10-K 1 ecr-10k_20171231.htm 10-K ecr-10k_20171231.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

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

For the fiscal year ended December 31, 2017

or

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

For the transition period from                      to                     

Commission File Number: 001-36511

 

Eclipse Resources Corporation

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

46-4812998

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

 

2121 Old Gatesburg Rd, Suite 110
State College, PA

 

16803

(Address of principal executive offices)

 

(Zip code)

(814) 308-9754

(Registrant’s telephone number, including area code)

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

 

Title of Each Class

 

Name of Each Exchange on which Registered

Common Stock, Par Value $0.01 Per Share

 

New York Stock Exchange

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

 

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

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

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

Indicate by check mark whether the registrant has submitted electronically 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.

 

Large accelerated filer

 

  

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

 

 

 

 

 

 

 

 

 

 

 

Emerging growth company

 

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

 

 

  

 

 

Page

Cautionary Statement Regarding Forward-Looking Statements

 

 

ii

 

 

 

 

Glossary of Oil and Natural Gas Terms

  

  

iii

 

 

 

 

 

 

PART I

  

 

 

 

 

Items 1 and 2  

  

Business and Properties

 

 

1

Item 1A

  

Risk Factors

 

 

22

Item 1B

  

Unresolved Staff Comments

 

 

49

Item 3

  

Legal Proceedings

 

 

49

Item 4

  

Mine Safety Disclosures

 

 

49

 

 

 

 

 

 

PART II

  

 

 

 

 

Item 5

  

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

 

 

50

Item 6

  

Selected Financial Data

 

 

51

Item 7

  

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

 

 

54

Item 7A

  

Quantitative and Qualitative Disclosures About Market Risk

 

 

80

Item 8

  

Financial Statements and Supplementary Data

 

 

81

Item 9

  

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

 

81

Item 9A

  

Controls and Procedures

 

 

81

Item 9B

  

Other Information

 

 

82

 

 

 

 

 

 

PART III

  

 

 

 

 

Item 10

  

Directors, Executive Officers and Corporate Governance

 

 

83

Item 11

  

Executive Compensation

 

 

83

Item 12

  

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

 

 

83

Item 13

  

Certain Relationships and Related Transactions, and Director Independence

 

 

83

Item 14

  

Principal Accounting Fees and Services

 

 

83

 

 

 

 

 

 

PART IV

  

 

 

 

 

Item 15

  

Exhibits, Financial Statement Schedules

 

 

83

Item 16

 

Form 10-K Summary

 

 

87

 

 

 

 

SIGNATURES

 

 

88

 

 

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:

 

realized prices for natural gas, natural gas liquids (“NGLs”) and oil and the volatility of those prices;

 

write-downs of our natural gas and oil asset values due to declines in commodity prices;

 

our business strategy;

 

our reserves;

 

general economic conditions;

 

our financial strategy, liquidity and capital required for developing our properties and the timing related thereto;

 

the timing and amount of our future production of natural gas, NGLs and oil;

 

our hedging strategy and results;

 

future drilling plans;

 

competition and government regulations, including those related to hydraulic fracturing;

 

the anticipated benefits under our commercial agreements;

 

marketing of natural gas, NGLs and oil;

 

leasehold and business acquisitions and joint ventures;

 

leasehold terms expiring before production can be established and our costs to extend such terms;

 

the costs, terms and availability of gathering, processing, fractionation and other midstream services;

 

credit markets;

 

uncertainty regarding our future operating results, including initial production rates and liquids yields in our type curve areas; and

 

plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

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:

 

“Bbl” refers to a standard barrel containing 42 U.S. gallons;

 

“Bbls/d” refers to Bbls per day;

 

“Bcfe” refers to one billion cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids;

 

“Boe” refers to one barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil;

 

“Btu” refers to one British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit;

 

“Completion” refers to the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency;

 

“Condensate” or “Condensate Window” refers to the area in which we generally expect Utica Shale wells to produce natural gas having a heat content greater than 1,210 Btu, with an initial condensate yield of approximately 60 to 300 barrels per MMcf of natural gas produced;

 

“Developed acreage” refers to the number of acres that are allocated or assignable to productive wells or wells capable of production;

 

