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Table of Contents

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, 2019

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 001-36120

Graphic

ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

80-0162034
(IRS Employer
Identification No.)

1615 Wynkoop Street, Denver, Colorado
(Address of principal executive offices)

80202
(Zip Code)

(303357-7310

(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 each exchange on which registered

Common Stock, par value $0.01

AR

New York Stock Exchange

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  No

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

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

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

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 

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).  Yes  No

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 28, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $1.5 billion based on the $5.53 per share closing price of Antero Resources Corporation’s common stock as reported on that day on the New York Stock Exchange

The registrant had 286,677,115 shares of common stock outstanding as of February 7, 2020.

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

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

ii

PART I

1

Items 1 and 2.

Business and Properties

1

Item 1A.

Risk Factors

25

Item 1B.

Unresolved Staff Comments

46

Item 3.

Legal Proceedings

46

Item 4.

Mine Safety Disclosures

46

PART II

47

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

47

Item 6.

Selected Financial Data

49

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

55

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

73

Item 8.

Financial Statements and Supplementary Data

75

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

75

Item 9A.

Controls and Procedures

75

Item 9B.

Other Information

76

PART III

77

Item 10.

Directors, Executive Officers and Corporate Governance

77

Item 11.

Executive Compensation

80

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

80

Item 13.

Certain Relationships and Related Transactions and Director Independence

80

Item 14.

Principal Accountant Fees and Services

81

PART IV

82

Item 15.

Exhibits and Financial Statement Schedules

82

SIGNATURES

86

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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. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. 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 belief, 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;
timing and amount of future production of natural gas, NGLs, and oil;
our hedging strategy and results;
our ability to successfully execute our share repurchase program, debt repurchase program and/or our asset sale program;
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 and treatment 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;
credit markets;
expectations regarding the amount and timing of jury awards;

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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, 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.

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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:

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.

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 used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle 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.

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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 one barrel of oil, condensate or NGLs converted to six cubic feet 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.

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.

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.

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 oil, natural gas and natural gas liquids 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

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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.

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PART I

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 exploration, development, and acquisition of natural gas, NGLs, and oil properties in the Appalachian Basin in West Virginia and Ohio. 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, 2019, we held approximately 541,000 net acres of oil and gas properties located in the Appalachian Basin in West Virginia and Ohio. Our corporate headquarters are in Denver, Colorado.

Ownership in Antero Midstream

In 2014, 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, par value $0.01 per share, in exchange for our 98,870,335 common units representing limited partner interests in Antero Midstream Partners owned immediately prior to the Transactions.

Prior to the Transactions, our ownership of Antero Midstream Partners common units represented approximately a 53% limited partner interest in Antero Midstream Partners, and we consolidated Antero Midstream Partners’ financial position and results of operations into our consolidated financial statements. The Transactions resulted in us owning approximately 31% of Antero Midstream’s common stock. As a result, 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. Because Antero Midstream Partners does not meet the requirements of a discontinued operation, Antero Midstream Partners’ results of operations continue to be included in our consolidated statement of operations and comprehensive income (loss) through March 12, 2019. Please see Note 3 to the consolidated financial statements for more information on the Transactions.

On December 16, 2019, we sold 19,377,592 shares of Antero Midstream’s common stock to Antero Midstream at a price of $5.1606 per share, which shares were thereafter cancelled by Antero Midstream, resulting in aggregate proceeds to us of $100 million. This reduced our interest in Antero Midstream to approximately 28.7% at December 31, 2019.

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General

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

December 31,

At December 31, 2019

2019

Average net

Proved

Net proved

Gross potential

daily

Reserves

PV-10

developed

drilling

production

    

(Bcfe)(1)

    

(in millions)(2)

    

wells(3)

    

Total net acres

    

locations(4)

    

(MMcfe/d)

 

Appalachian Basin:

Marcellus Shale

17,350

$

5,500

923

450,633

2,211

2,832

Ohio Utica Shale

1,543

$

567

207

90,814

174

353

Total

18,893

$

6,067

1,130

541,447

2,385

3,185

(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, 2019, which were $2.41 per MMBtu for natural gas based on a $2.63 per MMBtu NYMEX reference price, $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 per Bbl WTI reference price.
(2)PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 of $6.1 billion to the Standardized measure of $5.5 billion, please see “—Our Properties and Operations—Estimated Proved Reserves.”
(3)Does not include certain vertical wells with no proved reserves booked that were primarily acquired in conjunction with leasehold acreage acquisitions.
(4)Gross potential drilling locations are comprised of 328 locations classified as proved undeveloped, 1,958 locations classified as probable and 99 locations classified as 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.

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 profitably grow our reserves and production, primarily on our existing multi-year project inventory.

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 Marcellus Shale and Utica Shale of the Appalachian Basin. We have 2,385 potential horizontal well locations on our existing leasehold acreage within our proved, probable, and possible reserve categories.

We have secured sufficient long-term firm takeaway capacity on major pipelines in each of our core operating areas to accommodate our current development plans.

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) the gathering and processing of natural gas through our equity method investment in Antero Midstream Corporation. 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 to the consolidated financial statements for further discussion on our industry segment operations.

