8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 28, 2018

Eclipse Resources Corporation

(Exact name of Registrant as Specified in Its Charter)

Delaware	001-36511	46-4812998
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(IRS Employer Identification No.)
2121 Old Gatesburg Road, Suite 110 State College, Pennsylvania		16803
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: (814) 308-9754

Not Applicable

(Former Name or Former Address, if Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instructions A.2. below):

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

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. ☒

Item 2.02Results of Operations and Financial Condition.

On February 28, 2018, Eclipse Resources Corporation (the “Company”) issued a press release, a copy of which is attached hereto as Exhibit 99.1, announcing its financial and operational results for the fourth quarter 2017 and the year ended December 31, 2017 and updated first quarter 2018 production guidance.

Item 7.01Regulation FD Disclosure.

On February 28, 2018, the Company posted an updated corporate presentation in the Investor Center section of the Company’s website at: www.eclipseresources.com.

The information in this Current Report, including Exhibit 99.1, is being furnished pursuant to Items 2.02 and 7.01 of Form 8-K and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act unless specifically identified therein as being incorporated therein by reference.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit Number	Description
99.1	Press Release, dated February 28, 2018.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ECLIPSE RESOURCES CORPORATION
Date: February 28, 2018	By:	/s/ Christopher K. Hulburt
	Name:	Christopher K. Hulburt
	Title:	Executive Vice President, Secretary and General Counsel

EX-99.1

Exhibit 99.1

Eclipse Resources Corporation Announces Fourth Quarter and Full Year 2017 Results and an Increase in First Quarter 2018 Production Guidance

STATE COLLEGE, PA- February 28, 2018- (BUSINESS WIRE) - Eclipse Resources Corporation (NYSE:ECR) (the “Company” or “Eclipse Resources”) today announced its fourth quarter 2017 and full year 2017 financial and operational results, along with an increase in first quarter 2018 production guidance. In conjunction with this release, the Company has posted an updated investor presentation to its website at www.eclipseresources.com.

Fourth Quarter 2017 Highlights:

• Average net daily production was 311.7 MMcfe per day, consisting of 74% natural gas and 26% liquids.

• Realized an average natural gas price, before the impact of cash settled derivatives and firm transportation expenses, of $2.55 per Mcf, a $0.38 per Mcf discount to the average monthly NYMEX settled natural gas price during the quarter.

• Realized an average oil price, before the impact of cash settled derivatives, of $49.61 per barrel, a $5.66 per barrel discount to the average WTI oil price during the quarter.

• Realized an average natural gas liquids (“NGL”) price, before the impact of cash settled derivatives, of $31.16 per barrel, or approximately 56% of the average WTI oil price during the quarter.

• Per unit cash production costs (including lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.49 per Mcfe, including $0.34 per Mcfe in firm transportation expenses.

• Net loss for the fourth quarter of 2017 was $13.1 million; and Adjusted EBITDAX¹ for the fourth quarter of 2017 was $53.5 million.

Full Year 2017 Highlights:

• Average net daily production was 310.7 MMcfe per day, consisting of 77% natural gas and 23% liquids.

• Realized an average natural gas price, before the impact of cash settled derivatives and firm transportation expenses, of $2.76 per Mcf, a $0.35 per Mcf discount to the average monthly NYMEX settled natural gas price during the year.

• Realized an average oil price, before the impact of cash settled derivatives, of $46.04 per barrel, a $4.76 per barrel discount to the average WTI oil price during the year.

• Realized an average natural gas liquids price, before the impact of cash settled derivatives, of $23.62 per barrel, or approximately 46% of the average WTI oil price during the year.

• Per unit cash production costs (including lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.35 per Mcfe, including $0.34 per Mcfe in firm transportation expenses.

• Net income for the year was $8.5 million; and Adjusted EBITDAX¹ for the year was $189.1 million.

