|TEV||4,741||TEV/EBIT||15||TTM 2019-09-30, in MM, except price, ratios|
|8-K||2021-01-26||Off-BS Arrangement, Exhibits|
|8-K||2021-01-11||Other Events, Exhibits|
|8-K||2021-01-07||Other Events, Exhibits|
|8-K||2021-01-04||Off-BS Arrangement, Exhibits|
|8-K||2020-12-17||Other Events, Exhibits|
|Item 1A. Risk Factors|
|Item 1B. Unresolved Staff Comments|
|Item 3. Legal Proceedings|
|Item 4. Mine Safety Disclosures|
|Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities|
|Item 6. Selected Financial Data|
|Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations|
|Item 7A. Quantitative and Qualitative Disclosures About Market Risk|
|Item 8. Financial Statements and Supplementary Data|
|Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure|
|Item 9A. Controls and Procedures|
|Item 9B. Other Information|
|Item 10. Directors, Executive Officers, and Corporate Governance|
|Item 11. Executive Compensation|
|Item 12. Security Ownership of Certain Beneficial Owners and Management|
|Item 13. Certain Relationships and Related Transactions and Director Independence|
|Item 14. Principal Accountant Fees and Services|
|Item 15. Exhibit and Financial Statement Schedules|
|Balance Sheet||Income Statement||Cash Flow|
Rev, G Profit, Net Income
Ops, Inv, Fin
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No.
(Exact name of registrant as specified in its charter)
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
Securities Registered Pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ◻ Yes ⌧
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ◻ Yes ⌧
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. ⌧
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). ⌧
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.
Accelerated filer ◻
Non-accelerated filer ◻
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected 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 Act).
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 the voting common stock held by non-affiliates of the registrant as of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $
The registrant had
Documents incorporated by reference: Portions of the registrant’s proxy statement for its annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days after the registrant’s fiscal year end are incorporated by reference into Part III of this Annual Report on Form 10-K.
TABLE OF CONTENTS
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Some of the information in this Annual Report on Form 10-K may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward looking statements. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
|●||our ability to execute our business strategy;|
|●||our production and oil and gas reserves;|
|●||our financial strategy, liquidity and capital required for our development program;|
|●||our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;|
|●||natural gas, natural gas liquids (“NGLs”), and oil prices;|
|●||impacts of world health events, including the coronavirus (“COVID-19”) pandemic;|
|●||timing and amount of future production of natural gas, NGLs, and oil;|
|●||our hedging strategy and results;|
|●||our ability to meet minimum volume commitments and to utilize or monetize our firm transportation commitments;|
|●||our future drilling plans;|
|●||our projected well costs and cost savings initiatives, including with respect to water handling services provided by Antero Midstream Corporation;|
|●||competition and government regulations;|
|●||pending legal or environmental matters;|
|●||marketing of natural gas, NGLs, and oil;|
|●||leasehold or business acquisitions;|
|●||costs of developing our properties;|
|●||operations of Antero Midstream Corporation;|
|●||general economic conditions;|
|●||expectations regarding the amount and timing of jury awards;|
|●||uncertainty regarding our future operating results; and|
|●||our other plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K.|
We caution investors that these forward-looking statements are subject to all of the risks and uncertainties incidental to our business, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, availability of drilling, completion and production equipment and services, environmental risks, drilling and completion and other operating risks, marketing and transportation risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs, and oil reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, conflicts of interest among our stockholders, impacts of world health events, including the COVID-19 pandemic and the other risks described under the heading “Item 1A. Risk Factors” in this Annual Report on Form 10-K.
Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities, or changes in commodity prices, 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 natural gas, NGLs, and oil that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K.
SUMMARY RISK FACTORS
|●||Natural gas, NGLs, and oil price volatility, or a substantial or prolonged period of low natural gas, NGLs, and oil prices, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.|
|●||Currently, we receive significant incremental cash flows as a result of our hedging activity. To the extent we are unable to obtain future hedges at effective prices consistent with those we have received to date and commodity prices do not improve, our cash flows may be adversely impacted. Furthermore, our derivative activities could result in financial losses or could reduce our earnings. In certain circumstances, we may have to make cash payments under our hedging arrangements and these payments could be significant.|
|●||If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we will be required to take write-downs of the carrying values of our properties.|
|●||The imbalance between the supply of and demand for oil, natural gas and NGLs has caused extreme market volatility and may result in increased costs and decreased availability of storage capacity. The lack of a market or available storage for certain of our products could cause interruptions in our operations, including temporary curtailments or shut-ins, or force us to sell our production at below-market prices, which could adversely affect our financial condition and results of operations.|
|●||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.|
|●||Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.|
|●||Unless we replace our reserves with new reserves and develop those reserves, our reserves and, eventually, production will decline, which would adversely affect our future cash flows and results of operations.|
|●||Approximately 58% 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.|
|●||Drilling for and producing oil and 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 natural gas, NGLs or oil in commercially viable quantities, which may adversely affect our financial condition, results of operations and cash flows.|
|●||Market conditions or operational impediments, such as the unavailability of satisfactory transportation arrangements, may hinder our access to natural gas, NGLs, and oil markets or delay our production.|
|●||Our ability to produce natural gas, NGLs, and oil economically and in commercial quantities is dependent on the availability of adequate supplies of water for drilling and completion operations and access to water and waste disposal or recycling facilities and services at a reasonable cost. Restrictions on our ability to obtain water or dispose of produced water and other waste may have an adverse effect on our financial condition, results of operations and cash flows.|
|●||Our failure to develop, obtain, access or maintain the necessary infrastructure to successfully deliver natural gas, NGLs, and oil to market may adversely affect our business, financial condition or results of operations.|
|●||Increased attention to environmental, social and governance (“ESG”) matters and conservation measures may adversely impact our business.|
|●||A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.|
Customer Concentration and Credit Risk
|●||Our hedging transactions expose us to counterparty credit risk and may become more costly or unavailable to us.|
|●||We are required to pay fees to our service providers based on minimum volumes under long-term contracts regardless of actual volume throughput.|
|●||Interruptions in operations at facilities that process our gas may adversely affect our business, financial condition and results of operations.|
Acquisitions, Divestitures and Takeovers
|●||Our 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.|
Capital Structure and Access 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 oil and gas reserves.|
|●||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 indebtedness, which may not be successful.|
|●||The borrowing base under the senior secured revolving credit facility (the “Credit Facility”) may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs. We may also be required to post additional collateral as financial assurance of our performance under certain contractual arrangements, which could adversely impact available liquidity under our Credit Facility.|
|●||Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.|
Compliance with Regulations
|●||Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities 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.|
|●||Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.|
|●||We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.|
GLOSSARY OF COMMONLY USED TERMS
The following are abbreviations and definitions of certain terms used in this document, some of which are commonly used in the oil and gas industry:
“ASC.” Accounting Standards Codification.
