the future may become subject, to litigation claims. These claims and legal proceedings are typically claims that arise in the normal course of business and include, without limitation, claims relating to environmental, safety and health matters, commercial or contractual disputes with suppliers and customers, claims regarding ownership of mineral interests, including from royalty owners, claims regarding acquisitions and divestitures, regulatory matters and employment and labor matters. We may also become subject to governmental or regulatory proceedings. The outcome of such claims and legal proceedings cannot be predicted with certainty and some may be disposed of unfavorably to us. In addition, the claims resolutions process in connection with the Chapter 11 Cases is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court. The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose before confirmation of the Plan (i) would be subject to compromise and/or treatment under the Plan and/or (ii) would be discharged in accordance with the terms of the Plan. Any claims not ultimately discharged through the Plan could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis. To the extent that these legal proceedings result in claims being allowed against us, such claims will be satisfied through the issuance of shares of our common stock, except as noted herein. As a result, we have not established reserves within our liabilities in connection with these claims. However, it is possible with respect to certain claims that the ultimate outcome of the legal proceedings may result in the contracts not being treated as rejected or the amounts at issue being treated as administrative claims by the Bankruptcy Court, either of which could require us to make cash payments to resolve claims instead of issuing shares of our common stock or require us to establish reserves and accrue liabilities with respect to such claims at a future date. We also may not have insurance that covers such claims and legal proceedings. Successful claims or litigation against us for significant amounts could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows. Further, even if successful in resolving a claim or legal proceeding, such process could require the attention of members of our senior management, reducing the time they have available to devote to managing our business, and require us to incur substantial legal expenses.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments from the SEC staff regarding our reports under the Exchange Act of 1934, as amended (the “Exchange Act”).
ITEM 3. LEGAL PROCEEDINGS
We are involved in various legal proceedings and review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our business, financial position, results of operations or liquidity.
COGCC Notices of Alleged Violations (“NOAVs”). We have received NOAVs from the COGCC for alleged compliance violations that we have responded to. We do not believe penalties that could result from these NOAVs will have a material effect on our business, financial condition, results of operations or liquidity, but Extraction is in negotiations to settle all of its outstanding NOAVs with the COGCC, and the ultimate settlement amount is expected to exceed $600,000.
The information set forth in Note 16 — Commitments and Contingencies — Litigation and Legal Items, to the accompanying consolidated financial statements included in this Annual Report on Form 10-K is incorporated by reference into this Item 3.
For information on the Chapter 11 Cases, see Items 1. and 2. — Business and Properties — Recent Developments — Chapter 11 Cases which information is incorporated herein by reference.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information.
Our common stock is currently traded on the NASDAQ under the ticker symbol “XOG.”
NASDAQ Delisting and Relisting
Our common stock was traded on the NASDAQ under the symbol “XOG” until June 25, 2020. On June 16, 2020, we received a letter from the NASDAQ notifying us that, as a result of the Chapter 11 Cases and in accordance with NASDAQ rules, our securities would be delisted at the opening of business on June 25, 2020. On June 25, 2020, our common stock began to be quoted on the Pink Open Market under the symbol “XOGAQ”. In connection with our emergence from bankruptcy, our common stock was relisted on the NASDAQ Global Select Market on January 21, 2021 trading under the symbol “XOG.”
Dividend Policy
We have not historically paid any cash dividends to holders of our common stock.
Holders
Pursuant to the records of the transfer agent, as of March 15, 2021 the number of holders of record of our common stock was 233.
Sales of Unregistered Securities
We did not have any sales of unregistered securities during the fiscal year ended December 31, 2020.
Issuer Purchases of Equity Securities
We did not have any share repurchase activity during the three months ended December 31, 2020.
ITEM 6. SELECTED FINANCIAL DATA
The information responsive to Item 301 of Regulation S-K is not required of smaller reporting companies.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes appearing in “Item 8. Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
This section of this Form 10-K generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Form 10-K and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2019 and are incorporated herein by reference.
OVERVIEW
We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserve in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development drilling opportunities on high resource-potential leasehold on contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin.
Our Properties and Operations
We have assembled, as of December 31, 2020, approximately 140,000 net acres of large, contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin as indicated by the results of our horizontal drilling program and the results of offset operators. Additionally, we hold approximately 96,700 net acres outside of what we consider our Core DJ Basin, which we refer to as our “Other Rockies Area,” that we believe has many of the same formations as our properties in the Core DJ Basin. We operated 99% of our horizontal production for the year ended December 31, 2020, our total estimated proved reserves were approximately 145.9 MMBoe, of which approximately 77% were classified as proved developed reserves. For more information about our properties, please read Items 1. and 2. Business and Properties — Our Properties in Part 1 of this Annual Report.