• Capital expenditures for fiscal 2017 were $314.1 million, including $246.4 million for drilling and completions, $10.5 million for midstream expenditures, $55.9 million for land-related expenditures, and $1.3 million for corporate-related expenditures

• Proved reserves grew 211% over the previous year to approximately 1.46 Tcfe at SEC pricing and by 19% to approximately 1.46 Tcfe based on forward NYMEX strip pricing; Finding and Development costs, including revisions, for fiscal 2017 decreased to $0.26 per Mcfe, utilizing drilling and completion costs, and $0.31 per Mcfe including all capital uses.

¹ Non-GAAP measure. See reconciliation for details

Benjamin W. Hulburt, Chairman, President and CEO, commented on the Company’s fourth quarter and full year 2017 results, “During 2017, Eclipse Resources had substantial operational and strategic success leading to an expansion in our asset base, a substantial increase in cash flow and the addition of a strategic joint venture partner.  Through these actions, we increased our acreage footprint by 57%, generated 85% year over year growth in EBITDAX, to a company record of approximately $189 million and commenced a $290 million joint venture process.  

As we highlighted during our analyst day, the strategic shift toward increasing activity in our liquids area has allowed us to capture the benefit of the recovery in oil prices and to exceed our full year 2017 guidance for both oil and NGL production. In 2018, the Company plans to turn 13 gross (9 net) Utica Condensate wells with an average lateral length of 16,325 feet to sales, resulting in over 40% oil production growth year over year. The first of which was very recently put to sales with an initial production rate of approximately 2,000 BOE per day consisting of 60% in total liquids, including approximately 735 barrels of oil, from a well with a completed lateral length of 15,600 feet.  As the well is continuing to unload water and undergoing our managed flowback procedure we expect the well’s production to continue to increase by approximately 15-20% before hitting peak production over the next two weeks.  We expect to put the two remaining wells on the pad with similar lateral lengths to sales over the course of the coming week.  In addition, the Company has recently turned to sales two Marcellus Condensate wells with initial production characteristics exceeding expectations on Mcfe basis, and we will continue to evaluate the performance of these wells.

As 2018 continues to unfold, we will focus on corporate level returns and seek to improve these returns by focusing on optimization of our drilling and completions approach on a pad by pad and well by well basis.  This approach will seek to vary items including proppant concentrations, stage spacing, cluster spacing, lateral length, intra-lateral spacing, wells per pad, first well spud to pad turn to sales cycle time, and most importantly the interrelationship between each of these variables as a means of maximizing returns on each well we drill rather than trying to maximize production or EURs at any cost.  At the corporate level we then focus on full cycle returns which incorporate land, G&A, and hedges to ensure we are exceeding our weighted average cost of capital.  We have tied our compensation structure to this approach as well which requires a frequent “lookback” on actual results to calculate our full cycle internal rate of return on every well using actual timing of capital and turn to sales, drilling and completion costs, cash flows and incorporating our best estimate of forward cash flows at current forward strip prices.  We will also continue to produce our wells in a way that maximizes rate while maintaining the fracture network to accelerate cash flows up to the point where we believe we would begin to impact well performance.

During 2018, we plan to drill 33 gross wells with an average lateral length of approximately 16,800 feet, 73% of which are expected to be “Super-Laterals” with lateral extensions exceeding 15,000 feet. This represents a 24% increase in average lateral footage per well over 2017 and remains well above any of our peers. While leading the industry on lateral lengths should allow us to continue to lower our cost per foot of lateral, we have also taken significant steps to manage our well costs through innovation, including reduced plug drill out times, expanding the use of a bi-fuel fleet, the continued evolution of engineered completions and the optimization of proppant loading.

Despite a significant amount of volatility during the fourth quarter of 2017 in natural gas prices, we have again been able to deliver a strong natural gas realized price, as recent firm transportation projects have created incremental unutilized capacity and new buyers needing to fill this capacity. We have also taken advantage of this volatility by adding to our hedge portfolio, with the goal of retaining upside participation if the natural gas price increases. Lastly, I am extremely pleased with our team’s continued ability to find creative solutions to build our business, from the execution of our previously-announced joint venture agreement with Sequel Energy to our accretive acquisition of the Flat Castle acreage, which marks another year of accomplishments that we believe have put us on a path for a successful future.”