“ASU.” Accounting Standards Update.
“Basin.” A large natural depression on the earth’s surface in which sediments, generally brought by water, accumulate.
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, NGLs, or water.
“Bbl/d.” Bbl per day.
“Bcf.” One billion cubic feet of natural gas.
“Bcfe.” One billion cubic feet of natural gas equivalent with one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.
“Btu.” British thermal unit.
“C3+ NGLs.” Natural gas liquids excluding ethane, consisting primarily of propane, isobutane, normal butane and natural gasoline.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“DD&A.” Depletion, depreciation, and amortization.
“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“EPA.” United States Environmental Protection Agency.
“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir, or to extend a known reservoir.
“FASB.” Financial Accounting Standards Board.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
“Gross acres or gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Horizontal drilling.” A drilling technique where a well is drilled vertically to a certain depth and then drilled along a horizontal path oriented at approximately 85 to 95 degrees from a vertical direction within a specified interval.
“Joint Venture.” The joint venture entered into on February 6, 2017 between Antero Midstream Partners LP, a wholly owned subsidiary of Antero Midstream and MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, LP (“MPLX”), to develop processing and fractionation assets in Appalachia.
“Liquids-rich.” Natural gas with a heating value of at least 1,100 Btu per Mcf.
“LPG.” Liquefied petroleum gas consisting of propane and butane.
“MBbl.” One thousand barrels of crude oil, condensate or NGLs.
“Mcf.” One thousand cubic feet of natural gas.
“Mcfe.” One thousand cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six Mcf of natural gas.
“MMBbl.” One million barrels of crude oil, condensate or NGLs.
“MMBtu.” One million British thermal units.
“MMBtu/d.” MMBtu per day.
“MMcf.” One million cubic feet of natural gas.
“MMcf/d.” MMcf per day.
“MMcfe.” One million cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six thousand cubic feet of natural gas.
“MMcfe/d.” MMcfe per day.
“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% working interest in 100 acres owns 50 net acres.
“Net well.” The percentage ownership interest in a well that an owner has based on the working interest. An owner who has a 50% working interest in a well has a 0.50 net well.
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products such as ethane, propane, isobutane and normal butane, and natural gasoline.
“NYMEX.” The New York Mercantile Exchange.
“Potential well locations.” Total gross locations that we may be able to drill on our existing acreage. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas, NGLs, and oil prices, costs, drilling results, and other factors.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Prospect.” A specific geographic area which, based on supporting geological, geophysical, or other data, and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved reserves.” The estimated quantities of natural gas, NGLs, and oil that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
“Proved undeveloped reserves” or “PUD.” 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.
“PV-10.” When used with respect to oil and gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using average yearly prices computed using Securities and Exchange Commission (“SEC”) rules, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized measure represents an estimate of the fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, or distance between two horizontal well legs, and is often established by regulatory agencies.
“Standardized measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Strip prices.” The daily settlement prices of commodity futures contracts, such as those for natural gas, NGLs, and oil. Strip prices represent the prices at which a given commodity can be sold at specified future dates, which may not represent actual market prices available upon such date in the future.
“Tcf.” One trillion cubic feet of natural gas.
“Tcfe.” One trillion cubic feet of natural gas equivalent with one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.
“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas, NGLs, and oil regardless of whether such acreage contains proved reserves.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“WTI.” West Texas Intermediate light sweet crude oil.
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Our Company and Organizational Structure
Antero Resources Corporation (individually referred to as “Antero”) and its consolidated subsidiaries (collectively referred to as “Antero Resources,” the “Company,” “we,” “us” or “our”) are engaged in the development, production, exploration and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs, and oil from unconventional formations. As of December 31, 2020, we held approximately 515,000 net acres of natural gas, NGLs, and oil properties located in the Appalachian Basin primarily in West Virginia and Ohio. Our corporate headquarters are in Denver, Colorado.
Ownership in Antero Midstream
We formed Antero Midstream Partners LP (“Antero Midstream Partners”) to own, operate and develop midstream energy assets that service our production. Antero Midstream Partners’ assets consist of gathering systems and compression facilities, water handling and treatment facilities, and interests in processing and fractionation plants, through which it provides services to us under long-term, fixed-fee contracts.