2019 and Recent Developments and Highlights

Reserves, Production, and Financial Results

As of December 31, 2019, our estimated proved reserves were 18.9 Tcfe, consisting of 11.5 Tcf of natural gas, 652 MMBbl of ethane, 540 MMBbl of C3+ NGLs, and 42 MMBbl of oil. As of December 31, 2019, 61% of our estimated proved reserves by volume were natural gas, 38% were NGLs, and 1% was oil. Proved developed reserves were 11.7 Tcfe, or 62% of total proved reserves.

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For the year ended December 31, 2019, our net production totaled 1,175 Bcfe, or 3,220 MMcfe per day, a 19% increase compared to 989 Bcfe, or 2,709 MMcfe per day, for the year ended December 31, 2018. Production growth resulted from an increase in the number of producing wells as a result of our drilling and completion activity. Our average price received for production, before the effects of gains on settled commodity derivatives, for the year ended December 31, 2019 was $3.10 per Mcfe compared to $3.69 per Mcfe for the year ended December 31, 2018. Our average realized price after the effects of gains on settled commodity derivatives was $3.38 per Mcfe for the year ended December 31, 2019 as compared to $3.94 per Mcfe for the year ended December 31, 2018.

For the year ended December 31, 2019, we generated consolidated cash flows from operations of $1.1 billion, a consolidated net loss of $340 million and Adjusted EBITDAX of $1.2 billion. This compares to cash flows from operations of $2.1 billion, a consolidated net loss of $398 million, Adjusted EBITDAX of $1.7 billion for the year ended December 31, 2018. See “Item 6. Selected Financial Data” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income (loss).

Consolidated net loss for 2019 included (i) commodity derivative fair value gains of $464 million, comprised of gains on settled derivatives of $325 million and a non-cash gain of $139 million on changes in the fair value of commodity derivatives, (ii) a non-cash charge of $24 million for equity-based compensation, (iii) a non-cash charge of $1.3 billion for impairments of oil and gas properties, (iv) a non-cash charge of $468 million for an impairment of equity investments and (v) a non-cash deferred tax benefit of $79 million.

2019 Capital Spending and 2020 Capital Budget

For the year ended December 31, 2019, our total consolidated capital expenditures were approximately $1.4 billion, including drilling and completion expenditures of $1.3 billion, leasehold additions of $89 million, gathering and compression expenditures of $48 million, water handling and treatment expenditures of $24 million, and other capital expenditures of $7 million. Our capital budget for 2020 is $1.2 billion. Our budget includes: $1.15 billion for drilling and completion and $50 million for leasehold expenditures. We do not budget for acquisitions. During 2020, we plan to operate an average of four drilling rigs and three to four completion crews and we plan to complete 120 to 130 horizontal wells in the Marcellus and Utica Shales in 2020. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

Furthermore, in December 2019, we announced an asset sale program pursuant to which we expect to execute between $750 million and $1.0 billion asset monetization opportunities through 2020, which can include dispositions of lease acreage, minerals, producing properties or our shares of Antero Midstream common stock, or hedge restructuring. We expect to use the proceeds from this program to reduce indebtedness. We initiated this program by selling $100 million of our shares of Antero Midstream common stock in December 2019 to Antero Midstream.

Hedge Position

At December 31, 2019, we had fixed price swap contracts in place for January 1, 2020 through December 31, 2023 for 1.7 Tcf of our projected natural gas production at a weighted average index price of $2.84 per MMBtu. These hedging contracts include contracts for the year ending December 31, 2020 of 815 Bcf of natural gas at a weighted average price of $2.87 per MMBtu. We also have fixed price swaps for NGLs and Oil for approximately 15 MMBbls for the year ending December 31, 2020 at weighted average index prices of $0.50 to $0.81 per gallon and $55.63 per Bbl, respectively. Additionally, we have basis swaps in place for January 1, 2020 through December 31, 2024 for 95 Bcf of our projected natural gas production with pricing differentials ranging from $0.35 to $0.53 per MMBtu. See Note 11 to the consolidated financial statements for more information on our current hedge position.

To the extent we have hedged the price of a portion of our estimated future production through 2024, we believe this hedge position provides some certainty to cash flows supporting our future operations and capital spending plans. As of December 31, 2019, the estimated fair value of our commodity net derivative contracts was approximately $746 million.

Credit Facility

At December 31, 2019, the borrowing base under our senior secured revolving credit facility (the “Credit Facility”) was $4.5 billion and lender commitments were $2.64 billion. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero’s senior notes then outstanding. The borrowing base under the Credit Facility is redetermined annually and is based on the estimated future cash flows from our proved oil and gas reserves and our commodity derivative positions. The next redetermination is scheduled to occur in April 2020. At

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December 31, 2019, we had $552 million of borrowings, with a weighted average interest rate of 3.28%, and $623 million of letters of credit outstanding under the revolving credit facility. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of the Credit Facility.