Operational Discussion

The Company’s production for the three and twelve months ended December 31, 2017 and 2016 is set forth in the following table:

	Three Months Ended December 31,				Year Ended December 31,
	2017		2016		2017		2016
Production:
Natural gas (MMcf)		21,178.5		16,563.9		87,404.2		60,921.9
NGLs (Mbbls)		711.0		721.1		2,713.7		2,446.2
Oil (Mbbls)		539.2		433.4		1,622.4		1,343.8
Total (MMcfe)		28,679.7		23,490.9		113,420.8		83,661.9
Average daily production volume:

Natural gas (Mcf/d)	230,201	180,042	239,464	166,453
NGLs (Bbls/d)	7,728	7,838	7,435	6,684
Oil (Bbls/d)	5,861	4,711	4,445	3,672
Total (MMcfe/d)	311.7	255.3	310.7	228.6

Market Conditions

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists average daily, high, low and average monthly settled NYMEX Henry Hub prices for natural gas and average daily, high and low NYMEX WTI prices for oil for the three and twelve months ended December 31, 2017 and 2016:

	Year Ended December 31,
	2017		2016		2015
NYMEX Henry Hub High ($/MMBtu)	$	3.71	$	3.80	$	3.32
NYMEX Henry Hub Low ($/MMBtu)		2.44		1.49		1.63
Average Daily NYMEX Henry Hub ($/MMBtu)		2.99		2.52		2.57
Average Monthly Settled NYMEX Henry Hub    ($/MMBtu)		3.11		2.46		2.66
NYMEX WTI High ($/Bbl)	$	60.46	$	54.01	$	61.36
NYMEX WTI Low ($/Bbl)		42.48		26.19		34.55
Average Daily NYMEX WTI ($/Bbl)		50.80		43.29		49.33

Financial Discussion

Revenue for the fourth quarter of 2017 totaled $104.1 million, compared to $83.9 million for the fourth quarter of 2016.  Adjusted Revenue², which includes the impact of cash settled derivatives and excludes brokered natural gas and marketing revenue, totaled $105.8 million for the fourth quarter of 2017 compared to $85.1 million for the fourth quarter of 2016.  Net Loss for the fourth quarter of 2017 was $13.1 million, or $0.05 per share compared to $62.1 million or $0.24 per share for the fourth quarter of 2016. Adjusted Net Income² for the fourth quarter of 2017 was $5.2 million, or $0.02 per share, compared to an Adjusted Net Loss $4.8 million, or $0.02 per share for the fourth quarter of 2016. Adjusted EBITDAX² was $53.5 million for the fourth quarter of 2017 compared to $42.2 million for the fourth quarter of 2016.

Revenue for the year ended December 31, 2017 totaled $383.7 million, compared to $235.0 million for the year ended December 31, 2016.  Adjusted Revenue², which includes the impact of cash settled derivatives and excludes brokered natural gas and marketing revenue, totaled $378.0 million for the year ended December 31, 2017 compared to $261.7 million for the year ended December 31, 2016.  Net Income for the year ended December 31, 2017 was $8.5 million, or $0.03 per share compared to a Net Loss of $206.7 million or $0.86 per share for the year ended December 31, 2016.  Adjusted Net Income² for the year ended December 31, 2017 was $1.5 million, or $0.01 per share, compared to an Adjusted Net Loss $64.5 million, or $0.27 per share for the year ended December 31, 2016.  Adjusted EBITDAX² was $189.1 million for the year ended December 31, 2017 compared to $102.1 million for the year ended December 31, 2016.