“Differential” refers to an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas;

 

“Dry Gas” refers to the area in which we generally expect Utica Shale wells to produce natural gas having a heat content between 1,010 Btu and 1,150 Btu with no initial condensate yield;

 

“Dth” refers to a thermal unit, and is equal to one million Btus;

 

“Dry hole” or “dry well” refers to 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;

iii


 

 

“Exploration” refers to a development or other project that may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects;

 

“Field” refers to 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” refers to a layer of rock that has distinct characteristics that differs from nearby rock;

 

“Gross acres” or “gross wells” refers to the total acres or wells, as the case may be, in which a working interest is owned;

 

“Horizontal drilling” refers to 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;

 

“Identified drilling locations” refers to total gross (net) resource play 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 and oil prices, costs, drilling results and other factors;

 

“Marcellus Condensate” or “Marcellus Area” refers to the area in which we generally expect Marcellus Shale wells to produce a natural gas having a heat content of approximately 1,300 Btu, with an initial condensate yield of approximately 60-140 barrels per MMcf of natural gas produced;

 

“MBbl” refers to one thousand barrels;

 

“MBoe” refers to one thousand Boe;

 

“Mcf” refers to one thousand cubic feet;

 

“Mcfe” refers to one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs;

 

“Mcf/d” refers to Mcfs per day;

 

“MMBbls” refers to one million barrels;

 

“MMBoe” refers to one million Boe;

 

“MMBtu” refers to one million British thermal units;

 

“MMcf” refers to one million cubic feet;

 

“MMcfe” refers to one million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs;

 

“Net acres” refers to the amount of leased real estate that a petroleum and/or natural gas company has a true working interest in. Net acres express actual percentage interest when a company shares its working interest with another company; the total acreage under lease by a company is referred to as gross acres. Net acres account for the Company’s percentage interest, multiplied by the gross acreage. If a company holds the entire working interest, its net acreage and gross acreage will be the same;

 

“Net production” refers to production that is owned by us less royalties and production due others;

 

“NGLs” refers to natural gas liquids, which are hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline;

 

“NYMEX” refers to the New York Mercantile Exchange;

 

“Operator” refers to the individual or company responsible for the exploration and/or production of an oil or natural gas well or lease;

 

“Plugging” refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface;

iv


 

 

“Productive well” refers to a well that is expected to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceeds production expenses and taxes;

 

“Prospect” refers to a geological feature mapped as a location or probable location of a commercial oil and/ or gas accumulation. A prospect is defined as a result of geophysical and geological studies allowing the identification and quantification of uncertainties, probabilities of success, estimates of potential resources and economic viability;

 

“Proved undeveloped reserves” refers to 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;

(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;

 

“PV-10” refers to, when used with respect to natural gas and oil reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using sales prices used in estimating proved oil and gas reserves and costs in effect at the determination date, 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;

 

“Realized price” refers to the cash market price less all expected quality, transportation and demand adjustments;

 

“Reservoir” refers to 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;

 

“Rich Gas” or “Rich Gas Window” refers to the area in which we generally expect Utica Shale wells to produce natural gas having a heat content between 1,150 Btu and 1,210 Btu, with an initial condensate yield of approximately 0 to 60 barrels per MMcf of natural gas produced;

 

“SEC” refers to the United States Securities and Exchange Commission;

 

“Spacing” refers to the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies;

 

“Spot market price” refers to the cash market price without reduction for expected quality, transportation and demand adjustments;

 

“Standardized measure” refers to discounted future net cash flows estimated by applying sales prices used in estimating proved oil and gas reserves 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;

v


 

 

“Undeveloped acreage” refers to lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves;

 

“Unit” refers to the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement;

 

“Working interest” refers to the right granted to the lessee of a property to explore for and to produce and own oil, 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” refers to West Texas Intermediate; and

 

The terms “development project,” “development well,” “exploratory well,” “proved developed reserves,” “proved reserves” and “reserves” are defined by the SEC.

 

 

 

vi


 

 

Items 1 and 2.