Deconsolidation of Elevation Midstream, LLC
Please see Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for information related to the deconsolidation of Elevation Midstream, LLC.
Financial Overview
For the year ended December 31, 2020, we had a net loss of $1.3 billion as compared to net loss of $1.4 billion for the year ended December 31, 2019. The decrease in net loss was primarily driven by a decrease in operating expenses of $1.1 billion, which includes a decrease of $1.1 billion in the impairment of long-lived assets, and a change from a loss to a gain on commodity derivatives of $202.1 million. These were offset by a decrease in sales revenues of $348.7 million, $676.9 million in reorganization items which did not exist in 2019, and a $73.1 million loss on deconsolidation of Elevation Midstream, LLC which also did not exist in 2019. Additionally, interest expense decreased $22.1 million.
For the year ended December 31, 2020, crude oil, natural gas, NGL sales and gathering and compression revenue, coupled with the impact of settled derivatives, decreased to $650.7 million as compared to $881.9 million in the same prior year period due to a decrease of $7.24 in realized price per BOE, including settled derivatives, offset by an increase in sales volumes
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of approximately 155 MBoe. During June 2020, we unwound the majority of our hedges when we filed for bankruptcy and received aggregate settlement proceeds of $96.1 million.
Adjusted EBITDAX was $449.2 million for the year ended December 31, 2020, as compared to $610.7 million in the same period in 2019, reflecting a 26% decrease. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Adjusted EBITDAX.”
Operational Overview
During the year ended December 31, 2020, we focused on emerging from bankruptcy, improving free cash flow and implemented operational efficiencies to reduce drilling, completion and operating costs. We incurred approximately $159.6 million in drilling 37 gross (25.7 net) wells with an average lateral length of 2.3 miles and completing 45 gross (34.1 net) wells with an average lateral length of 2.4 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately $16.9 million of leasehold and surface acreage additions.
How We Evaluate Our Operations
We use various financial and operational metrics to assess the performance of our oil and gas operations, including:
•Sources of revenue;
•Sales volumes;
•Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts;
•Lease operating expenses (“LOE”);
•Capital expenditures;
•Adjusted EBITDAX (a Non-GAAP measure); and
•Free cash flow (a Non-GAAP measure).
Sources of Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the year ended December 31, 2020, our revenues were derived 69% from oil sales, 17% from natural gas sales and 14% from NGL sales. For the year ended December 31, 2019, our revenues were derived 80% from oil sales, 12% from natural gas sales and 8% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
Sales Volumes
The following table presents historical sales volumes for the periods indicated:
| For the Year Ended | |||||||||||
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Oil (MBbl) | 12,543 | 15,436 | |||||||||
| Natural gas (MMcf) | 72,311 | 64,710 | |||||||||
| NGL (MBbl) | 7,945 | 6,164 | |||||||||
| Total (MBoe) | 32,540 | 32,385 | |||||||||
| Average net sales (BOE/d) | 88,907 | 88,728 | |||||||||
As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic growth as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read Item 1A. Risk Factors — Risks Related to the Oil, Natural Gas and NGL Industry and Our Business in Part 1 of this Annual Report for a further description of the risks that affect us.
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Realized Prices on the Sale of Oil, Natural Gas and NGL
Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL and our ability to market our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period from January 1, 2014 to December 31, 2020, NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of negative $37.63 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.48 per MMBtu during the same period. Declines in, and continued depression of, the price of oil and natural gas occurring during 2015, 2019 and 2020 are due to a combination of factors including increased U.S. supply, global economic concerns stemming from COVID-19 and the price war between Russia and Saudi Arabia. These price variations can have a material impact on our financial results and capital expenditures.
Oil pricing is predominantly driven by the physical market, supply and demand, financial markets and national and international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials.
Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The price we receive for our natural gas produced in the DJ Basin is based on CIG prices, adjusted for certain deductions.
Our price for NGL produced in the DJ Basin is based on a combination of prices from the Conway hub in Kansas and Mont Belvieu in Texas where this production is marketed.
