UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

For the fiscal year ended December 31, 2017

or

For the transition period from                      to                     

Commission File Number: 001-36511

 

Eclipse Resources Corporation

(Exact name of registrant as specified in its charter)

 

 

(814) 308-9754

(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 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 Exchange Act).    ☐  Yes    ☒  No

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2017, the last business day of the most recently completed second fiscal quarter, was approximately $248 million.

Number of shares of the registrant’s common stock outstanding at March 2, 2018: 301,770,671 shares.

Documents incorporated by reference: Portions of the registrant’s proxy statement for its 2018 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

 

 

 

i

---

 

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.

ii

---

 

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:

iii

---

 

iv

---

 

(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;

v

---

 

 

 

 

vi

---

 

 

Our Company

We are 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, 2017, we had assembled an acreage position approximating 203,000 net acres in Eastern Ohio.  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, “Eclipse,” “Eclipse Resources,” the “Company,” “we,” “our,” “us” and like terms refer collectively to Eclipse Resources Corporation and its consolidated subsidiaries.

Our Properties

As of December 31, 2017 , we had approximately 96,000 net acres in the Utica Shale fairway, which we refer to as the Utica Core Area and approximately 15,500 acres in our Marcellus Area.  We are the operator of approximately 93% of our proved reserves within the Utica Core Area and our Marcellus Area. Additionally, we own approximately 107,000 net acres (which are approximately 71% 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.

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, 2017, we had approximately 15,500 net acres 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.

Activity

Through December 31, 2017, we, or our operating partners, had commenced drilling 234 gross wells within the Utica Core Area and our Marcellus Area, which are summarized below:

 

 

1

---

 

As of December 31, 2017, our estimated proved reserves were 1,458.6 Bcfe, or 243.1 MMBoe, an increase of 211% from December 31, 2016 reserves of 469.4 Bcfe, or 78.2 MMBoe, based on reserve reports prepared by Netherland, Sewell & Associates, Inc., or NSAI, our independent petroleum engineers. As of December 31, 2017, our estimated proved reserves were approximately 75% natural gas, 17% NGLs and 8% oil, and approximately 31% were proved developed reserves. The following table provides information regarding our proved reserves as of December 31, 2017, 2016, and 2015:

 

 

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, 2017:

 

 

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.

 

2

---

 

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 Dominion Resources, Inc. and Caiman Energy II, LLC.  This gas-processing agreement does not require us to make minimum volume deliveries or shortfall payments.  Additionally, we have contracted with Eureka Midstream LLC (“Eureka Midstream”) for firm gathering services on a significant portion of our operated acreage in the Dry Gas area of the Utica Core Area.

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.

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

 

 

 

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.

3

---

 

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 January of 2018, we amended our firm gas gathering services agreement with Eureka Midstream to gather and compress a substantial portion of our operated production of Dry Gas through Eureka Midstream’s system. This new agreement replaces an existing agreement with Eureka Midstream that we had entered into in 2013. Under the new 20-year agreement, we will 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, which will be effective immediately. Through this agreement, we obtained access to additional downstream pipelines and markets connected to Eureka including the Rover Pipeline System accessing our new 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:

 

 

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. The Mariner East II Project will connect the NGLs resources in the Marcellus and Utica Shale to Sunoco’s existing infrastructure and international port at its Marcus Hook facility near Philadelphia. Mariner East II is expected to be operational in 2018. Under the agreement, we will have firm transportation, which increases during the term of the agreement, from between approximately 7,500 barrels to 14,000 barrels per day (67% propane and 33% butane). Through this agreement, we plan to 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 (“Marathon”) 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.

4

---

 

As of December 31, 2017, our natural gas firm transportation commitments through 2022 include:

 

 

The minimum demand fees related to these volume and firm transportation agreements that were in place as of December 31, 2017 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.

Recent Developments

Drilling Joint Venture

On December 22, 2017, we entered into definitive agreements with Sequel Energy Group LLC (“Sequel”) (an affiliate of GSO Capital Partners LP) to establish a drilling joint venture on our Utica Shale acreage in Guernsey and Monroe Counties in southeast Ohio.  We have committed funding from Sequel of up to $285 million to fund its proportionate share of two drilling programs comprising of 33 gross wells in aggregate, with the mutual option for an additional third well program consisting of approximately 16 wells (which would increase the committed funding).  We will retain 50% of our pre-carry working interest in the first program and 30% of our pre-carry working interest in the second program.  We have the option to adjust our pre-carry working interest in the third program, if applicable, to between 30% to 70%, which must be exercised prior to the commencement of the third program.  We will receive a 15% carried interest on drilling and completion capital expenditures incurred in each well program, which will be proportionately reduced based upon our retained pre-carry working interest in such well program, and a significant portion of Sequel’s working interest in each well program will revert to Eclipse once a certain return is realized by Sequel in each program.  We will be the operator of all wells drilled within each well program.  

5

---

 

Flat Castle Acquisition

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, wells and other oil and gas rights and interests covering approximately 44,500 net acres located in the counties of Tioga and Potter in the Commonwealth of Pennsylvania (such transaction, the “Flat Castle Acquisition”) from Travis Peak Resources, LLC.  The aggregate adjusted purchase price for the Flat Castle Acquisition was $92.2 million, which was paid entirely with approximately 37.8 million shares of the Company’s common stock.  The Flat Castle Acquisition includes one producing well, increases our drilling location count by approximately 87 net drilling locations ⁽¹⁾, and significantly expands our Utica Shale dry gas acreage.  In addition, on December 8, 2017, Eclipse Resources Midstream, LP, a wholly owned subsidiary of the Company (“Eclipse Midstream”), acquired the exclusive right and option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC, which owns midstream infrastructure with associated gathering rights on the acreage acquired in the Flat Castle Acquisition, from Cardinal Midstream II, LLC for an aggregate purchase price of $18.3 million in cash.  The option granted to Eclipse Midstream expires as of the close of business on June 30, 2018 if not exercised prior to such time.