² Adjusted Revenue, Adjusted Net Income (Loss) and Adjusted EBITDAX are non-GAAP financial measures. Tables reconciling Adjusted Revenue, Adjusted Net Income (Loss) and Adjusted EBITDAX to the most directly comparable GAAP measures can be found at the end of the financial statements included in this press release.

Average realized price calculations for the three months and years ended December 31, 2017 and 2016 are set forth in the table below:

	Three Months Ended December 31,				Year Ended December 31,
	2017		2016		2017		2016
Average realized price (excluding cash settled derivatives    and firm transportation)
Natural gas ($/Mcf)	$	2.55	$	2.88	$	2.76	$	2.21
NGLs ($/Bbl)		31.16		21.22		23.62		15.62
Oil ($/Bbl)		49.61		44.51		46.04		37.35
Total average prices ($/Mcfe)		3.59		3.50		3.35		2.67
Average realized price (including cash settled derivatives,    excluding firm transportation)
Natural gas ($/Mcf)	$	2.81	$	3.00	$	2.79	$	2.69
NGLs ($/Bbl)		27.52		20.78		21.96		15.55
Oil ($/Bbl)		49.61		46.97		46.14		44.66
Total average prices ($/Mcfe)		3.69		3.62		3.33		3.13
Average realized price (including firm transportation,    excluding cash settled derivatives)
Natural gas ($/Mcf)	$	2.09	$	2.29	$	2.31	$	1.71
NGLs ($/Bbl)		31.16		21.22		23.62		15.62
Oil ($/Bbl)		49.61		44.51		46.04		37.35
Total average prices ($/Mcfe)		3.25		3.09		3.01		2.30
Average realized price (including cash settled derivatives    and firm transportation)
Natural gas ($/Mcf)	$	2.34	$	2.42	$	2.34	$	2.19
NGLs ($/Bbl)		27.52		20.78		21.96		15.55
Oil ($/Bbl)		49.61		46.97		46.14		44.66
Total average prices ($/Mcfe)		3.35		3.21		2.99		2.76

Per unit cash production costs, which include $0.34 per Mcfe of firm transportation expense, were $1.49 per Mcfe for the fourth quarter 2017 and increased by 1% compared to the fourth quarter of 2016.  The Company’s cash production costs (includes lease operating, transportation, gathering and compression, production and ad valorem taxes) are shown in the table below.

Per unit cash production costs, which include $0.34 per Mcfe of firm transportation expense, were $1.35 per Mcfe for the year ended December 31, 2017 and decreased by 10% compared to the year ended December 31, 2016. The Company’s cash production costs (includes lease operating, transportation, gathering and compression, production and ad valorem taxes) are shown in the table below.  

General and administrative expense was $44.6 million for the year ended December 31, 2017 compared to $39.4 million for the year ended December 31, 2016 and are shown in the table below. General and administrative expense per Mcfe was $0.39 in the year ended December 31, 2017 compared to $0.47 in the year ended December 31, 2016. General and administrative expense includes $9.3 million and $6.2 million of stock-based compensation expense for the years ended December 31, 2017 and 2016, respectively.

	Three Months Ended December 31,				Year Ended December 31,
	2017		2016		2017		2016
Operating expenses (in thousands):
Lease operating	$	8,582	$	1,912	$	20,525	$	9,023
Transportation, gathering and compression		32,124		30,947		124,839		109,226
Production and ad valorem taxes		2,098		2,033		8,490		7,927
Depreciation, depletion and amortization		31,889		28,661		118,818		92,948
General and administrative		12,344		9,719		44,553		39,431
Operating expenses per Mcfe:
Lease operating	$	0.30	$	0.08	$	0.18	$	0.11
Transportation, gathering and compression		1.12		1.31		1.10		1.30
Production and ad valorem taxes		0.07		0.09		0.07		0.09
Depreciation, depletion and amortization		1.11		1.22		1.05		1.11
General and administrative		0.43		0.41		0.39		0.47

Capital Expenditures

Fourth quarter 2017 capital expenditures were $32.3 million, including $21.8 million for drilling and completions, $4.6 million for midstream expenditures, $5.7 million for land-related expenditures, and $0.2 million for corporate-related expenditures.