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The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and NGL normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, as applicable.
| For the Year Ended | |||||||||||
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Oil | |||||||||||
| NYMEX WTI High ($/Bbl) | $ | 63.27 | $ | 66.30 | |||||||
| NYMEX WTI Low ($/Bbl) | $ | (37.63) | $ | 46.54 | |||||||
| NYMEX WTI Average ($/Bbl) | $ | 39.34 | $ | 57.04 | |||||||
Average Realized Price ($/Bbl) (1) | $ | 30.50 | $ | 46.74 | |||||||
Average Realized Price, with derivative settlements ($/Bbl) (1) | $ | 37.15 | $ | 45.16 | |||||||
| Average Realized Price as a % of Average NYMEX WTI | 77.5 | % | 81.9 | % | |||||||
Differential ($/Bbl) to Average NYMEX WTI (2) | $ | (7.92) | $ | (8.71) | |||||||
| Natural Gas | |||||||||||
| NYMEX Henry Hub High ($/MMBtu) | $ | 3.35 | $ | 3.59 | |||||||
| NYMEX Henry Hub Low ($/MMBtu) | $ | 1.48 | $ | 2.07 | |||||||
NYMEX Henry Hub Average ($/MMBtu) (3) | $ | 2.34 | $ | 2.78 | |||||||
Average Realized Price ($/Mcf) | $ | 1.34 | $ | 1.68 | |||||||
Average Realized Price, with derivative settlements ($/Mcf) | $ | 1.47 | $ | 1.68 | |||||||
Average Realized Price as a % of Average NYMEX Henry Hub (3) | 57.3 | % | 60.4 | % | |||||||
Differential ($/Mcf) to Average NYMEX Henry Hub (3) | $ | (1.00) | $ | (1.10) | |||||||
| NGL | |||||||||||
Average Realized Price ($/Bbl) | $ | 9.72 | $ | 12.18 | |||||||
Average Realized Price as a % of Average NYMEX WTI | 24.7 | % | 21.4 | % | |||||||
(1)Includes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the years ended December 31, 2020, and December 31, 2019, pursuant to ASC 606, Revenue Recognition.
(2)Excludes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the year ended December 31, 2020, and December 31, 2019, pursuant to ASC 606, Revenue Recognition.
(3)Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf using a conversion factor of 1.1 to 1.
Derivative Arrangements
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time, we enter into derivative arrangements for our oil and natural gas production. By removing a significant portion of price volatility associated with our oil and natural gas production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts.
We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We have relied on a variety of hedging strategies and instruments to hedge our future price risk. We have utilized swaps, put options and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production. We expect to continue to use a variety of hedging strategies and instruments for the foreseeable future.
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The hedge prices will depend on the commodity price environment at the time those hedge transactions are entered into. Our ability to enter into derivative arrangements at favorable prices may be limited, and, under our RBL Credit Agreement (as defined in Note 8—Long-Term Debt in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report), we are obligated to hedge a specific portion of our oil or natural gas production. The RBL Credit Agreement requires us to maintain commodity hedges covering a minimum of 65% of our anticipated oil and gas production from PDP reserves for the succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the next succeeding twelve months.
For a description of our derivative instruments that we utilize and a summary of our open commodity derivative contracts as of December 31, 2020, please see Note 9 — Commodity Derivative Instruments in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated.
| For the Year Ended December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| NYMEX WTI Crude Swaps: | |||||||||||
| Notional volume (Bbl) | 4,316,000 | 9,830,000 | |||||||||
| Weighted average fixed price ($/Bbl) | $ | 49.16 | $ | 53.08 | |||||||
| NYMEX WTI Crude Purchased Puts: | |||||||||||
| Notional volume (Bbl) | 4,950,000 | 22,050,000 | |||||||||
| Weighted average purchased put price ($/Bbl) | $ | 54.48 | $ | 46.87 | |||||||
| NYMEX WTI Crude Purchased Calls: | |||||||||||
| Notional volume (Bbl) | 1,100,000 | 18,350,000 | |||||||||
| Weighted average purchased call price ($/Bbl) | $ | 68.04 | $ | 65.74 | |||||||
| NYMEX WTI Crude Sold Calls: | |||||||||||
| Notional volume (Bbl) | 5,650,000 | 22,300,000 | |||||||||
| Weighted average sold call price ($/Bbl) | $ | 63.37 | $ | 64.57 | |||||||
NYMEX WTI Crude Sold Puts: | |||||||||||
| Notional volume (Bbl) | 5,300,000 | 22,350,000 | |||||||||
| Weighted average sold put price ($/Bbl) | $ | 44.39 | $ | 45.11 | |||||||
| NYMEX HH Natural Gas Swaps: | |||||||||||
| Notional volume (MMBtu) | 31,000,000 | 32,400,000 | |||||||||
| Weighted average fixed price ($/MMBtu) | $ | 2.66 | $ | 2.81 | |||||||
| NYMEX HH Natural Gas Purchased Puts: | |||||||||||
| Notional volume (MMBtu) | 600,000 | 3,600,000 | |||||||||
| Weighted average purchased put price ($/MMBtu) | $ | 2.90 | $ | 3.04 | |||||||
| NYMEX HH Natural Gas Sold Calls: | |||||||||||