Business and Properties

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:

 

 

 

Operated Gross Wells

 

 

Non-Operated Gross Wells

 

Type Curve Area

 

Producing

to Sales(1)

 

 

Awaiting

Turn to

Sales

 

 

Awaiting

Completion/

Completing

 

 

Drilling

 

 

Producing

to Sales

 

 

Awaiting

Turn to

Sales

 

 

Awaiting

Completion/

Completing

 

 

Drilling

 

Dry Gas

 

 

38

 

 

 

 

 

 

2

 

 

 

2

 

 

 

30

 

 

 

 

 

 

 

 

 

 

Rich Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

22

 

 

 

 

 

 

 

 

 

 

Condensate

 

 

63

 

 

 

 

 

 

12

 

 

 

5

 

 

 

55

 

 

 

 

 

 

 

 

 

 

Total Utica Core Area

 

 

101

 

 

 

 

 

 

14

 

 

 

7

 

 

 

107

 

 

 

 

 

 

 

 

 

 

Marcellus Condensate(1)

 

 

1

 

 

 

2

 

 

 

 

 

 

 

 

 

1

 

 

 

 

 

 

 

 

 

 

Marcellus Area

 

 

1

 

 

 

2

 

 

 

 

 

 

 

 

 

1

 

 

 

 

 

 

 

 

 

 

Total

 

 

102

 

 

 

2

 

 

 

14

 

 

 

7

 

 

 

108

 

 

 

 

 

 

 

 

 

 

 

1


 

(1)

Excludes one Marcellus producing well outside our defined type curve area.

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:

 

 

 

Estimated Total Proved Reserves

 

 

 

Natural Gas

(Bcf)

 

 

Oil

(MMBbls)

 

 

NGLs

(MMBbls)

 

 

Total

(Bcfe)

 

 

Total

(MMBoe)

 

 

%

Liquids

 

 

%

Developed

 

December 31, 2015

 

 

274.1

 

 

 

4.7

 

 

 

7.8

 

 

 

348.8

 

 

 

58.1

 

 

 

21.4

%

 

 

79.8

%

December 31, 2016

 

 

386.4

 

 

 

5.2

 

 

 

8.7

 

 

 

469.4

 

 

 

78.2

 

 

 

17.7

%

 

 

63.4

%

December 31, 2017

 

 

1,090.1

 

 

 

19.5

 

 

 

41.9

 

 

 

1,458.6

 

 

 

243.1

 

 

 

25.3

%

 

 

31.3

%

 

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:

 

 

 

As of December 31, 2017

 

 

 

Approximate Net Acreage

 

 

Net Producing Locations

 

 

Net Undeveloped Locations(1)

 

Dry Gas

 

 

48,051

 

 

 

37.4

 

 

 

98.2

 

Rich Gas

 

 

8,046

 

 

 

2.8

 

 

 

18.3

 

Condensate

 

 

39,672

 

 

 

66.7

 

 

 

93.8

 

Marcellus Condensate(2)

 

 

15,456

 

 

 

0.6

 

 

 

78.1

 

Total

 

 

111,225

 

 

 

107.5

 

 

 

288.4

 

 

(1)

Based on our reserve report as of December 31, 2017, we had 85 net drilling locations associated with proved undeveloped reserves and 13 net locations associated with proved developed non-producing reserves.  Please see “—Determination of Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors.  Our drilling locations are also scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our drilling locations.  Please see “Item 1A. Risk Factors” for more information.

(2)

Excludes one Marcellus producing well outside our defined type curve area.

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.

 

 

Undeveloped Net Dry Gas Locations – We assume these locations have 16,000 foot laterals and 1,000 foot spacing between wells which yields approximately 374 acre spacing.  As of December 31, 2017, we had approximately 48,051 net acres in the Dry Gas area, which, after removing net producing locations, results in 98.2 net undeveloped locations.

 

Undeveloped Net Rich Gas Locations – We assume these locations have 16,000 foot laterals and 1,000 foot spacing between wells which yields approximately 374 acre spacing.  As of December 31, 2017, we had approximately 8,046 net acres in the Rich Gas area, which, after removing net producing locations, results in 18.3 net undeveloped locations.

2


 

 

Undeveloped Net Condensate Locations – We assume these locations have 16,000 foot laterals and 750 foot spacing between wells which yields approximately 281 acre spacing.  As of December 31, 2017, we had approximately 39,672 net acres in the Condensate area, which, after removing net producing locations, results in 93.8 net undeveloped locations.