 

Tax Reform

New tax legislation, commonly referred to as the Tax Cuts and Jobs Act, was enacted on December 22, 2017.  ASC 740, Accounting for Income Taxes, requires companies to recognize the effect of tax law changes in the period of enactment even though the effective date for most provisions is for tax years beginning after December 31, 2017.  Adjustments to our tax provision that were recorded in the three months ended December 31, 2017 principally relate to the reduction in the U.S. corporate income tax rate to 21%, which resulted in the Company recognizing a $142 million reduction of tax benefit to remeasure deferred tax assets that will reverse at the new 21% rate.  Other significant provisions that are not yet effective but may impact incomes taxes in future years include: the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income, a limitation on utilization of net operating losses generated after tax year 2017 to 80% of taxable income, the unlimited carryforward of net operating losses generated after tax year 2017, the repeal of the corporate Alternative Minimum Tax, temporary 100% expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation.  Currently, we do not anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to our ability to expense intangible drilling costs and the utilization of our net operating loss carryforwards.  Future interpretations relating to the recently enacted U.S. federal income tax legislation, which vary from our current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on this projection.

2018 Capital Budget

Our Board of Directors recently approved an initial capital budget for 2018 of between approximately $300 - $320 million, allocated approximately 84% for drilling and completions activities, 8% for midstream activities, 6% for land activities and 2% for other capital requirements. The 2018 capital budget is expected to be substantially funded through internally generated cash flows, the Company’s current cash balance, proceeds from our drilling joint venture, borrowings under the revolving credit facility and/or other debt and equity offerings.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Proved Reserves. Our historical proved reserve estimates were prepared by NSAI. 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. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of NSAI’s proved reserve reports as of December 31, 2017, December 31, 2016 and December 31, 2015 are attached hereto as exhibits.

6

---

 

We maintain an internal staff of engineers and geoscience professionals who work closely with NSAI 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 NSAI 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 NSAI, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Michael Lynch, our Vice President, Reservoir Engineering, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Lynch is an engineer with over 30 years of reservoir, completions and operations experience and our reservoir engineering staff has an average of approximately eight years of industry experience per person.

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:

The reserves estimates 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, 2017, December 31, 2016 and December 31, 2015 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;

7

---

 

(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, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

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, 2017, December 31, 2016 and December 31, 2015, based on the proved reserve reports prepared by NSAI, our independent petroleum engineers, 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 2017, 2016, and 2015. For oil and NGLs volumes, the average WTI spot price of $51.34 per barrel for December 31, 2017, $42.75 per barrel for December 31, 2016 and $50.28 per barrel for December 31, 2015, 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 $2.98 per MMBtu for December 31, 2017, $2.48 per MMBtu for December 31, 2016 and $2.59 per MMBtu for December 31, 2015 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, 2017, December 31, 2016 and December 31, 2015 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.

8

---

 

 

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 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, 2017, 2016, and 2015, 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, 2017, we increased proved reserves by 989.2 Bcfe compared to the year ended December 31, 2016, primarily through revisions, extensions and discoveries and acquisitions. This increase in proved reserves was comprised of 405.1 Bcfe of extensions and discoveries, 695.6 Bcfe of revisions, and 1.9 Bcfe of acquisitions. The increase was offset by 113.4 Bcfe of production.  The revisions consisted of positive revisions of 27.0 Bcfe due to technical adjustments and 668.6 Bcfe due to pricing and differential changes.

Future Net Cash Flows. At December 31, 2017, 2016, and 2015, the standardized measure of estimated future net cash flows after income taxes from our proved reserves was $729.7 million, $206.0 million and $212.9 million, respectively.  At December 31, 2017, 2016, and 2015, the PV-10 value of estimated future net cash flows before income taxes from our proved reserves was $729.7 million, $206.0 million and $212.9 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.

9

---

 

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, 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.  As of December 31, 2015, our proved undeveloped reserves were comprised of 453.9 MBbls of oil, 64.5 Bcf of natural gas and 513.0 MBbls of NGLs, for a total of 70.3 Bcfe.  PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes our changes in PUDs during 2015, 2016, and 2017 (in Bcfe):

 

 

10

---

 

During the year ended December 31, 2017, we converted approximately 90.0 Bcfe, or 52% of our proved undeveloped reserves as of December 31, 2016, to proved developed reserves at a capital cost of approximately $34 million.  Estimated future development costs relating to the development of our proved undeveloped reserves as of December 31, 2017 are approximately $835 million over the next five years.

Production and Price History

The following table sets forth information regarding net production of natural gas, NGLs and oil, and certain price and cost information for the periods indicated:

 

 

11

---

 

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2017 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

 

 

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms, although approximately 68% of our leases in the Utica Core Area have a 3-5 year extension at our option. The following table sets forth the total gross and net undeveloped acres as of December 31, 2017 that will expire over the next five years unless operations have commenced on the leasehold acreage or lands pooled therewith have been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities:

 

 

In 2018, we expect to incur approximately $28 million related to delay rentals and lease extensions related to acreage that would otherwise expire during 2018.  

12

---

 

Drilling Results

The following table sets forth information with respect to the number of wells completed during the years indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.