Debt Repurchase Program

During the fourth quarter of 2019, we repurchased $225 million principal amount of debt at a 17% weighted average discount, including a portion of our 5.375% senior notes due November 1, 2021 (the “2021 notes”) and our 5.125% senior notes due December 1, 2022 (the “2022 notes”). As of December 31, 2019, we have $952.5 million in aggregate principal amount outstanding of our 2021 notes and $923.0 million in aggregate principal amount outstanding of our 2022 notes.  See Note 7 to the consolidated financial statements for more information on long-term debt.

Share Repurchase Program

In October 2018, our Board of Directors authorized a $600 million share repurchase program through March 31, 2020. During the year ended December 31, 2019, we repurchased 13.4 million shares of our common stock (approximately 4% of total shares outstanding at commencement of the program) at a total cost of approximately $39 million. See “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Issuer Purchases of Equity Securities.”

Our Properties and Operations

Estimated Proved Reserves

The information with respect to our estimated proved reserves presented below has been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”).

Reserves Presentation

The following table summarizes our estimated proved reserves, related Standardized measure, and PV-10 at December 31, 2017, 2018 and 2019. The decrease in pre-tax estimated proved reserves PV-10 value as compared to 2018, was due primarily to lower SEC pricing and the deconsolidation of Antero Midstream Partners from Antero Resources’ financial statements. The deconsolidation resulted in Antero Resources recording the full fees paid to Antero Midstream Partners for services rendered and no longer recording the capital expenditures associated with Antero Midstream Partners. Prior to deconsolidation, Antero Resources’ consolidated reserves included the elimination of full fees paid by Antero Resources to Antero Midstream Partners and the inclusion of the operating costs and capital associated with Antero Midstream Partners.

Our estimated proved reserves are based on evaluations prepared by our internal reserve engineers, which 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 at December 31, 2019 is filed as Exhibit 99.1 to this Annual Report on Form 10-K. Within D&M, the technical person primarily responsible for reviewing our reserves estimates was Gregory K. Graves, P.E. Mr. Graves is a Registered Professional Engineer in the State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and has in excess of 34 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum Engineering. Reserves at December 31, 2017, 2018 and 2019 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.

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At December 31,

2017

2018

    

2019

 

Estimated proved reserves:

Proved developed reserves:

Natural gas (Bcf)

5,587

6,669

7,229

Ethane (MMBbl)

268

341

428

C3+ NGLs (MMBbl)

199

259

302

Oil (MMBbl)

16

20

21

Total equivalent proved developed reserves (Bcfe)

8,488

10,389

11,740

Proved undeveloped reserves:

Natural gas (Bcf)

5,511

4,756

4,265

Ethane (MMBbl)

260

213

224

C3+ NGLs (MMBbl)

262

238

237

Oil (MMBbl)

22

26

20

Total equivalent proved undeveloped reserves (Bcfe)

8,773

7,622

7,153

Proved developed producing (Bcfe)

7,996

9,841

11,267

Proved developed non-producing (Bcfe)

492

548

473

Percent developed

49

%

58

%

62

%

Total estimated proved reserves (Bcfe)

17,261

18,011

18,893

PV-10 (in millions)(1)

$

10,175

$

12,589

$

6,067

Standardized measure (in millions)(1)

$

8,627

$

10,478

$

5,469

(1)PV-10 was prepared using average yearly prices computed using SEC rules, discounted at 10% per annum, without giving effect to taxes. 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 to the consolidated financial statements for more information about the calculation of Standardized measure.

The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV-10), the present value of those net cash flows after income tax (Standardized measure) and the prices used in projecting future net cash flows at December 31, 2017, 2018 and 2019:

At December 31,

(In millions)

    

2017(1)

    

2018(2)

    

2019(3)

 

Future net cash flows

$

26,137

$

30,739

$

14,932

Present value of future net cash flows:

Before income tax (PV-10)

$

10,175

$

12,589

$

6,067

Income taxes

$

(1,548)

$

(2,111)

$

(598)

After income tax (Standardized measure)

$

8,627

$

10,478

$

5,469

(1)12 month average prices used at December 31, 2017 were $2.91 per MMBtu for natural gas, $9.95 per Bbl for ethane, $32.37 per Bbl for C3+ NGLs, and $45.35 per Bbl for oil for the Appalachian Basin based on a $51.03 WTI reference price.
(2)12 month average prices used at December 31, 2018 were $2.93 per MMBtu for natural gas, $12.26 per Bbl for ethane, $39.29 per Bbl for C3+ NGLs and $56.62 per Bbl for oil for the Appalachian Basin based on a $65.66 WTI reference price.
(3)12 month average prices used at 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.

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Future net cash flows represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Prices for 2017, 2018 and 2019 were based on 12-month unweighted average of the first-day-of-the-month pricing, without escalation. Costs are based on costs in effect for the applicable year without escalation. There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimates for the same properties.