On March 12, 2019, pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among Antero Midstream GP LP (“AMGP”), Antero Midstream Partners and certain of their affiliates (the “Simplification Agreement”) (i) AMGP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation (together with its consolidated subsidiaries, as appropriate, “Antero Midstream”), and (ii) an indirect, wholly owned subsidiary of Antero Midstream was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream (together, along with the other transactions contemplated by the Simplification Agreement, the “Transactions”). In connection with the Transactions, we received $297 million in cash and 158.4 million shares of Antero Midstream’s common stock in exchange for our 98,870,335 common units representing limited partner interests in Antero Midstream Partners owned immediately prior to the Transactions.
As a result of the Transactions, we no longer hold a controlling interest in Antero Midstream Partners and now have an interest in Antero Midstream that provides significant influence, but not control, over Antero Midstream. Thus, effective March 13, 2019, we no longer consolidate Antero Midstream Partners in our consolidated financial statements and account for our interest in Antero Midstream using the equity method of accounting. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for more information on the Transactions.
As of December 31, 2020, we owned 29.2% of Antero Midstream’s common stock.
The following table provides a summary of selected data for our Appalachian Basin natural gas, NGLs, and oil assets as of the date and for the period indicated.
Three Months Ended
As of December 31, 2020
December 31, 2020
Reserves (1) (2)
Discounted future income taxes (6)
Standardized Measure (7)
|(1)||Estimated proved reserve volumes and values were calculated assuming partial ethane recovery, with rejection of the remaining ethane and using the unweighted twelve-month average of the first-day-of-the-month prices for the period ended December 31, 2020, which were $1.82 per MMBtu for natural gas based on a|
|$2.08 per MMBtu NYMEX reference price, $9.30 per Bbl for ethane, $14.31 per Bbl for C3+ NGLs and $30.03 per Bbl for oil for the Appalachian Basin based on a $39.72 per Bbl WTI reference price.|
|(2)||Proved reserves for the noncontrolling interest in Martica Holdings LLC (“Martica”) as of December 31, 2020 were 254 Bcfe. See “—Asset Sales Program” below for more information.|
|(3)||PV-10 is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV-10 amount is the discounted amount of estimated future income taxes. Future income taxes are not basin specific, and therefore, the standardized measure is only at a company level. See Note 21—Supplemental Information on Oil and Gas Producing Activities to the consolidated financial statements for more information about the calculation of standardized measure.|
|(4)||Excludes certain vertical wells with no proved reserves booked that were primarily acquired in conjunction with leasehold acreage acquisitions.|
|(5)||Gross potential drilling locations are comprised of 256 locations classified as proved undeveloped, 1,877 locations classified as probable and possible. See “Item 1A. Risk Factors” for risks and uncertainties related to developing our potential well locations contained in our proved, probable and possible reserve categories.|
|(6)||Based on the 12-month average of the first-day-of-the-month prices used in the computation of PV-10 as of December 31, 2020, the future taxable net income generated over the life of our proved reserves is expected to be less than our net operating loss carryforward deductions, and therefore, under the standardized measure, there is no deduction for federal or state income taxes.|
|(7)||Standardized measure of discounted future net cash flows for the noncontrolling interest in Martica as of December 31, 2020 was $359 million.|
For the year ended December 31, 2020, our total consolidated capital expenditures were approximately $785 million, including drilling and completion expenditures of $735 million, leasehold additions of $48 million and other capital expenditures of $2 million. Our net capital budget for 2021 is $635 million. Our budget includes: $590 million for drilling and completion and $45 million for leasehold expenditures. We do not budget for acquisitions. During 2021, we plan to operate an average of three drilling rigs and two completion crews, and we plan to complete 65 to 70 horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.
Business Strategy and Competitive Strengths
Experienced Management Team
Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year project inventory.
Focused, Long-Lived Asset Base with Sufficient Takeaway Capacity
We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Appalachian Basin. We have secured sufficient long-term firm takeaway capacity on major pipelines in our core operating area to accommodate our current development plans.
Integrated Business Platform
We operate in the following industry segments: (i) the exploration, development and production of natural gas, NGLs, and oil; (ii) marketing of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. As described above and elsewhere in this Annual Report on Form 10-K, effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in our results. See Note 18—Segment Information to the consolidated financial statements for further discussion on our industry segment operations.
We maintain an active hedging program designed to mitigate volatility in commodity prices and to protect our expected future cash flows for our future operations and capital spending plans. As of December 31, 2020, we had fixed price swap contracts in place for January 1, 2021 through December 31, 2023 for 1.2 Tcf of our projected natural gas production at a weighted average index price of $2.67 per MMBtu. These hedging contracts include contracts for the year ending December 31, 2021 of 788 Bcf of natural gas at a weighted average price of $2.77 per MMBtu. We also have fixed price swaps for the year ending December 31, 2021 for ethane for approximately 19 MMBbl at a weighted average index price of $0.20 per gallon and oil for approximately 3 MMBbl at a weighted average index price of $55.16 per Bbl. Additionally, we have basis swaps in place for January 1, 2021 through December 31, 2024 for 73 Bcf of our projected natural gas production with pricing differentials ranging from $0.414 to $0.53 per MMBtu. As of
December 31, 2020, the estimated fair value of our commodity net derivative contracts was approximately $22 million. See Note 12—Derivative Instruments to the consolidated financial statements for more information on our current hedge position.
Asset Sales Program
In December 2019, we announced an asset sale program of $750 million to $1 billion, the proceeds of which would be used to reduce indebtedness. Since December 2019, we have announced $751 million in asset sales, which includes up to $51 million of contingent consideration related to the ORRI transaction described below that may be earned in 2021. All proceeds from these assets sales were used for debt reduction, and any additional asset sales or excess cash flows are expected to be used for further debt reduction.
