UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2018

or

For the transition period from                      to                     

Commission File Number: 001-36511

Montage Resources Corporation

(Exact name of registrant as specified in its charter)

(469) 444-1647

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   ☐     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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     ☐

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 not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    ☐  Yes    ☒  No

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2018, the last business day of the most recently completed second fiscal quarter, was approximately $140 million.

Number of shares of the registrant’s common stock outstanding at March 13, 2019: 35,193,719 shares.

Documents incorporated by reference: Portions of the registrant’s proxy statement for its 2019 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

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Cautionary Statement Regarding Forward-Looking Statements

This Annual Report on Form 10-K (the “Annual Report”) contains “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, regarding our strategy, future operations, financial position, estimated revenues and income or losses, projected costs and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “will,” “plan,” “would,” “could,” “endeavor,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are or were, when made, based on current expectations and assumptions about future events and are or were, when made based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described in “Item 1A. Risk Factors” of this Annual Report.

Forward-looking statements may include statements about, among other things:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, legal and environmental risks, drilling and other operating risks, regulatory changes, commodity price volatility and the significant decline of the price of natural gas, NGLs and oil from historical highs, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flows and access to capital, risks associated with our level of indebtedness, the timing of development expenditures, and the other risks described in “Item 1A. Risk Factors” of this Annual Report.

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Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could 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 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 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, all of which are expressly qualified by the statements in this section, to reflect new information obtained or events or circumstances that occur after the date of this Annual Report.

Glossary of Oil and Natural Gas Terms

As used in this Annual Report, unless the context indicates or otherwise requires, the following terms have the following meanings:

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(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances;

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time;

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir (as defined in Rule 4-10(a) (2) of Regulation S-X), or by other evidence using reliable technology establishing reasonable certainty;

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PART I

Our Company

Montage Resources Corporation, a Delaware corporation formed in 2014, is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. As of December 31, 2018, we had assembled an acreage position approximating 241,000 net acres in Ohio and Pennsylvania.  We intend to focus on developing our substantial inventory of horizontal drilling locations during commodity price environments that will allow us to generate attractive returns and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.  As used in this Annual Report, unless the context indicates or otherwise requires, “Montage” “Montage Resources,” the “Company,” “we,” “our,” “us” and like terms refer collectively to Montage Resources Corporation and its consolidated subsidiaries.

Our Properties

As of December 31, 2018, we had approximately 134,000 net acres in the Utica Shale fairway, which we refer to as the Utica Core Area and approximately 14,500 net acres of stacked pay opportunity in our Marcellus Area.  We are the operator of approximately 94% of our proved reserves within the Utica Core Area and our Marcellus Area. Additionally, we own approximately 107,000 net acres (which are approximately 94% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale.

Utica Shale

The Ordovician-aged Utica Shale is an unconventional reservoir comprised of organic-rich black shale, with most production occurring at vertical depths between 6,000 and 10,000 feet. The richest and thickest concentration of organic-carbon content is present within the Point Pleasant layer of the Lower Utica formation.  Across the Utica Core Area, the eastern boundary is more thermally mature and expected to produce dry gas, while the western boundary is less thermally mature and expected to produce a greater proportion of condensate and NGLs in addition to natural gas.  We classify our acreage between these boundaries as being prospective for Dry Gas, Rich Gas, or Condensate.

Indian Castle/Flat Creek Shales

The Indian Castle and Flat Creek Shales consist of organic-rich black shale, and we refer to them collectively as the “Flat Castle” area.  They are Ordovician in age and are correlative to the Utica, Point Pleasant and Logana Shales of Ohio.  The core of the area is located in Tioga County, Pennsylvania.  The top of the Flat Castle area is between 9,500 and 10,500 feet deep.  As of December 31, 2018, we had approximate 45,000 net acres in the core of the area.  The shales in the Flat Castle area are very mature and produce Dry Gas in the area.