Changes in Proved Reserves During 2019

The following table summarizes the changes in our estimated proved reserves during 2019 (in Bcfe):

Proved reserves, December 31, 2018

18,011

Extensions, discoveries, and other additions

3,705

Performance revisions

63

Revisions to five-year development plan

(1,705)

Price revisions

(157)

Deconsolidation of Antero Midstream Partners

(164)

Revisions to ethane recovery

315

Production

(1,175)

Proved reserves, December 31, 2019

18,893

Extensions, discoveries, and other additions of 3,705 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. Included in the extensions are 1,202 Bcfe of volumes associated with a third party acreage trade. Upward revisions of 63 Bcfe related to well performance. Net downward revisions of 1,705 Bcfe related to optimization of our five-year development plan. This figure includes upward revisions of 595 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2018 to proved undeveloped at December 31, 2019 due to their addition to our five-year development plan, and downward revisions of 2,300 Bcfe for locations that were not developed within five years of initial booking as proved reserves. Downward revisions of 157 Bcfe were due to decreases in prices for natural gas, NGLs, and oil. Downward revisions of 164 Bcfe were due to an increase in fee structure resulting from the deconsolidation of Antero Midstream Partners. Deconsolidation of Antero Midstream Partners resulted in Antero Resources recording the full fees paid to Antero Midstream Partners for services rendered and no longer including future capital expenditures associated with Antero Midstream Partners’ assets in future development costs. Prior to deconsolidation, Antero Resources’ consolidated reserves included the elimination of full fees paid by Antero Resources to Antero Midstream Partners and the inclusion of the operating costs and capital incurred by Antero Midstream Partners. Upward revisions of 315 Bcfe were due to an increase in our assumed future ethane recovery. Our estimated proved reserves as of December 31, 2019 totaled approximately 18,893 Bcfe, an increase of 5% 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 2019 (in Bcfe):

Proved undeveloped reserves, December 31, 2018

7,622

Extension, discoveries, and other additions

3,433

Performance revisions

141

Revisions to five-year development plan

(1,705)

Price revisions

(30)

Deconsolidation of Antero Midstream Partners

(42)

Reclassifications to proved developed reserves

(2,201)

Revisions to ethane recovery

(65)

Proved undeveloped reserves, December 31, 2019

7,153

Extensions, discoveries, and other additions during 2019 of 3,433 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Marcellus and Utica Shales. Included in the extensions are 1,173 Bcfe of volumes associated with a third party acreage trade. Upward revisions of 141 Bcfe related to well performance. Net downward revisions of 1,705 Bcfe related to optimization of our five-year development plan. This figure includes upward revisions of 595 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2018 to proved undeveloped at December 31, 2019 due to their addition to our five-year development plan, and downward revisions of 2,300 Bcfe for locations that

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were not developed within five years of initial booking as proved reserves. Downward revisions of 30 Bcfe were due to decreases in prices for natural gas, NGLs, and oil. Downward revisions of 42 Bcfe were due to an increase in fee structure resulting from the deconsolidation of Antero Midstream Partners. Deconsolidation of Antero Midstream Partners resulted in Antero Resources recording the full fees paid to Antero Midstream Partners for services rendered and Antero Resources no longer including future capital expenditures associated with Antero Midstream Partners’ assets in future development costs. Prior to deconsolidation, Antero Resources’ consolidated reserves included the elimination of full fees paid by Antero Resources to Antero Midstream Partners and the inclusion of the operating costs and capital incurred by Antero Midstream Partners.

During the year ended December 31, 2019, we converted approximately 2,201 Bcfe, or 29%, of our proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $788 million. We spent an additional $316 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification at December 31, 2018, resulting in total development spending of $1.1 billion, as disclosed in Note 21 to the consolidated financial statements included elsewhere in this report. Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2019 are approximately $2.6 billion, or $0.37 per Mcfe, over the next five years. Based on strip pricing as of December 31, 2019, we believe that cash flows from operations 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 growth 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. As our well economics have changed, we have reallocated five-year capital to areas with expected highest rates of return and optimal lateral lengths. This resulted in the reclassification of 2,300 Bcfe of reserves from proved undeveloped to probable during the year ended December 31, 2019 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.

At December 31, 2019, an estimated 8,500 of our net leasehold acres, containing 227 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 $21 million to renew the 8,500 acres based upon current leasing authorizations and option to extend payments. Proved undeveloped reserves of 687 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 103 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 reserve estimates as of December 31, 2017, 2018 and 2019 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. Our internally prepared reserve estimates were audited by our independent reserve engineers. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources. 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 our independent reserve engineers 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 the independent reserve engineers 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

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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 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.

Proved reserves are reserves that, 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 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. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, micro-seismic data, and well-test data. Probable reserves are reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves that may potentially be recoverable through additional drilling or recovery techniques are, by nature, more uncertain than estimates of proved reserves and, accordingly, are subject to substantially greater risk of realization. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of possible reserves are also inherently imprecise. Estimates of probable and possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors.

Methodology Used to Apply Reserve Definitions

In the Marcellus Shale, our estimated reserves are based on information from our large, operated proved developed producing reserve base, as well as information from other operators in the area, which can be used to confirm or supplement our internal estimates. Typically, proved undeveloped properties are booked based on applying the estimated lateral length to the average wellhead Bcf per 1,000 feet from our proved developed producing wells, then converting to a processed volume where applicable.