Conveyance of Overriding Royalty Interest
On June 15, 2020, we announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across our existing asset base (the “ORRIs”). In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica, and Sixth Street at the initial closing contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs are achieved in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street was distributed to us. During the third quarter of 2020, we met the applicable production threshold and received a $51 million cash distribution during the year ended December 31, 2020.
The ORRIs include an overriding royalty interest of 1.25% of our working interest in all of our operated proved developed properties in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”), and an overriding royalty interest of 3.75% of our working interest in all of our undeveloped properties in West Virginia and Ohio (the “Development Override”). Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which we turn to sales 2.2 million lateral feet (net to our interest) of horizontal wells burdened by the Development Override and (b) the earlier of (i) April 1, 2023 and (ii) the date on which we turn to sales 3.82 million lateral feet (net to our interest) of horizontal wells are subject to the Development Override.
The ORRIs also include an additional overriding royalty interest of 2.00% of our working interest in the properties underlying the Initial PDP Override (the “Incremental Override”). The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to us (at our election) if certain production targets attributable to the ORRIs are achieved through March 31, 2023. Any portion of the Incremental Override that may not be re-conveyed to us based on us achieving such production volumes through March 31, 2023 will remain with Martica.
Prior to Sixth Street achieving an internal rate of return of 13% and 1.5x cash-on-cash return (the “Hurdle”), Sixth Street will receive all distributions in respect of the Initial PDP Override and the Development Override, and we will receive all distributions in respect of the Incremental Override, unless certain production targets are not achieved, in which case Sixth Street will receive some or all of the distributions in respect of the Incremental Override. Following Sixth Street achieving the Hurdle, we will receive 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved.
Volumetric Production Payment Transaction
On August 10, 2020, we completed a volumetric production payment transaction and received net proceeds of approximately $216 million (the "VPP"). In connection with the VPP, we entered into a purchase and sale agreement, together with a conveyance agreement and production and marketing agreement, with J.P. Morgan Ventures Energy Corporation ("JPM-VEC") to convey, effective July 1, 2020, an overriding royalty interest in dry gas producing properties in West Virginia (the "VPP Properties") equal to 136,589,000 MMBtu over the expected seven-year term of the VPP.
We accounted for the VPP as a conveyance under Accounting Standard Codifications ASC Topic 932, Extractive Industries—Oil and Gas, and the net proceeds were recorded as deferred revenue. Revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP. Under the production and marketing agreement, we and our affiliates provide certain marketing services as JPM-VEC’s agent, and any income or expenses related to these services will be recorded as marketing revenue or marketing expenses as appropriate.
Contemporaneously with the VPP, we executed a call option related to the production volumes associated with our retained interest in the VPP properties, which is collateralized by a mortgage on the VPP properties. Additionally, the production and marketing agreement contains an embedded put option related to the production volumes for our retained interest in the VPP properties, which has been bifurcated from the production and marketing arrangement and accounted for as a derivative instrument
recorded at fair value as of December 31, 2020. See Note 12—Derivative Instruments to the consolidated financial statements for further discussion of such derivative instruments.
On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners. Under the terms of the arrangement, QL will fund 20% of total development capital spending in 2021 and is expected to fund between 15% and 20% of total development capital spending on an annual basis from 2022 through 2024. All of the wells spud during each calendar year period will be a separate annual tranche. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for our account.
For each tranche other than 2021, we will propose a capital budget and estimated internal rate of return (“IRR”) for all wells to be spud during the year and, subject to the mutual agreement of the parties that the estimated IRR for each tranche exceeds a specified return, QL will be obligated to participate in such tranche. For each annual tranche in which QL participates, QL will receive a proportionate working interest percentage in each well spud in such tranche. If we present a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, we will not be obligated to offer QL the opportunity to participate in subsequent tranches. No earlier than December 31 following the expiration of each tranche year, we will calculate the tranche IRR for such tranche year and, if the tranche IRR exceeds certain specified returns, we will receive a carry in the form of a one-time payment from QL for such annual tranche.
Our Properties and Operations
The table below summarizes our estimated proved reserves as of December 31, 2019 and 2020, which were prepared assuming partial ethane recovery, and rejection of the remaining ethane. When ethane is rejected at the processing plant, it is left in the gas stream and sold with the methane gas.