Marcellus Shale

The Marcellus Shale consists of organic-rich black shale, with most production occurring at vertical depths between 5,000 and 8,000 feet.  As of December 31, 2018, we had approximately 14,500 net acres of stacked pay opportunity in the highly liquids rich area of the Marcellus Shale in Eastern Ohio within what we refer to as our Marcellus Area. The reservoir underlying this acreage is less thermally mature than the Marcellus Shale in Southwestern Pennsylvania, and consequently, we believe natural gas production from this area will yield significant NGLs and condensate.

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Activity

Through December 31, 2018, we, or our operating partners, had commenced drilling 256 gross (136.1 net) wells within the Utica Core Area and our Marcellus Area, which are summarized below:

As of December 31, 2018, our estimated proved reserves were 1,864.7 Bcfe, or 310.8 MMBoe, an increase of 28% from December 31, 2017 estimated proved reserves of 1,458.6 Bcfe, or 243.1 MMBoe, based on reserve reports prepared by Software Integrated Solutions Division of Schlumberger Technology Corporation (“SIS”), our independent petroleum engineers for the year ended December 31, 2018, and Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineers for the year ended December 31, 2017. As of December 31, 2018, our estimated proved reserves were approximately 82% natural gas, 11% NGLs and 7% oil, and approximately 36% were proved developed reserves. The following table provides information regarding our proved reserves as of December 31, 2018, 2017, and 2016:

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Net Undeveloped Locations

The following table provides a summary of our approximate net acreage, net producing locations and net undeveloped locations as of December 31, 2018:

Determination of Drilling Locations

Net undeveloped locations are calculated by taking our total net acreage and multiplying such amount by a risk factor, which is then divided by our expected well spacing.  In each type curve area, we apply a 10% risk factor to our net acreage to account for inefficient unitization, acreage expirations and the risk associated with our inability to force pool under state law.  We then subtract net producing wells to arrive at net undeveloped locations.

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Midstream Agreements

We work closely with our midstream partners to coordinate our drilling and completion schedule with their well hook up and facility construction schedule to ensure sufficient capacity is available to minimize any delays in turning production into sales.

We have contracted for firm gathering, processing and fractionation capacity for a significant portion of our operated acreage in the Condensate and Rich Gas Windows of the Utica Core Area with Blue Racer Midstream, LLC (“Blue Racer”), a joint venture between First Reserve and Caiman Energy II, LLC.  This gas-processing agreement does not require us to make minimum volume deliveries or shortfall payments.  

In 2018, we amended our firm gas gathering services agreement with Eureka Midstream LLC (“Eureka Midstream”) to gather and compress a substantial portion of our operated production of Dry Gas through Eureka Midstream’s system. This new agreement replaced an existing agreement with Eureka Midstream that we had entered into in 2013. Under the new 20-year agreement, we have firm gathering capacity, which increases during the term of the agreement, from between approximately 275 MMcf to 900 MMcf per day. This agreement provides for reduced gathering and compression charges. Through this agreement, we obtained access to additional downstream pipelines and markets connected to Eureka Midstream including the Rover Pipeline System, accessing our firm transportation capacity. This midstream agreement requires us to make minimum volume deliveries to the Eureka Midstream gathering system or shortfall payments. The following table illustrates the minimum volume commitments under our agreement with Eureka Midstream:

During 2018, we assigned our option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC (“Cardinal”), a wholly owned subsidiary of Cardinal Midstream II, LLC, which owns midstream infrastructure with associated gathering rights on acreage in the Flat Castle area, to DTE Pipeline Company (“DTE”).  The option was exercised and DTE completed its acquisition of Cardinal in July 2018.  The legacy gathering agreement was assigned to DTE and does not require us to make minimum volume deliveries or shortfall payments.

The following table illustrates the natural gas firm transportation and sales volumes associated with our operated assets:

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As of December 31, 2018, our natural gas firm transportation commitments through 2023 include:

The minimum demand fees related to these volume and firm transportation agreements that were in place as of December 31, 2018 are reflected in our table of contractual obligations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Contractual Obligations.” See “Item 1A. Risk Factors” for a discussion of risks and uncertainties relating to our gathering, processing and fractionation arrangements.