 

Undeveloped Net Marcellus Condensate Locations – We assume these locations have 10,000 foot laterals and 750 foot spacing between wells which yields approximately 177 acre spacing.  As of December 31, 2017, we had approximately 15,456 net acres in the Marcellus Condensate area, which, after removing net producing locations, results in 78.1 net undeveloped locations.

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:

 

Firm Sales & Transportation

 

Start Date

 

Term

 

Volume (Dth/d)

 

 

Market

Columbia Gas Transmission

   ("TCO")

 

October 2016

 

15 years

 

 

205,000

 

 

TCO Pool

Rover Pipeline System(1)

 

May 2018

 

15 years

 

 

100,000

 

 

Gulf Coast

Rover Pipeline System(1)

 

May 2018

 

15 years

 

 

50,000

 

 

Canada

 

(1)

Anticipated start date based on public statements from Energy Transfer Partners.

 

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:

 

Term

 

Natural Gas

(Mcf/d)

 

 

Term

 

Oil

(Bbl/d)

 

 

Term

 

Water

(Bbl/d)

 

January 2018 – May 2018

 

 

60,800

 

 

January 2018 – March 2018

 

 

3,000

 

 

January 2018 – May 2019

 

 

5,000

 

June 2018 – June 2018

 

 

89,300

 

 

April 2018 – July 2018

 

 

6,000

 

 

 

 

 

 

 

July 2018 – December 2018

 

 

117,800

 

 

August 2018 – June 2020

 

 

10,052

 

 

 

 

 

 

 

January 2019 – December 2019

 

 

92,400

 

 

 

 

 

 

 

 

 

 

 

 

 

January 2020 – June 2020

 

 

82,300

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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:

 

Term

 

Natural Gas

(Mcf/d)

 

January 2018 – December 2018

 

 

180,000

 

January 2019 – December 2019

 

 

212,500

 

January 2020 – December 2020

 

 

310,000

 

January 2021 – December 2021

 

 

355,000

 

January 2022 – December 2022

 

 

400,000

 

 

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:

 

Year Ended December 31,

 

Volume of

Natural Gas

(MMBtu/d)

 

 

Volume of

NGLs (Bbls/d)

 

2018

 

 

318,014

 

 

 

5,590

 

2019

 

 

355,000

 

 

 

10,739

 

2020

 

 

355,000

 

 

 

10,724

 

2021

 

 

355,000

 

 

 

9,310

 

2022

 

 

355,000

 

 

 

8,115

 

 

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.

 

(1)

Please see “—Determination of Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified.

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:

 

review and verification of historical production data, which data is based on actual production as reported by us;

 

preparation of reserve estimates by Mr. Lynch or under his direct supervision;

 

review by Mr. Lynch of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions by our Chief Executive Officer, Chief Operating Officer, Chief Financial Officer and Executive Vice President, Corporate Development and Geosciences;

 

direct reporting responsibilities by Mr. Lynch to our Chief Operating Officer; and

 

verification of property ownership by our land department.

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.

 

 

2017

 

 

2016

 

 

2015

 

Proved Developed Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

334.6

 

 

 

226.1

 

 

 

209.5

 

NGLs (MBbls)

 

 

13,782.9

 

 

 

7,520.0

 

 

 

7,245.7

 

Oil (MBbls)

 

 

6,449.6

 

 

 

4,439.5

 

 

 

4,239.2

 

Combined (Bcfe)

 

 

456.0

 

 

 

297.8

 

 

 

278.4

 

Proved Undeveloped Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

755.5

 

 

 

160.4

 

 

 

64.5

 

NGLs (MBbls)

 

 

28,147.7

 

 

 

1,155.5

 

 

 

513.0

 

Oil (MBbls)

 

 

13,031.2

 

 

 

718.1

 

 

 

453.9

 

Combined (Bcfe)

 

 

1,002.6

 

 

 

171.6

 

 

 

70.3

 

Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

1,090.1

 

 

 

386.4

 

 

 

274.1

 

NGLs (MBbls)

 

 

41,930.6

 

 

 

8,675.5

 

 

 

7,758.7

 

Oil (MBbls)

 

 

19,480.8

 

 

 

5,157.7

 

 

 

4,693.1

 

Combined (Bcfe)

 

 

1,458.6

 

 

 

469.4

 

 

 

348.8

 

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.