As of December 31, 2019 (1)
Proved developed reserves
Proved undeveloped reserves
As of December 31, 2020 (2)
Proved developed reserves (3)
Proved undeveloped reserves (4)
|(1)||Unweighted 12 month average prices of the first-day-of-the-month for the period ended December 31, 2019 were $2.41 per MMBtu for natural gas, $10.59 per Bbl for ethane, $29.47 per Bbl for C3+ NGLs and $45.75 per Bbl for oil for the Appalachian Basin based on a $55.65 WTI reference price.|
|(2)||Unweighted 12 month average prices of the first-day-of-the-month for the period ended December 31, 2020 were $1.82 per MMBtu for natural gas, $9.30 per Bbl for ethane, $14.31 per Bbl for C3+ NGLs, and $30.03 per Bbl for oil for the Appalachian Basin based on a $39.72 WTI reference price.|
|(3)||Proved developed reserves for the noncontrolling interest in Martica as of December 31, 2020 were 181 Bcfe, which consisted of 110 Bcf of natural gas, 11 MMBbl of NGLs and 0.3 MMBbl of oil and condensate.|
|(4)||Proved undeveloped reserves for the noncontrolling interest in Martica as of December 31, 2020 were 73 Bcfe, which consisted of 49 Bcf of natural gas, 4 MMBbl of NGLs and 0.2 MMBbl of oil and condensate.|
The following table summarizes the changes in our estimated proved reserves during 2020 (in Bcfe):
Proved reserves, December 31, 2019
Extensions, discoveries, and other additions
Revisions to five-year development plan
Sales of reserves in place
Revisions to ethane recovery
Proved reserves, December 31, 2020
Extensions and discoveries of 1,105 Bcfe of proved reserves resulted from delineation and developmental drilling in the Appalachian Basin. Performance revisions resulted in a net upward revision of 491 Bcfe. Revisions to five-year development plan downward of 790 Bcfe include a downward revision of 922 Bcfe for locations that were not developed within five years of initial booking as proved reserves, partially offset by a net upward revision of 132 Bcfe from schedule optimization primarily driven by previously proved undeveloped properties reclassified from non-proved to proved undeveloped. Price revisions downward of 1,126 Bcfe are due to decreases in prices for natural gas, NGLs and oil. Sales of reserves of 113 Bcfe resulted from the VPP. Upward revisions to ethane recovery of 485 Bcfe are due to an increase in assumed future ethane recovery. Estimated proved reserves as of December 31, 2020 totaled 17,635 Bcfe, a decrease of 7% from the prior year.
Proved Undeveloped Reserves
Proved undeveloped reserves are included in the previous table of total proved reserves. The following table summarizes the changes in our estimated proved undeveloped reserves during 2020 (in Bcfe):
Proved undeveloped reserves, December 31, 2019
Extensions, discoveries, and other additions
Revisions to five-year development plan
Reclassifications to proved developed reserves
Revisions to ethane recovery
Proved undeveloped reserves, December 31, 2020
Extensions and discoveries during 2020 of 1,105 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Appalachian Basin. Performance revisions resulted in a net upward revision of 172 Bcfe. Revisions to five-year development plan downward of 735 Bcfe included a downward revision of 927 Bcfe for locations that were not developed within five years of initial booking as proved reserves, partially offset by a net upward revision of 192 Bcfe from schedule optimization primarily driven by previously proved undeveloped properties reclassified from non-proved properties to proved undeveloped. Price revisions downward of 54 Bcfe are due to decreases in prices for natural gas, NGLs and oil. Upward revisions to ethane recovery of 88 Bcfe are due to an increase in assumed future ethane recovery.
During the year ended December 31, 2020, we converted approximately 1,967 Bcfe, or 27%, of our proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $570 million. We spent an additional $253 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification as of December 31, 2019, resulting in total development spending of $823 million, as disclosed in Note 21—Supplemental Information on Oil and Gas Producing Activities to the consolidated financial statements. Estimated future development costs relating to the development of our proved undeveloped reserves as of December 31, 2020 are approximately $1.5 billion, or $0.27 per Mcfe, over the next five years. Based on strip pricing as of December 31, 2020, we believe that net cash provided by operating activities will be sufficient to finance such future development costs. While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also continue drilling our proved undeveloped reserves. See “Item 1A. Risk Factors—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.”
We maintain a five-year development plan, which is reviewed by our Board of Directors, which supports our corporate production target. The development plan is reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations. In response to lower commodity prices, we reduced the pace of activity in our five-year development plan to a maintenance capital program. This resulted in the reclassification of 790 Bcfe of reserves from proved undeveloped to non-proved during the year ended December 31, 2020 due to the five-year development rule. Based on our then-current acreage position, strip prices, anticipated well economics, and our development plans at the time these reserves were classified as proved, we believe the previous classification of these locations as proved undeveloped was appropriate.
As of December 31, 2020, an estimated 11,342 of our net leasehold acres, containing 220 locations associated with proved undeveloped reserves, are subject to renewal prior to scheduled drilling. Some of these leases have contract renewal options and some will need to be renegotiated. We estimate a potential cost of approximately $31.4 million to renew the 11,342 acres based upon current leasing authorizations and option to extend payments. Proved undeveloped reserves of 913 Bcfe are related to these leases. Historically, we have had a high success rate in renewing leases, and we expect that we will be able to renew substantially all of the leases underlying this acreage prior to the scheduled drilling dates. Based on our historical success rate in renewing leases, we estimate that we may not be able to renew leases covering approximately 137 Bcfe of these proved undeveloped reserves.
If we are not able to renew these leases prior to the scheduled drilling dates, our quantities of net proved undeveloped reserves will be somewhat reduced on those locations.
Preparation of Reserve Estimates
Our proved reserve estimates as of December 31, 2018, 2019 and 2020 included in this Annual Report on Form 10-K were prepared by our internal reserve engineers in accordance with petroleum engineering and evaluation standards published by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. These proved reserve estimates have been audited by our independent engineers, DeGolyer and MacNaughton (“D&M”). We refer to D&M as our independent engineers. A copy of the summary report of D&M with respect to our reserves as of December 31, 2020 is filed as Exhibit 99.1 to this Annual Report on Form 10 K. The technical person at D&M primarily responsible for reviewing our reserves estimates was Dilhan Ilk, P.E. Mr. Ilk is a Registered Professional Engineer in the State of Texas (License No. 139334), is a member of the Society of Petroleum Engineers, and has in excess of 10 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Ilk graduated from the Istanbul Technical University in 2003 with a Bachelor of Science degree in Petroleum Engineering, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005 and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010. The technical persons responsible for overseeing the audit of our reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Our internal staff of petroleum engineers and geoscience professionals works closely with D&M to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process. Periodically, our technical team meets with D&M to review properties and discuss methods and assumptions used by us to prepare reserve estimates. Our internally prepared reserve estimates and related reports are reviewed and approved by our Senior Vice President - Reserves, Planning and Midstream, W. Patrick Ash. Mr. Ash has served as Senior Vice President-Reserves, Planning and Midstream since June 2019. Previously, he served as Vice President of Reservoir Engineering and Planning from December 2017 to June 2019. Prior to December 2017, Mr. Ash was at Ultra Petroleum for six years in management positions of increasing responsibility, most recently serving as Vice President, Development. In this position he led the reservoir engineering, geoscience, and corporate engineering groups. From 2001 to 2011, Mr. Ash served in engineering roles at Devon Energy, NFR Energy and Encana Corporation. Mr. Ash holds a B.S. in Petroleum Engineering from Texas A&M University and an MBA from Washington University in St. Louis.