In March 2014, we entered into a 20-year contract with Shell Chemical, LP (“Shell Chemical”) for the sale of ethane to Shell Chemical’s proposed Appalachian cracker project in Monaca, Pennsylvania. Under the terms of the contract, we agreed to sell to Shell Chemical, at a minimum, all of our “Must Recover Ethane” (i.e., 30% of total recoverable ethane) at Blue Racer’s fractionation facility near Natrium, West Virginia.  In June 2016, Shell Chemical provided notice of a positive final investment decision and election to purchase our ethane.

In August 2014, we entered into an agreement with EnLink Midstream Operating, LP (“EnLink Midstream”) for the marketing of our condensate and operation of our condensate stabilization facilities. Under the terms of the agreement, among other things, EnLink Midstream purchased two of our existing condensate stabilization facilities, and plans to construct and operate additional facilities to support our drilling program in the Utica Shale. This midstream agreement requires us to make minimum volume deliveries to the condensate stabilization facilities or shortfall payments. The following table illustrates the minimum volume commitments under our agreement with EnLink Midstream:

In December 2014, we entered into a 10-year firm transportation and marketing agreement with Blue Racer to market a substantial portion of our operated production of propane and butane through Blue Racer’s firm capacity on Sunoco’s Mariner East II Project. Commencing operations in late 2018, the Mariner East II Project connects the NGL resources in the Marcellus and Utica Shale to Sunoco’s existing infrastructure and international port at its Marcus Hook facility near Philadelphia.  During 2018, we modified the agreement to eliminate minimum volume commitments or shortfall payments, while maintaining our ability to market a portion of our operated production of propane and butane through the Mariner East II project.  Through this agreement, we will export propane and butane in order to potentially capture the premium pricing offered by international markets, but also retain the ability to sell domestically.

In April 2017, we entered into a 2-year hauling and marketing agreement with Marathon Petroleum Company LP (“Marathon” or “Marathon Petroleum”) to sell condensate volumes. As a part of this contract, Marathon will pick up the produced condensate at our stabilization facilities and well pads and haul it away utilizing their own fleet of vehicles or third-party services. The title and risk of loss will pass to Marathon at the intake flange of our stabilization facilities under the terms of this contract.

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Recent Developments

BRMR Merger

On February 28, 2019, the Company completed its previously announced business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”).

As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock split described below. Former stockholders of BRMR will receive cash for any fractional shares of the Company’s common stock to which they might otherwise be entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.

BRMR, a Delaware corporation formed in 1997, is an independent exploration and production company engaged in the acquisition, development and production of natural gas, NGLs and oil.  BRMR is active in two of the most prolific unconventional shale resource plays in North America, the Marcellus and Utica Shales.  As of December 31, 2018, BRMR held approximately 95,300 net surface leasehold acres in the Marcellus and Utica Shales in Ohio and West Virginia, approximately 85,100, or 89%, of which are undeveloped.  Approximately 81% of BRMR’s total net surface acres in these areas are held by production.  BRMR is the operator on approximately 98% of this net acreage and holds an average 78% working interest across the position within developed units.

Reverse Stock Split

Effective immediately prior to the Effective Time on February 28, 2019, the Company effected a 15-to-1 reverse stock split with respect to the issued and outstanding shares of its common stock. Holders of shares of the Company’s common stock immediately prior to the Effective Time will receive cash for any fractional shares of the Company’s common stock to which they might otherwise be entitled as a result of the reverse stock split. The reverse stock split lowered the par value to reflect the reduced shares with the offset to additional paid-in-capital.  All issued and outstanding share and per share amounts presented in this Annual Report have been adjusted retroactively to reflect the reverse stock split in accordance with ASC 505 “Equity”.

Name Change

Following the Effective Time on February 28, 2019, the Company effected a change in its legal name to “Montage Resources Corporation” through a Certificate of Ownership and Merger providing for a short-form merger pursuant to Section 253 of the General Corporation Law of the State of Delaware pursuant to which a subsidiary formed solely for the purpose of the name change was merged with and into the Company with the Company remaining as the surviving corporation in the merger. The short-form merger had the effect of amending the Company’s certificate of incorporation to reflect the Company’s new legal name.

