Antero Resources Earnings 2019-12-31

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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Commission File No. 001-36120

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ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

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(303) 357-7310

(Registrant’s telephone number, including area code)

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Securities Registered Pursuant to Section 12(g) of the Act: None.

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

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.

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.

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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:

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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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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.

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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.

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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.

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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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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:

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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):