| Notional volume (MMBtu) | 600,000 | 3,600,000 | |||||||||
| Weighted average sold call price ($/MMBtu) | $ | 3.48 | $ | 3.46 | |||||||
| NYMEX HH Natural Gas Sold Puts: | |||||||||||
| Notional volume (MMBtu) | — | 3,000,000 | |||||||||
| Weighted average fixed basis price ($/MMBtu) | $ | — | $ | 2.50 | |||||||
| CIG Basis Gas Swaps: | |||||||||||
| Notional volume (MMBtu) | 27,600,000 | 42,200,000 | |||||||||
| Weighted average fixed basis price ($/MMBtu) | $ | (0.58) | $ | (0.73) | |||||||
| Total Amounts Received/(Paid) from Settlement (in thousands) | $ | 188,822 | $ | (5,790) | |||||||
| Cash (used in) provided by changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives | $ | (2,957) | $ | 5,112 | |||||||
| Derivative unwinds reducing the Prior Credit Facility balance | $ | (96,065) | $ | — | |||||||
| Settlements on Commodity Derivatives per Consolidated Statements of Cash Flows | $ | 89,800 | $ | (678) | |||||||
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Lease Operating Expenses
All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constitutes part of the current operating expenses of a working interest. Such costs include labor, supplies, repairs, maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.
Capital Expenditures
For the year ended December 31, 2020, we incurred approximately $159.6 million in drilling and completion capital expenditures. For the year ended December 31, 2020, we drilled 37 gross (25.7 net) wells with an average lateral length of approximately 2.3 miles and completed 45 gross (34.1 net) wells with an average lateral length of approximately 2.4 miles. We turned to sales 49 gross (36.5 net) wells with an average lateral length of approximately 2.4 miles. In addition, we incurred approximately $16.9 million of leasehold and surface acreage additions.
Our 2021 capital budget for the drilling and completion of operated and non-operated wells is approximately $140 million to $180 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 34 gross operated wells, complete 49 gross operated wells and turn-in-line 44 gross operated wells. Our 2021 capital budget anticipates a one-rig drilling program we expect to operate most of the year.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer or accelerate a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.
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Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income (loss) as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net loss adjusted for certain cash and non-cash items, including depletion, depreciation, amortization and accretion (DD&A), impairment of long lived assets, non-recurring charges in other operating expenses, exploration and abandonment expenses, (gain) loss on sale of property and equipment, commodity derivatives (gain) loss, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the period, stock-based compensation expense, amortization of debt issuance costs, interest expense, gain on repurchase of senior notes, income tax benefit, loss on deconsolidation of Elevation Midstream, LLC and reorganization items, net. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. See Note 18 — Segment Information in Part II, Item 8 of this Annual Report for more information regarding the EBITDAX of reportable segments.
Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure (i) is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors; (ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and (iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting.
The following table presents a reconciliation of the GAAP financial measure net loss to Adjusted EBITDAX for each of the periods indicated (in thousands).
| For the Year Ended | |||||||||||
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Reconciliation of Net Loss to Adjusted EBITDAX: | |||||||||||
| Net Loss | $ | (1,267,534) | $ | (1,367,420) | |||||||
| Add back: | |||||||||||
| Depletion, depreciation, amortization and accretion | 332,319 | 524,537 | |||||||||
| Impairment of long lived assets | 208,463 | 1,337,996 | |||||||||
| Other operating expenses | 79,615 | — | |||||||||
| Exploration and abandonment expenses | 258,932 | 88,794 | |||||||||
| (Gain) loss on sale of property and equipment | (122) | 421 | |||||||||
| Commodity derivative (gain) loss | (164,968) | 37,107 | |||||||||
| Settlements on commodity derivative instruments | 188,822 | (5,790) | |||||||||
| Premiums paid for derivatives that settled during the period | — | (18,929) | |||||||||
| Stock-based compensation expense | 6,511 | 43,954 | |||||||||
| Amortization of debt issuance costs | 3,685 | 5,482 | |||||||||
| Interest expense | 53,458 | 84,236 | |||||||||
| Gain on repurchase of 2026 Senior Notes | — | (10,486) | |||||||||
| Income tax benefit | — | (109,176) | |||||||||
| Loss on deconsolidation of Elevation Midstream, LLC | 73,139 | — | |||||||||
| Reorganization items, net | 676,855 | — | |||||||||
| Adjusted EBITDAX | $ | 449,175 | |||||||||