Our senior management and Board of Directors also reviews our reserve estimates and related reports with Mr. Ash and other members of our technical staff. Additionally, our senior management reviews and approves any significant changes to our proved reserves on a quarterly basis.
Identification of Potential Well Locations
Our identified potential well locations represent locations to which proved, probable, or possible reserves were attributable based on SEC pricing as of December 31, 2020. We prepare internal estimates of probable and possible reserves but have not included disclosure of such reserves in this Annual Report on Form 10-K.
Production, Price and Cost History
Natural gas, NGLs, and oil are commodities, and the prices that we receive for our production are largely a function of market supply and demand. Demand for our products is impacted by general economic conditions, weather and other seasonal conditions. Over or under supply of natural gas, NGLs, or oil can result in substantial price volatility. A substantial or extended decline in commodity prices, or poor drilling results, could have a material adverse effect on our financial position, results of operations, cash flows, quantities of reserves that may be economically produced and our ability to access capital markets. See “Item 1A. Risk Factors— Natural gas, NGLs, and oil price volatility, or a substantial or prolonged period of low natural gas, NGLs, and oil prices, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”
Exploration and Production and Marketing Segments
The following table sets forth information regarding our production, realized prices, and production costs for the years ended December 31, 2018, 2019 and 2020. For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Year Ended December 31,
Production data (1) (2):
Natural gas (Bcf)
C2 Ethane (MBbl)
C3+ NGLs (MBbl)
Daily combined production (MMcfe/d)
Average prices before effects of derivative settlements:
Natural gas (per Mcf)
C2 Ethane (per Bbl)
C3+ NGLs (per Bbl)
Oil (per Bbl)
Combined average sales prices before effects of derivative settlements (per Mcfe) (1)
Combined average sales prices after effects of derivative settlements (per Mcfe) (1)
Average Costs (per Mcfe) (3):
Gathering, compression, processing, and transportation
Production and ad valorem taxes
Depletion, depreciation, amortization, and accretion
General and administrative (excluding equity-based compensation)
|(1)||Production data excludes volumes related to the VPP.|
|(2)||Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains on settlements of commodity derivatives (but does not include proceeds from the derivative monetizations in 2018 and 2020). These commodity derivatives do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.|
|(3)||Average costs prior to the deconsolidation of Antero Midstream Partners on March 12, 2019 have been adjusted to reflect our operating without eliminating intercompany transactions for midstream and water services provided by Antero Midstream Partners. Following the deconsolidation of Antero Midstream Partners, average costs reflect Antero’s actual operating costs.|
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we own an interest as of December 31, 2020. A majority of our developed acreage is subject to liens securing the Credit Facility. Approximately 75% of our net Appalachian Basin acreage is held by production. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this table.
Undeveloped Acres (2)
Total Acres (2)
Appalachian Basin (1)
|(1)||Our acreage is located in West Virginia, Ohio and Pennsylvania.|
|(2)||There are 44,309 gross (39,365 net), 49,589 gross (43,489 net) and 31,192 gross (26,745 net) acres subject to expiration during the years ending December 31, 2021, 2022 and 2023, respectively, if production is not established within the spacing units covering the acreage prior to the expiration dates and they are not otherwise extended or renewed.|
The following table summarizes gross and net productive wells as of December 31, 2020, all of which are natural gas wells. Net wells reflect the sum of our percentage ownership in gross wells.
December 31, 2020
The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2018, 2019 and 2020. Gross wells reflect the number of wells in which we own an interest and include historical drilling activity in the Appalachian Basin. Net wells reflect the sum of our working interests in gross wells.
Year Ended December 31,
Total development wells
Total exploratory wells
|(1)||Well counts exclude 23 gross wells (21.8 net wells) that were drilled and uncompleted or in the process of being completed as of December 31, 2020.|
Gathering and Compression
Our exploration and development activities are supported by the natural gas gathering and compression assets of Antero Midstream and by third-party gathering and compression arrangements. Our agreements with Antero Midstream allow us to obtain the necessary gathering and compression capacity for our production and we have leveraged our relationship with Antero Midstream to support our development. For the years ended December 31, 2019 and 2020, Antero Midstream spent approximately $316 million and $158 million, respectively, on gas gathering and compression infrastructure that services our production. Subject to pre-existing dedications and other third-party commitments, we have dedicated to Antero Midstream substantially all of our current and future acreage in West Virginia and Ohio for gathering and compression services.
As of December 31, 2020, Antero Midstream owned and operated 468 miles of gas gathering pipelines in the Appalachian Basin. We also have access to additional low-pressure and high-pressure pipelines owned and operated by third parties. As of December 31, 2020, Antero Midstream owned and operated 20 compressor stations, and we utilized 16 additional third-party compressor stations. The gathering, compression, and dehydration services provided by third parties are contracted on a fixed-fee basis.