For the year ended December 31, 2017 capital expenditures were $314.1 million, including $246.4 million for drilling and completions, $10.5 million for midstream expenditures, $55.9 million for land-related expenditures, and $1.3 million for corporate-related expenditures.

During the fourth quarter of 2017, the Company commenced drilling 6 gross (3.3 net) operated Utica Shale wells, commenced completions of 5 gross (3.7 net) operated wells and turned to sales 8 gross (6.6 net) operated wells.  

During the year ended December 31, 2017, the Company commended drilling 29 gross (21.6 net) operated Utica and Marcellus Shale wells, commenced completions of 24 gross (21.3 net) operated wells and turned to sales 24 gross (22.2 net) operated wells.

Financial Position and Liquidity

As of December 31, 2017, the Company’s liquidity was $208.6 million, consisting of $17.2 million in cash and cash equivalents and $191.4 million in available borrowing capacity under the Company’s revolving credit facility (after giving effect to outstanding letters of credit issued by the Company of $33.6 million).

Matthew R. DeNezza, Executive Vice President and Chief Financial Officer, commented, “The closing of the joint venture agreement with Sequel Energy late in the fourth quarter, our year end cash position, undrawn revolver availability of approximately $191 million, along with internally generated cash flows, provide us with the ability to fund our 2018 drilling program. In addition, we will continue to monitor commodity prices as we maintain the flexibility to adjust capital expenditures during the second half of 2018 as commodity prices dictate. ”

Commodity Derivatives

The Company engages in a number of different commodity trading program strategies as a risk management tool to attempt to mitigate the potential negative impact on cash flows caused by price fluctuations in natural gas, NGL and oil prices. Below is a table that illustrates the Company’s hedging activities as of December 31, 2017:

Natural Gas Derivatives

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		30,000	January 2018 – March 2018	$	3.46
Natural Gas Three-way Collars:
Floor purchase price (put)		30,000	January 2018 – March 2019	$	3.00
Ceiling sold price (call)		30,000	January 2018 – March 2019	$	3.40
Floor sold price (put)		30,000	January 2018 – March 2019	$	2.50
Floor purchase price (put)		40,000	January 2018 – March 2018	$	2.90
Floor purchase price (put)		40,000	April 2018 – December 2018	$	3.11
Ceiling sold price (call)		40,000	January 2018 – December 2018	$	3.38
Floor sold price (put)		40,000	January 2018 – December 2018	$	2.50
Floor purchase price (put)		60,000	January 2018 – March 2018	$	2.90
Ceiling sold price (call)		60,000	January 2018 – March 2018	$	3.75
Floor sold price (put)		60,000	January 2018 – March 2018	$	2.50
Floor purchase price (put)		60,000	January 2018 – December 2018	$	2.80
Ceiling sold price (call)		60,000	January 2018 – December 2018	$	3.35
Floor sold price (put)		60,000	January 2018 – December 2018	$	2.50
Natural Gas Call/Put Options:
Call sold		40,000	January 2018 – December 2018	$	3.75
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
Appalachia - Dominion		60,000	January 2018 – March 2018	$	(0.44	)
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)

Oil Derivatives

Description	Volume (Bbls/d)		Production Period	WeightedAverage Price($/Bbl)
Oil Three-way Collars:
Floor purchase price (put)		4,000	January 2018 – December 2018	$	45.00
Ceiling sold price (call)		4,000	January 2018 – December 2018	$	52.25
Floor sold price (put)		4,000	January 2018 – December 2018	$	35.00

Subsequent to the End of the Fourth Quarter:

• The Company added to its natural gas hedge portfolio by executing incremental natural gas swap hedges of 30,000 MMBtu per day at $2.90.