Amendment to the Revolving Credit Facility

On February 28, 2019, the Company amended and restated the credit agreement governing its revolving credit facility to, among other things, increase the borrowing base from $225 million to $375 million and extend the maturity date thereof to approximately five years after the closing of the BRMR Merger.  The amended and restated credit agreement also adjusted the ratio of Consolidated Total Funded Net Debt to EBITDAX (as such terms are defined in the amended and restated credit agreement) to provide that the Company will not, as of the last day of any

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fiscal quarter (commencing with the fiscal quarter ending March 31, 2019), permit its ratio of Consolidated Total Funded Net Debt to EBITDAX for the four previous fiscal quarters to be greater than 4.00 to 1.00.

2019 Capital Budget

Our Board of Directors recently approved an initial capital budget for 2019 of between approximately $375 - $400 million, allocated approximately 90% for drilling and completions activities and approximately 10% for land activities and other capital requirements. The 2019 capital budget is expected to be substantially funded through internally generated cash flows, the Company’s current cash balance and borrowings under our revolving credit facility.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Proved Reserves. Our historical proved reserve estimates were prepared by SIS for the year ended December 31, 2018 and NSAI for all prior years. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to 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. Neither SIS and nor NSAI own an interest in any of our properties, nor are they employed by us on a contingent basis. A copy of SIS proved reserve report as of December 31, 2018 and NSAI’s proved reserve reports as of December 31, 2017 and 2016 are attached hereto as exhibits.

We maintain an internal staff of engineers and geoscience professionals who work closely with SIS to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets. Our internal technical team members meet with SIS periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information for our properties to SIS, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Adam Caputo, our Manager, Reserves Reporting, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Caputo is an engineer with approximately eight years of reservoir and operations experience and our geoscience staff has an average of approximately 10 years of industry experience.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

SIS evaluated the proved reserves of 1,864.7 Bcfe as of December 31, 2018.  Schlumberger Technology Corporation was founded in 1926 and is the world’s leading provider of technology for reservoir characterization, drilling, production and process to the oil and natural gas industry.  SIS provides consulting, information management, and IT infrastructure services and sells proprietary software to customers in the oil and natural gas industry.  SIS also offers expert consulting services for reservoir characterization, field development planning and

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production enhancement.  The Lead Evaluator for the evaluation was Charles M. Boyer II, and his qualifications, independence, objectivity, and confidentiality meet the requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.  He has over 27 years of practical experience in the estimation and evaluation of reserves.  Mr. Boyer has been an employee of SIS since 1998 and is currently the Technical Team Leader and Advisor-Unconventional Reservoirs.  His responsibilities include reserves evaluation, acquisition and divestiture analysis, unconventional reservoir analysis, and underground gas storage evaluation.  Mr. Boyer graduated with a Bachelor of Science degree in Geological Sciences from The Pennsylvania State University in 1976; he is a registered Professional Geologist in the Commonwealth of Pennsylvania (No. PG004509), a Certified Petroleum Geologist of the American Association of Petroleum Geologists (No. 5733), and is a member in good standing of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists, and the Society for Mining, Metallurgy, and Exploration.

The reserves estimates as of December 31, 2017 and 2016 shown herein are based upon evaluations prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.  Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Steven W. Jansen and Mr. Edward C. Roy III.  Mr. Jansen, a Licensed Professional Engineer in the State of Texas (No. 112973), has been practicing consulting petroleum engineering at NSAI since 2011 and has over 4 years of prior industry experience.  He graduated from Kansas State University in 2007 with a Bachelor of Science Degree in Chemical Engineering.  Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience.  He graduated from Texas Christian University in 1992 with a Bachelor of Science Degree in Geology and from Texas A&M University in 1998 with a Master of Science Degree in Geology.  Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2018, 2017, and 2016 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties.