Natural Gas Processing
Many of our wells in the Appalachian Basin allow us to produce liquids-rich natural gas that contains a significant amount of NGLs. Liquids-rich natural gas is processed, which involves the removal and separation of NGLs from the wellhead natural gas.
NGLs are valuable commodities once removed from the natural gas stream in a cryogenic processing facility yielding y-grade liquids. Y-grade liquids are then fractionated, thereby breaking up the y-grade liquid into its key components. Fractionation refers to the process by which an NGL y-grade stream is separated into individual NGL products such as ethane, propane, normal butane, isobutane, and natural gasoline. Fractionation occurs by heating the y-grade liquids to allow for the separation of the component parts based on the specific boiling points of each product. Each of the individual products has its own market price.
The combination of infrastructure constraints in the Appalachian Basin and low ethane prices has resulted in many producers “rejecting” rather than “recovering” ethane. Ethane rejection occurs when ethane is left in the wellhead gas stream when the gas is processed, rather than being extracted and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue gas at the tailgate of the processing plant is higher. Producers generally elect to “reject” ethane when the price received for the ethane in the gas stream is greater than the net price received for the ethane being sold as a liquid after fractionation. When ethane is recovered, the Btu content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate product.
Given the existing commodity price environment and the current limited ethane market in the northeast, we are currently rejecting the majority of the ethane obtained in the natural gas stream when processing our liquids-rich gas. However, we realize a pricing upgrade when selling the remaining NGLs product stream at current prices. We may elect to recover more ethane when ethane prices result in a value for the ethane that is greater than the Btu equivalent residue gas and incremental recovery costs.
We contract with MarkWest to provide cryogenic processing capacity for our Appalachian Basin production. Antero Midstream owns a 50% interest in a joint venture with MarkWest to develop processing and fractionation assets in Appalachia. Below is a summary of the nameplate capacity of the processing plants owned by MarkWest and the Joint Venture, our contracted capacity at these plants and their completion status.
Sherwood 1 through 13 (1)
Smithburg 1 (1)
Q3 2021 (2)
Seneca 1 through 4
|(1)||MarkWest owns the gas processing plants referred to as Sherwood 1 through 6 and Seneca 1 through 4 and the Joint Venture owns the gas processing plants referred to as Sherwood 7 through 13 and Smithburg 1. The Joint Venture also owns a 33 1/3% interest in two fractionation facilities located at MarkWest’s Hopedale complex, with MarkWest owning the remaining interest.|
|(2)||Anticipated contractual start date.|
Transportation and Takeaway Capacity
We have entered into firm transportation agreements with various pipelines that enable us to deliver natural gas to the Midwest, Gulf Coast, Eastern Regional, and Mid-Atlantic markets. Our primary firm transportation commitments include the following:
Midwest-Chicago Regional Markets
We have several firm transportation contracts with pipelines that have capacity to deliver natural gas to the Chicago and Michigan markets. The Chicago directed pipelines include the Rockies Express Pipeline (“REX”), the Midwestern Gas Transmission pipeline (“MGT”), the Natural Gas Pipeline Company of America pipeline (“NGPL”), and the ANR Pipeline Company pipeline (“ANR”). The firm transportation contract on REX provides firm capacity for 600,000 MMBtu per day and delivers gas to downstream contracts on MGT, NGPL, and ANR. On October 1, 2021, firm transportation capacity will be reduced to 400,000 MMBtu per day.
We have 265,000, 310,000 and 200,000 MMBtu per day of firm transportation on MGT, NGPL and ANR, respectively. On September 30, 2021, MGT contracts will be reduced to 125,000 MMBtu per day. The MGT and NGPL contracts deliver gas to the Chicago city gate area and the ANR contract delivers natural gas to Chicago in the summer and Michigan in the winter. The Chicago and Michigan contracts expire at various dates from 2021 through 2035.