 

 

 

Natural Gas

(Bcf)

 

 

NGLs

(MBbls)

 

 

Oil

(MBbls)

 

 

Total

(Bcfe)

 

Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

 

 

256.3

 

 

 

10,879.0

 

 

 

5,697.4

 

 

 

355.8

 

Reserve revisions

 

 

(115.3

)

 

 

(4,705.7

)

 

 

(1,550.1

)

 

 

(152.9

)

Extensions and discoveries

 

 

182.6

 

 

 

4,035.7

 

 

 

2,496.3

 

 

 

221.7

 

Production

 

 

(49.5

)

 

 

(2,450.3

)

 

 

(1,950.5

)

 

 

(75.8

)

December 31, 2015

 

 

274.1

 

 

 

7,758.7

 

 

 

4,693.1

 

 

 

348.8

 

Reserve revisions

 

 

(0.1

)

 

 

1,273.7

 

 

 

1,196.8

 

 

 

14.8

 

Extensions and discoveries

 

 

175.4

 

 

 

2,156.0

 

 

 

1,300.2

 

 

 

196.1

 

Acquisitions

 

 

3.8

 

 

 

24.8

 

 

 

15.1

 

 

 

4.1

 

Divestitures

 

 

(5.9

)

 

 

(91.5

)

 

 

(703.7

)

 

 

(10.7

)

Production

 

 

(60.9

)

 

 

(2,446.2

)

 

 

(1,343.8

)

 

 

(83.7

)

December 31, 2016

 

 

386.4

 

 

 

8,675.5

 

 

 

5,157.7

 

 

 

469.4

 

Reserve revisions

 

 

515.1

 

 

 

20,327.3

 

 

 

9,746.8

 

 

 

695.6

 

Extensions and discoveries

 

 

274.4

 

 

 

15,598.8

 

 

 

6,192.9

 

 

 

405.1

 

Acquisitions

 

 

1.6

 

 

 

42.6

 

 

 

5.8

 

 

 

1.9

 

Production

 

 

(87.4

)

 

 

(2,713.6

)

 

 

(1,622.4

)

 

 

(113.4

)

December 31,  2017

 

 

1,090.1

 

 

 

41,930.6

 

 

 

19,480.8

 

 

 

1,458.6

 

 

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):

 

 

 

Year Ended December 31,

 

(In thousands)

 

2017

 

 

2016

 

 

2015

 

Future net cash flows

 

$

1,538,529

 

 

$

300,430

 

 

$

300,059

 

Present value of future net cash flows:

 

 

 

 

 

 

 

 

 

 

 

 

Before income tax (PV-10)

 

$

729,686

 

 

$

205,981

 

 

$

212,865

 

Income taxes

 

 

 

 

 

 

 

 

 

After income tax (standardized measure)

 

$

729,686

 

 

$

205,981

 

 

$

212,865

 

 

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):

 

Balance, December 31, 2014

 

 

159.0

 

Reserve revisions(1)

 

 

(134.5

)

Extensions and discoveries

 

 

55.2

 

Transfers to proved developed

 

 

(9.4

)

Balance, December 31, 2015

 

 

70.3

 

Reserve revisions(2)

 

 

(14.2

)

Acquisitions

 

 

3.6

 

Extensions and discoveries

 

 

111.9

 

Balance, December 31, 2016

 

 

171.6

 

Reserve revisions(3)

 

 

528.5

 

Acquisitions

 

 

1.3

 

Extensions and discoveries

 

 

391.2

 

Transfers to proved developed

 

 

(90.0

)

Balance, December 31, 2017

 

 

1,002.6

 

 

(1)

Revisions to previous estimates are comprised of 19.6 Bcfe of positive technical revisions, 0.3 Bcfe positive revision related to differentials, 0.7 Bcfe negative revision due to expense assumptions, 121.8 Bcfe negative price revisions, and 31.9 Bcfe negative revisions due to reclassification of wells to unproved because of a slower pace of development beyond the five-year development horizon. The positive technical revisions were primarily due to improved well performance from offsetting producing wells, which we believe were mainly due to improvements in well completion design and pressure managed production techniques.