We may attribute up to 11 proved undeveloped locations based on one proved developed producing well where analysis of geologic and engineering data can be estimated with reasonable certainty to be commercially recoverable. However, the ratio of proved undeveloped locations generated will be lower when multiple proved developed wells are drilled on a single pad. In addition, we have applied the concept of a statistically proven area to certain areas of our Marcellus Shale acreage whereby undeveloped properties are booked as proved reserves so long as well count is sufficient for statistical analysis and certain land, geologic, engineering and commercial criteria are met.

Although our operating history in the Utica Shale is more limited than our Marcellus Shale operations, we expect to be able to apply a similar methodology once the well count is sufficient for statistical analysis. The primary differences between the two areas are that (i) we have not established a statistically proven area in the Utica Shale and (ii) each proved developed producing well in the Utica Shale only generates four direct offset well locations due to less relative maturity of the play.

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, 2019. 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, Revenues, and Price History

Because natural gas, NGLs, and oil are commodities, the prices that we receive for our production are largely a function of market supply and demand. While demand for natural gas in the United States has increased materially since 2000, natural gas and NGLs supplies have also increased significantly as a result of horizontal drilling and fracture stimulation technologies which have been used to find and recover large amounts of oil and gas from various shale formations throughout the United States. Demand 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

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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.”

Operations Data – 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, 2017, 2018 and 2019. 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,

2017

2018

2019

Production data:

Natural gas (Bcf)

591

710

822

C2 Ethane (MBbl)

10,539

14,221

15,861

C3+ NGLs (MBbl)

25,507

28,913

39,445

Oil (MBbl)

2,451

3,265

3,632

Combined (Bcfe)

822

989

1,175

Daily combined production (MMcfe/d)

2,253

2,709

3,220

Average sales prices before effects of derivative settlements:

Natural gas (per Mcf)

$

2.99

$

3.22

$

2.74

C2 Ethane (per Bbl)

$

8.83

$

12.14

$

7.85

C3+ NGLs (per Bbl)

$

30.48

$

34.76

$

27.75

Oil (per Bbl)

$

44.14

$

57.34

$

48.88

Combined average sales prices before effects of derivative settlements (per Mcfe) (1)

$

3.34

$

3.69

$

3.10

Combined average sales prices after effects of derivative settlements (per Mcfe) (1)

$

3.60

$

3.94

$

3.38

Average Costs (per Mcfe) (2):

Lease operating

$

0.11

$

0.14

$

0.13

Gathering, compression, processing, and transportation

$

1.75

$

1.81

$

1.92

Production and ad valorem taxes

$

0.11

$

0.12

$

0.11

Marketing, net

$

0.13

$

0.23

$

0.22

Depletion, depreciation, amortization, and accretion

$

0.86

$

0.85

$

0.76

General and administrative (excluding equity-based compensation)

$

0.14

$

0.13

$

0.12

(1)Average sales prices shown in the table reflect both the before and after effects of our settled derivatives. Our calculation of such after effects includes gains on settlements of derivatives excluding proceeds from the derivative monetizations in 2017 and 2018. Our hedges 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.
(2)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.

Productive Wells

As of December 31, 2019, we held interests in a total of 1,238 gross (1,148.2 net) producing wells on our Marcellus Shale acreage, including the following:

915 gross (904.4 net) horizontal wells, averaging a 99% working interest, operated by us.
64 gross (5.6 net) horizontal wells operated by other producers.
259 gross (238.2 net) shallow vertical wells.

As of December 31, 2019, we held interests in a total of 244 gross (206.3 net) producing wells on our Ohio Utica Shale acreage, including the following:

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222 gross (206.2 net) horizontal wells, averaging a 93% working interest, operated by us.
22 gross (0.1 net) horizontal wells operated by other producers.

Additionally, at December 31, 2019, we had 19 net horizontal proved developed non-producing wells, and 68 gross horizontal wells (65.5 net) that were drilled and uncompleted or in the process of being completed. The shallow vertical wells and wells operated by other producers were primarily acquired in conjunction with leasehold acreage acquisitions.

Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we own an interest as of December 31, 2019. A majority of our developed acreage is subject to liens securing the Credit Facility. Approximately 70% of our net Marcellus acreage and 71% of our net Utica acreage is held by production. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this table.

Developed Acres

Undeveloped Acres

Total Acres

Basin

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

Marcellus Shale

149,777

148,098

343,269

302,535

493,046

450,633

Utica Shale

44,989

40,800

55,873

50,014

100,862

90,814

Total

194,766

188,898

399,142

352,549

593,908

541,447

The following table provides a summary of our current gross and net acreage by county in the Marcellus Shale and the Ohio Utica Shale in which we own an interest as of December 31, 2019.