• The Company added to its oil hedge portfolio by executing incremental oil swap hedges of 1,000 Bbl per day at $61.00 as well as incremental three way collars of 2,000 Bbl per day at an average floor price of $50.00 and an average ceiling price of $60.56.

• The Company added to its oil hedge portfolio by executing incremental oil call options of 1,000 Bbl per day at an average ceiling sold price of $57.12 and purchased price of $52.25.

Below are tables that illustrates the Company’s hedging activities subsequent to the end of the fourth quarter:

Natural Gas:

Description	Volume (MMbtu/d)		Production Period	Weighted Average Price ($/MMbtu)
Natural Gas Swaps:
		30,000	April 2018 – March 2019	$	2.90

Oil:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Swaps:
		1,000	July 2018 – March 2019	$	61.00
Oil Three-way Collars:
Floor purchase price (put)		2,000	January 2019 – December 2019	$	50.00
Ceiling sold price (call)		2,000	January 2019 – December 2019	$	60.56
Floor sold price (put)		2,000	January 2019 – December 2019	$	40.00
Oil Call/Put Options:
Ceiling sold price (call)		1,000	February 2018 – December 2018	$	57.12
Ceiling purchased price (call)		1,000	February 2018 – December 2018	$	52.25

Guidance

The Company has also reaffirmed its previously issued first quarter and full year 2018 guidance as set forth in the table below:

	Q1 2018	FY 2018
Production MMcfe/d	304 - 311	335 - 355
% Gas	74% - 76%	73% - 77%
% NGL	13% - 15%	12% - 16%
% Oil	10% - 12%	10% - 12%
Gas Price Differential ($/Mcf)1,2	$(0.10) - $(0.20)	$(0.25) - $(0.35)
Oil Differential ($/Bbl)1	$(6.25) - $(6.75)	$(6.25) - $(7.25)
NGL Prices (% of  WTI)1	45% - 48%	35% - 40%
Cash Production Costs ($/Mcfe)3	$1.50 - $1.55	$1.55 - $1.60
Cash G&A ($mm)4	$9.5 - $10.0	$38 - $40
CAPEX ($mm)		~$300 - $320

₁ Excludes impact of hedges

₂ Excludes the cost of firm transportation

₃ Includes lease operating, transportation, gathering and compression, production and ad valorem taxes

₄ Non-GAAP measure which excludes non-cash compensation, see reconciliation to the most comparable GAAP measure at the end of the financial statements included in this press release

Conference Call

A conference call to review the Company’s financial and operational results is scheduled for Thursday, March 1, 2018 at 10:00 a.m. Eastern Time.  To participate in the call, please dial 877-709-8150 or 201-689-8354 for international callers and reference Eclipse Resources Fourth Quarter and Full Year 2017 Earnings Call.  A replay of the call will be available through May 1, 2018.  To access the phone replay dial 877-660-6853 or 201-612-7415 for international callers.  The conference ID is 13676633.  A live webcast of the call may be accessed through the Investor Center on the Company’s website at www.eclipseresources.com.  The webcast will be archived for replay on the Company’s website for six months.

ECLIPSE RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

	December 31, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	17,224		$	201,229
Accounts receivable		77,609			44,423
Assets held for sale		206			468
Other current assets		12,023			4,295
Total current assets		107,062			250,415
PROPERTY AND EQUIPMENT AT COST
Oil and natural gas properties, successful efforts method:
Unproved properties		459,549			526,270
Proved oil and gas properties, net		647,881			414,482
Other property and equipment, net		6,942			6,748
Total property and equipment, net		1,114,372			947,500
OTHER NONCURRENT ASSETS
Other assets		2,093			729
TOTAL ASSETS	$	1,223,527		$	1,198,644
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	76,174		$	44,049
Accrued capital expenditures		10,658			11,083
Accrued liabilities		41,662			55,044
Accrued interest payable		21,100			21,098
Liabilities held for sale		—			245
Total current liabilities		149,594			131,519
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs		495,021			492,278
Credit facility		—			—
Asset retirement obligations		6,029			4,806
Other liabilities		529			13,434
Total liabilities		651,173			642,037
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, 50,000,000 authorized, no shares issued and outstanding		—			—
Common stock, $0.01 par value, 1,000,000,000 authorized, 262,740,355    and 260,591,893 shares issued and outstanding, respectively		2,637			2,607
Additional paid in capital		1,967,958			1,958,731
Treasury stock, shares at cost; 992,315 and 72,704 shares, respectively		(2,096	)		(61	)
Accumulated deficit		(1,396,145	)		(1,404,670	)
Total stockholders' equity		572,354			556,607
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,223,527		$	1,198,644