10


 

(2)

Revisions to previous estimates are comprised of 16.6 Bcfe of positive technical revisions primarily due to well performance, 20.2 Bcfe of negative revisions related to pricing and differential changes, and negative revisions of 10.6 Bcfe due to economic locations that the Company no longer expects to develop within five years of initial classification.

(3)

Revisions to previous estimates are comprised of 91.1 Bcfe of negative technical revisions primarily due to well performance, 620.6 Bcfe of positive revisions related to pricing and differential changes, and negative revisions of 1.0 Bcfe due to expense assumption changes.

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:

 

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

Total production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

87,404.2

 

 

 

60,921.9

 

 

 

49,477.6

 

NGLs (MBbls)

 

 

2,713.7

 

 

 

2,446.2

 

 

 

2,450.3

 

Oil (MBbls)

 

 

1,622.4

 

 

 

1,343.8

 

 

 

1,950.5

 

Combined (MMcfe)

 

 

113,420.8

 

 

 

83,661.9

 

 

 

75,882.4

 

Average daily production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf/d)

 

 

239,464

 

 

 

166,453

 

 

 

135,555

 

NGLs (Bbls/d)

 

 

7,435

 

 

 

6,684

 

 

 

6,713

 

Oil (Bbls/d)

 

 

4,445

 

 

 

3,672

 

 

 

5,344

 

Combined (Mcfe/d)

 

 

310,744

 

 

 

228,589

 

 

 

207,897

 

Average Realized Price (including cash settled

   derivatives and firm transportation):

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.34

 

 

$

2.19

 

 

$

2.95

 

NGLs ($/Bbl)

 

 

21.96

 

 

 

15.55

 

 

 

12.32

 

Oil ($/Bbl)

 

 

46.14

 

 

 

44.66

 

 

 

38.38

 

Combined ($/Mcfe)

 

$

2.99

 

 

$

2.76

 

 

$

3.38

 

Expenses (per Mcfe):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

0.18

 

 

$

0.11

 

 

$

0.18

 

Transportation, gathering and compression

 

 

1.10

 

 

 

1.30

 

 

 

1.13

 

Production, severance and ad valorem taxes

 

 

0.07

 

 

 

0.09

 

 

 

0.05

 

Depletion, depreciation and amortization

 

 

1.05

 

 

 

1.11

 

 

 

3.23

 

General and administrative

 

 

0.39

 

 

 

0.47

 

 

 

0.61

 

 

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.

 

 

 

Developed Acreage

 

 

Undeveloped Acreage

 

 

Total Acreage

 

Area

 

Gross

 

 

Net(1)

 

 

Gross

 

 

Net(1)

 

 

Gross

 

 

Net(1)

 

Ohio

 

 

175,878

 

 

 

137,677

 

 

 

94,134

 

 

 

64,954

 

 

 

270,012

 

 

 

202,631

 

Total

 

 

175,878

 

 

 

137,677

 

 

 

94,134

 

 

 

64,954

 

 

 

270,012

 

 

 

202,631

 

 

(1)

Fossil Creek owns a right to participate for a 12.5% working interest in approximately 2,812 gross acres within our area of mutual interest with Antero Resources. In calculating our net acreage, we have assumed that Fossil Creek will elect to participate in all wells in which they have a right to participate for their full interest and have deducted this 12.5% working interest from our net acreage where applicable.

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:

 

Year Ending December 31,

 

Gross Acres

 

 

Net Acres

 

2018

 

 

33,069

 

 

 

21,473

 

2019

 

 

12,339

 

 

 

9,760

 

2020

 

 

3,320

 

 

 

2,657

 

2021

 

 

14,570

 

 

 

11,919

 

2022 and beyond

 

 

14,657

 

 

 

11,685

 

 

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.

 

 

 

2017

 

 

2016

 

 

2015

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

25

 

 

 

22.2

 

 

 

22

 

 

 

18.1

 

 

 

76

 

 

 

33.9

 

Dry holes

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry holes

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

25

 

 

 

22.2

 

 

 

22

 

 

 

18.1

 

 

 

76

 

 

 

33.9

 

Dry holes