Marcellus

Gross

Net

County, State

Acres

Acres

 

Doddridge, WV

145,562

133,041

Fayette, PA

5,967

5,454

Gilmer, WV

6,147

5,619

Harrison, WV

96,692

88,374

Lewis, WV

46

42

Marion, WV

5,342

4,882

Monongalia, WV

1,340

1,225

Pleasants, WV

3,692

3,374

Ritchie, WV

72,712

66,457

Tyler, WV

103,543

94,636

Washington, PA

115

105

Westmoreland, PA

4,019

3,673

Wetzel, WV

47,869

43,751

Total Marcellus Shale

493,046

450,633

Ohio Utica

Gross

Net

Acres

Acres

 

Belmont, OH

7,653

5,450

Guernsey, OH

3,635

3,158

Monroe, OH

47,024

45,616

Noble, OH

42,496

36,544

Washington, OH

54

46

Total Utica Shale

100,862

90,814

Total Marcellus and Utica Shales

593,908

541,447

Undeveloped Acreage Expirations

The following table sets forth our total gross and net undeveloped acres as of December 31, 2019 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates, or unless the leases containing such acreage are extended or renewed.

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Marcellus

Ohio Utica

Total

Gross

Net

Gross

Net

Gross

Net

Acres

Acres

Acres

Acres

Acres

Acres

2020

28,432

25,987

15,001

13,300

43,433

39,287

2021

35,209

32,180

7,091

5,984

42,300

38,164

2022

41,719

38,131

5,413

4,371

47,132

42,502

Drilling Activity

The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2017, 2018 and 2019. 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,

2017

2018

2019

    

Gross

Net

    

Gross

Net

    

Gross

Net

 

Marcellus

Development wells:

Productive

112

111

136

134

117

116

Dry

Total development wells

112

111

136

134

117

116

Exploratory wells:

Productive

1

1

2

2

8

8

Dry

Total exploratory wells

1

1

2

2

8

8

Utica

Development wells:

Productive

4

4

17

17

6

6

Dry

Total development wells

4

4

17

17

6

6

Exploratory wells:

Productive

18

18

8

8

Dry

Total exploratory wells

18

18

8

8

Total

Development wells:

Productive

116

115

153

151

123

122

Dry

Total development wells

116

115

153

151

123

122

Exploratory wells:

Productive

19

19

10

10

8

8

Dry

Total exploratory wells

19

19

10

10

8

8

The figures in the table above do not include 68 gross wells (65 net) that were drilled and uncompleted or in the process of being completed at December 31, 2019.

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Delivery Commitments

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, 2019, our firm sales commitments through 2024 included:

Volume of

Volume of

Volume of

Natural Gas

Ethane

C3+ NGLs

Year Ending December 31,

(MMBtu/d)

(Bbl/day)

(Bbl/day)

2020

1,030,000

46,500

55,000

2021

900,000

76,500

23,000

2022

780,000

96,500

5,000

2023

690,000

96,500

5,000

2024

600,000

91,500

5,000

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.”

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. Unlike many producing basins in the United States, certain portions of the Appalachian Basin do not have sufficient midstream infrastructure to support the existing and expected increasing levels of production. Our relationship with Antero Midstream allows us to obtain the necessary gathering and compression capacity for our production and we have leveraged our relationship with Antero Midstream to support our growth. For the years ended December 31, 2018 and 2019, Antero Midstream spent approximately $444 million and $316 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, 2019, Antero Midstream owned and operated 324 miles of gas gathering pipelines in the Marcellus Shale. We also have access to additional low-pressure and high-pressure pipelines owned and operated by third parties. As of December 31, 2019, Antero Midstream owned and operated 17 compressor stations and we utilized 12 additional third-party compressor stations in the Marcellus Shale. The gathering, compression, and dehydration services provided by third parties are contracted on a fixed-fee basis.

As of December 31, 2019, in the Utica Shale Antero Midstream owned and operated 110 miles of low-pressure and high-pressure gathering pipelines and Antero Resources owned and operated eight miles of high-pressure pipelines. As of December 31, 2019, Antero Midstream owned and operated two compressor stations and we utilized four additional third-party compressor stations in the Utica Shale.

Natural Gas Processing

Many of our wells in the Marcellus and Utica Shales allow us to produce liquids-rich natural gas that contains a significant amount of NGLs. Liquids-rich natural gas must be 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 a 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.

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The combination of infrastructure constraints in the Appalachian region 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.

As of December 31, 2019, we had contracted with MarkWest Energy Partners L.P. to provide cryogenic processing capacity for our Marcellus and Utica Shales production as follows:

Contracted

Plant

Firm

Processing

Processing

Capacity

Capacity

Completion

(MMcf/d)

(MMcf/d)

Status

 

Marcellus Shale:

Sherwood 1

200

200

In service

Sherwood 2

200

200

In service

Sherwood 3

200

200

In service

Sherwood 4

200

200

In service

Sherwood 5

200

200

In service

Sherwood 6

200

200

In service

Sherwood 7

200

200

In service

Sherwood 8

200

200

In service

Sherwood 9

200

200

In service

Sherwood 10

200

200

In service

Sherwood 11

200

200

In service

Sherwood 12

200

200

In service

Sherwood 13

200

200

In service

Smithburg 1

200

200

2Q 2020*

Marcellus Shale Total

2,800

2,800

Utica Shale:

Seneca 1

200

150

In service

Seneca 2

200

50

In service

Seneca 3

200

200

In service

Seneca 4

200

200

In service

Utica Shale Total

800

600

* Anticipated in-service date

Antero Midstream owns a 50% interest in the Joint Venture which owns certain of the existing and future Sherwood gas processing plants and a 33 1/3% interest in two fractionation facilities located at the Hopedale complex in Harrison County, Ohio. The Joint Venture’s processing investment began with the seventh plant at the Sherwood facility and continues through Sherwood 13 and Smithburg 1 in the table above. The Joint Venture provides processing services to us under a long-term, fixed-fee arrangement, subject to annual CPI-based adjustments.