Gulf Coast, Atlantic Seaboard and International Markets
We have firm transportation contracts with various pipelines to access the Gulf Coast, Atlantic Seaboard and international markets. These contracts include firm capacity on the following pipelines: (i) Columbia Gas Transmission pipeline (“TCO”),(ii) Columbia Gulf Transmission pipeline (“Columbia Gulf”), (iii) DTE Energy’s Stonewall Gas Gathering (“SGG”), (iv) Tennessee Gas Pipeline (“Tennessee”), (v) ANR Pipeline (“ANR-Gulf” or “ANR-Chicago”), (vi) Energy Transfer Rover Pipeline (“ET Rover”), (vii) Equitrans pipeline (“EQT”), (vii) Texas Eastern Transmission Corp. - M2 Zone (“TETCO M2”) (viii) DTE Energy’s Appalachia Gathering System (“AGS”), (ix) Mountaineer Xpress pipeline (“MXP”), (x) Columbia Gas Transmission IPP pool (“TCO IPP”), (xi) Gulf Xpress pipeline (“GXP”), (xii) Enterprise Products Partners ATEX pipeline (“ATEX”) and (xiii) Sunoco pipeline (“Mariner East 2”). Our diverse portfolio of firm capacity gives us the flexibility to move natural gas to the local Appalachia market or other preferred markets with more favorable pricing. These firm capacity contracts include:
|●||TCO firm capacity of approximately 584,000 MMBtu per day. On March 31, 2021, firm capacity will be reduced to 474,000 MMBtu per day. Of the 584,000 MMBtu per day of firm capacity on TCO, we have the ability to utilize 530,000 MMbtu per day on Columbia Gulf, which provides access to the Gulf Coast markets. These contracts expire at various dates from 2021 through 2058.|
|●||SGG firm capacity of 900,000 MMBtu per day which transports gas from various gathering system interconnection points and the MarkWest Sherwood plant complex to the TCO WB System. Additionally, we have firm transportation contracts with TCO for both the western and eastern directions on the pipeline. Our firm capacity of 800,000 MMBtu per day west bound on TCO (“TCO WB”) provides us access to the local Appalachia and the Gulf Coast markets via the Columbia Gulf or Tennessee pipelines. Our firm capacity of 330,000 MMBtu per day east bound on TCO delivers natural gas to the Cove Point LNG facility These contracts expire at various dates from 2033 through 2038.|
|o||Tennessee firm capacity of 790,000 MMBtu per day to deliver natural gas from the Broad Run interconnect on TCO WB to the Gulf Coast market. This contract expires in 2030.|
|o||ANR-Gulf firm capacity of 600,000 MMBtu per day to deliver natural gas from West Virginia and Ohio to the Gulf Coast market. This contract expires in 2045.|
|o||ET Rover Pipeline firm capacity of 840,000 MMBtu per day, which connects the Appalachian Basin to Midwest and Gulf Coast markets via the ANR Chicago and ANR Gulf. These contracts expire at various dates from 2025 through 2033.|
|o||EQT firm capacity of 250,000 MMBtu per day to deliver natural gas to TETCO M2 and other various delivery points. These contracts expire at various dates from 2022 through 2025.|
|o||AGS firm capacity of 275,000 MMBtu per day to deliver natural gas to TETCO M2 and other various local delivery points. These contracts expire in 2023.|
|o||MXP firm capacity of 700,000 MMBtu per day to deliver (i) 517,000 MMBtu per day to TCO IPP and (ii) 183,000 MMBtu per day to GXP which continues to Leach, Kentucky. These contracts allow us to deliver natural gas to the U.S. Gulf Coast and they expire in 2034.|
|●||ATEX firm capacity of 20,000 Bbl per day to deliver ethane to Mont Belvieu, Texas. This contract expires in 2028.|
|●||Mariner East 2 firm capacity for ethane of 11,500 Bbl per day and propane and butane of 55,000 Bbl per day to deliver to Marcus Hook, Pennsylvania. These contracts expire November 2028 and February 2029, respectively. The propane and butane contract increases 5,000 Bbl per day each year through 2022, resulting in an ultimate total firm capacity of 65,000 Bbl per day. Mariner East 2 provides access to international markets via trans-ocean LPG carriers.|
Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations” for information on our minimum fees for such contracts. Based on current projected 2021 annual production guidance, we estimate that we could incur annual net marketing costs of $0.08 per Mcfe to $0.10 per Mcfe in 2021 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials. Where permitted, we continue to actively market any excess capacity in order to offset minimum commitment fees and those activities are recorded in our net marketing expense.
We have entered into various firm sales contracts to deliver and sell gas and NGLs. We believe we will have sufficient production quantities to meet substantially all of such commitments. We may purchase gas from third parties to satisfy shortfalls should they occur.
As of December 31, 2020, our firm sales commitments through 2025 included:
Year Ending December 31,
We utilize a part of our firm transportation capacity to deliver gas and NGLs under the majority of these firm sales contracts. We have firm transportation contracts that require us to either ship products on said pipelines or pay demand charges for shortfalls. The minimum demand fees are reflected in our table of contractual obligations. See “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations.”
Water Handling and Treatment Operations
Our agreements with Antero Midstream allow us to obtain the necessary raw, fresh and recycled water (collectively, “fresh water”) for use in our drilling and completion operations, as well as services to dispose of wastewater resulting from our operations.
Antero Midstream owns two independent fresh water distribution systems that distribute fresh water from the Ohio River and several regional water sources, for well completion operations in the Appalachian Basin. These systems consist of permanent buried pipelines, portable surface pipelines and fresh water storage facilities, as well as pumping stations to transport the fresh water throughout the pipeline networks. The surface pipelines are moved to well pads to service completion operations to the extent necessary and feasible. As of December 31, 2020, Antero Midstream had the ability to store 5.7 million barrels of fresh water in 37 impoundments located throughout our leasehold acreage. Due to the extensive geographic distribution of Antero Midstream’s water pipeline systems in the Appalachian Basin, it is able to provide water delivery services to neighboring oil and gas producers within and adjacent to our operating area, subject to commercial arrangements, while reducing water truck traffic.
As of December 31, 2020, Antero Midstream owned and operated 203 miles of buried fresh water pipelines and 134 miles of portable surface fresh water pipelines in the Appalachian Basin, as well as 37 fresh water storage facilities equipped with transfer pumps. Through Antero Midstream, we also recycle and reuse the majority of our flowback and produced water through blending.
Our sales to major customers (purchasers in excess of 10% of total sales) for the years ended December 31, 2018, 2019 and 2020 were as follows:
Year Ended December 31, 2018
Mercuria Energy America, Inc.
Tenaska Marketing Ventures
Year Ended December 31, 2019
Sabine Pass Liquefaction LLC
Year Ended December 31, 2020
Sabine Pass Liquefaction LLC
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, often in the case of undeveloped properties, cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use, or affect the value of, the properties. Burdens on properties may include:
|●||customary royalty interests;|
|●||liens incident to operating agreements and for current taxes;|
|●||obligations or duties under applicable laws;|
|●||development obligations under natural gas leases; or|
|●||net profits interests.|