To estimate economically recoverable proved reserves and related future net cash flows, SIS considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and

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engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Natural Gas, NGLs and Oil Reserves. The following table presents our estimated net proved natural gas, NGLs and oil reserves as of December 31, 2018, based on the proved reserve report prepared by SIS, our independent petroleum engineers for the year ended December 31, 2018, and as of December 31, 2017 and 2016, based on the proved reserve reports prepared by NSAI, our independent petroleum engineers for the years ended December 31, 2017 and 2016, and such proved reserve reports have been prepared in accordance with the rules and regulations of the SEC. Our estimated proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December for the years 2018, 2017, and 2016. For oil and NGLs volumes, the average WTI spot price of $65.56 per barrel for December 31, 2018, $51.34 per barrel for December 31, 2017 and $42.75 per barrel for December 31, 2016, has been adjusted by property group for quality, transportation fees and regional price differentials. For gas volumes, the average NYMEX Henry Hub spot price of $3.10 per MMBtu for December 31, 2018, $2.98 per MMBtu for December 31, 2017 and $2.48 per MMBtu for December 31, 2016 has been adjusted by property group for energy content, transportation fees and regional price differentials. All prices are held constant throughout the lives of the properties. All of our proved reserves are located in the United States. Copies of the proved reserve reports as of December 31, 2018 prepared by SIS and December 31, 2017 and 2016 prepared by NSAI with respect to our properties are included as exhibits to this Annual Report. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of natural gas, NGLs and oil that are ultimately recovered. Estimates of economically recoverable natural gas, NGLs and oil and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic

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interpretation, prices and future production rates and costs. Please read “Item 1A. Risk Factors” appearing elsewhere in this Annual Report.

Additional information regarding our proved reserves can be found in the notes to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” and the proved reserve reports as of December 31, 2018, 2017, and 2016, which are included as exhibits to this Annual Report.

Proved Reserves Additions and Revisions

To maintain and grow production and cash flow, we must continue to develop existing proved reserves and locate or acquire new natural gas, NGLs and oil reserves. The following is a discussion of net proved reserves, reserve additions and revisions and future net cash flows from proved reserves.

During the year ended December 31, 2018, we increased proved reserves by 406.1 Bcfe compared to the year ended December 31, 2017, primarily through extensions, performance revisions and acquisitions. This increase in proved reserves was comprised of 558.1 Bcfe of extensions and 16.3 Bcfe of acquisitions.  The increase was offset by 125.3 Bcfe of production, 42.8 Bcfe of revisions and 0.2 Bcfe from the divestiture of one non-operated producing well.  The revisions consisted of positive adjustments due to increased SEC pricing and differentials of 21.8 Bcfe, a positive performance revision of 67.5 Bcfe primarily due to well performance adjustments and a negative revision of 132.1 Bcfe due to changes in well spacing and field development.

Future Net Cash Flows. At December 31, 2018, 2017, and 2016, the standardized measure of estimated future net cash flows after income taxes from our proved reserves was $1,329.3 million, $729.7 million and $206.0 million, respectively.  At December 31, 2018, 2017, and 2016, the PV-10 value of estimated future net cash flows before income taxes from our proved reserves was $1,366.7 million, $729.7 million and $206.0 million, respectively. These PV-10 values were calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves.

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The following table sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity hedges), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (standardized measure):

PV-10 is a non-GAAP financial measure 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 oil and natural gas 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.  We believe that the presentation of the pre-tax PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our reserves prior to taking into account corporate income taxes and our current tax structure.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2018, our proved undeveloped reserves were comprised of 12,793.4 MBbls of oil, 1,030.2 Bcf of natural gas and 14,517.2 MBbls of NGLs, for a total of 1,194.1 Bcfe. As of December 31, 2017, our proved undeveloped reserves were comprised of 13,031.2 MBbls of oil, 755.5 Bcf of natural gas and 28,147.7 MBbls of NGLs, for a total of 1,002.6 Bcfe.  As of December 31, 2016, our proved undeveloped reserves were comprised of 718.1 MBbls of oil, 160.4 Bcf of natural gas and 1,155.5 MBbls of NGLs, for a total of 171.6 Bcfe.  PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes our changes in PUDs during 2016, 2017, and 2018 (in Bcfe):