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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:

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”).
oThe 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. We have 290,000 MMBtu per day of firm transportation on MGT. We have 310,000 MMBtu per day of firm transportation on NGPL. Both of these contracts deliver gas to the Chicago city gate area. In addition, we have 200,000 MMBtu per day of firm transportation on ANR to deliver 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.
To access the Gulf Coast market and Eastern Regional markets, we have firm transportation contracts with various pipelines. These contracts include firm capacity on the Columbia Gas Transmission pipeline (“TCO”), Columbia Gulf Transmission pipeline (“Columbia Gulf”), Tennessee Gas Pipeline (“Tennessee”), Energy Transfer Rover Pipeline (“ET Rover”), ANR Pipeline (“ANR-Gulf”), Equitrans pipeline (“EQT”), and DTE Energy’s Stonewall Gas Gathering (“SGG”) and Appalachia Gathering System (“AGS”). This 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.
oWe have several firm transportation contracts on TCO for volumes that total to approximately 584,000 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 of firm capacity on Columbia Gulf, which provides access to the Gulf Coast markets. These contracts expire at various dates from 2021 through 2058.
oWe have a firm transportation contract with SGG for 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. We have a firm transportation contract with TCO to transport natural gas in the western and eastern direction on TCO’s WB system. The firm transportation contract on TCO’s WB system provides firm capacity in the western direction for 800,000 MMBtu per day. This west directed firm capacity provides access to the local Appalachia market and the Gulf Coast market via the Columbia Gulf or Tennessee pipelines. The firm transportation contract on TCO’s WB system also provides firm capacity in the eastern direction, which delivers natural gas to the Cove Point LNG facility, for 330,000 MMBtu per day. These contracts expire at various dates from 2033 through 2038.
oWe have a firm transportation contract for 790,000 MMBtu per day on Tennessee to deliver natural gas from the Broad Run interconnect on TCO’s WB system to the Gulf Coast market. This contract expires in 2033.
oWe have a firm transportation contract for 600,000 MMBtu per day on ANR-Gulf to deliver natural gas from West Virginia and Ohio to the U.S Gulf Coast market. This contract expires in 2045.
oWe have a firm transportation contract for 800,000 MMBtu per day on the ET Rover Pipeline, which connects the Marcellus and Utica Shales’ assets to Midwest and Gulf Coast markets via our existing firm transportation on ANR Chicago and ANR Gulf. This contract expires in 2033.
oWe have firm transportation contracts for 250,000 MMBtu per day on EQT to deliver Marcellus natural gas to Tetco M2 and other various delivery points. These contracts expire at various dates from 2022 through 2025.
oWe have firm transportation contracts for 275,000 MMBtu per day on the DTE AGS to deliver Marcellus natural gas to TETCO M2 and other various local delivery points. These contracts expire in 2023.
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oWe have firm transportation contracts for 700,000 MMBtu per day on MXP to deliver 517,000 MMBtu per day to TCO IPP and 183,000 MMBtu per day continues on GXP to Leach, Kentucky and deliver to the U.S. Gulf Coast. These contracts expire in 2033.
We have a firm transportation contract for 20,000 Bbl per day on the Enterprise Products Partners ATEX pipeline (“ATEX”), to take ethane from Appalachia to Mont Belvieu, Texas. The ATEX firm transportation commitment expires in 2028.
We have a firm transportation contract for 11,500 Bbl per day on the Sunoco pipeline (or “Mariner East 2”) to take ethane from Houston, Pennsylvania to Marcus Hook, Pennsylvania.  This contract began November 2018. We also have a firm transportation contract on Mariner East 2 to take a combination of 50,000 Bbl per day of propane and butane from Hopedale, Ohio to Marcus Hook, Pennsylvania, which began February 2019. This contract increases 5,000 Bbl per day each year from 2020 – 2022, resulting in an ultimate total of 65,000 Bbl per day. These contracts expire on the tenth anniversary from the in-service date. 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 2020 annual production guidance, we estimate that we could incur annual net marketing costs of $0.10 per Mcfe to $0.12 per Mcfe in 2020 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.

Water Handling and Treatment Operations

On September 23, 2015, we contributed (i) all of the outstanding limited liability company interests of Antero Water LLC to Antero Midstream and (ii) all of the assets, contracts, rights, permits and properties we owned or leased and used primarily in connection with the construction, ownership, operation, use or maintenance of our advanced wastewater treatment facility in Doddridge County, West Virginia, to Antero Treatment LLC, a wholly owned subsidiary of Antero Midstream. Our relationship with Antero Midstream allows 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 Marcellus and Utica Shales. These systems consist of permanent buried pipelines, movable surface pipelines and fresh water storage facilitates, as well as pumping stations to transport the fresh water throughout the pipeline networks. To the extent necessary, the surface pipelines are moved to well pads for service completion operations in concert with our drilling program. As of December 31, 2019, Antero Midstream had the ability to store 5.8 million barrels of fresh water in 38 impoundments located throughout our leasehold acreage in the Marcellus and Utica Shales. Due to the extensive geographic distribution of Antero Midstream’s water pipeline systems in both West Virginia and Ohio, 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, 2019, Antero Midstream owned and operated 149 miles of buried fresh water pipelines and 98 miles of movable surface fresh water pipelines in the Marcellus Shale, as well as 26 fresh water storage facilities equipped with transfer pumps. As of December 31, 2019, Antero Midstream owned and operated 54 miles of buried fresh water pipelines and 31 miles of movable surface fresh water pipelines in the Utica Shale, as well as 12 fresh water storage facilities equipped with transfer pumps.

We recently announced certain efficiency improvements and water initiatives, which are expected to reduce the amount of fresh water needed to complete our operations.  Through Antero Midstream, we have also commenced operations to recycle and reuse a portion of our flowback and produced water through blending.

Major Customers

For the year ended December 31, 2019, sales to Sabine Pass Liquefaction, LLC and WGL Midstream accounted for approximately 16% and 15% of our total product revenues, respectively. For the year ended December 31, 2018, sales to Mercuria Energy America, Inc. and Tenaska Marketing Ventures accounted for approximately 14% and 13% of our total product revenues,

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respectively. For the year ended December 31, 2017, sales to Tenaska Marketing Ventures and WGL Midstream accounted for approximately 20% and 14% of our total product revenues, respectively.

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.

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. Cold winters can significantly increase demand and price fluctuations. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the spring, summer and fall. This can also reduce seasonal demand fluctuations. Seasonal anomalies can also increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do. Many of these companies not only explore for and produce natural gas, but also carry on 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 natural gas properties and exploratory prospects or define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit, and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. 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. 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.

Regulation of the Oil and Natural Gas Industry

General

Our oil and natural gas operations are subject to extensive, and frequently changing, laws and regulations related to well permitting, drilling, and completion, and to the production, transportation and sale of natural gas, NGLs, and oil. We believe compliance with existing requirements will not have a materially adverse effect on our financial position, cash flows or results of operations. However, such laws and regulations are frequently amended or reinterpreted. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, the states, local governments, and the courts. We cannot predict when or whether any such proposals may become effective. Therefore, we are unable to predict the future costs or impact of compliance. The regulatory burden on the industry increases the cost of doing business and affects profitability. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers, and marketers with which we compete.

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Regulation of Production of Natural Gas and Oil

We own interests in properties located onshore in West Virginia and Ohio, and our production activities on these properties are subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. These statutes and regulations address requirements related to permits for drilling of wells, bonding 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, the plugging and abandonment of wells, venting or flaring of natural gas, and the ratability or fair apportionment of production from fields and individual wells. In addition, all of the states in which we own and operate properties have regulations governing environmental and conservation matters, including provisions for the handling and disposing or discharge of waste materials, the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, and the size of drilling and spacing units or proration units and the density of wells that may be drilled. Some states also have the power to prorate production to the market demand for oil and gas. The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, NGLs, and oil within its jurisdiction.

The failure to comply with these rules and regulations 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.

Regulation of Transportation of Natural Gas

The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

Gathering services, which occurs upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Sales of Natural Gas, NGLs, and Oil

The prices at which we sell natural gas, NGLs, and oil are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate pipeline transportation of oil, NGLs, and

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other products, is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural gas and all sales of crude oil, condensate, and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

With regard to our physical sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC as described below, the U.S. Commodity Futures Trading Commission under Commodity Exchange Act, or CEA, and the Federal Trade Commission, or FTC. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Should we violate the anti-market manipulation laws and regulations, we could be subject to fines and penalties as well as related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

The Domenici Barton Energy Policy Act of 2005, or EPAct of 2005 amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provided FERC with additional civil penalty authority. In Order No. 670, FERC promulgated rules implementing the anti-market manipulation provision of the EPAct of 2005, which make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704 described below. Under the EPAct of 2005, FERC has the power to assess civil penalties of up to $1,000,000 per day for each violation of the NGA and the NGPA. In January 2020, FERC issued an order (Order No. 865) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of up to $1,291,894 per violation per day.

Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. In November 2009, the 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 $2 million (adjusted annually for inflation) per violation per day. Together with FERC, these agencies have imposed broad rules and regulations prohibiting fraud and manipulation in oil and gas markets and energy futures markets.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Regulation of Environmental and Occupational Safety and Health Matters

General

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health and the discharge of materials into the environment or otherwise relating to environmental protection. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas or areas with endangered or

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threatened species restrictions, require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits, establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and occupational health and workplace safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our financial position, results of operations or cash flows.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons incl