ECLIPSE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	For the Year Ended December 31,
	2017			2016			2015
REVENUES
Natural gas, oil and natural gas liquids sales	$	380,178		$	223,015		$	234,601
Brokered natural gas and marketing revenue		3,481			12,019			20,720
Total revenues		383,659			235,034			255,321
OPERATING EXPENSES
Lease operating		20,525			9,023			13,904
Transportation, gathering and compression		124,839			109,226			85,846
Production and ad valorem taxes		8,490			7,927			3,722
Brokered natural gas and marketing expense		3,191			12,268			26,173
Depreciation, depletion and amortization		118,818			92,948			244,750
Exploration		50,208			52,775			116,211
General and administrative		44,553			39,431			46,409
Rig termination and standby		1			3,846			9,672
Impairment of proved oil and gas properties		—			17,665			691,334
Accretion of asset retirement obligations		544			391			1,623
(Gain) loss on sale of assets		(179	)		6,936			(4,737	)
Total operating expenses		370,990			352,436			1,234,907
OPERATING INCOME (LOSS)		12,669			(117,402	)		(979,586	)
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		45,365			(52,338	)		56,021
Interest expense, net		(49,490	)		(50,789	)		(53,400	)
Gain (loss) on early extinguishment of debt		—			14,489			(59,392	)
Other income (expense)		(19	)		(149	)		400
Total other income (expense), net		(4,144	)		(88,787	)		(56,371	)
INCOME (LOSS) BEFORE INCOME TAXES		8,525			(206,189	)		(1,035,957	)
INCOME TAX BENEFIT (EXPENSE)		—			(546	)		74,166
NET INCOME (LOSS)	$	8,525		$	(206,735	)	$	(961,791	)
NET INCOME (LOSS) PER COMMON SHARE
Basic	$	0.03		$	(0.86	)	$	(4.41	)
Diluted	$	0.03		$	(0.86	)	$	(4.41	)
WEIGHTED AVERAGE COMMON SHARES    OUTSTANDING
Basic		262,181			241,434			217,897
Diluted		265,182			241,434			217,897

Adjusted Revenue

Adjusted revenue is a non-GAAP financial measure.  The Company defines Adjusted revenue as follows: total revenues plus net cash receipts or payments on settled derivative instruments less brokered natural gas and marketing revenue.  The Company believes Adjusted revenue provides investors with helpful information with respect to the performance of the Company’s operations and management uses Adjusted revenue to evaluate its ongoing operations and for internal planning and forecasting purposes. See the table below, which reconciles Adjusted revenue and total revenues.

	For the Three Months Ended December 31,						For the Year Ended December 31,
$ thousands	2017			2016			2017			2016
Total revenues	$	104,056		$	83,883		$	383,659		$	235,034
Net cash receipts (payments) on derivative    instruments		2,824			2,826			(2,224	)		38,696
Brokered natural gas and marketing revenue		(1,052	)		(1,608	)		(3,481	)		(12,019	)
Adjusted revenue	$	105,828		$	85,101		$	377,954		$	261,711

Adjusted Net Income (Loss)

Adjusted net income (loss) represents income (loss) before income taxes adjusted for certain non-cash items as set forth in the table below. We believe Adjusted net income (loss) is used by many investors and published research in making investment decisions and evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net income (loss) is not a measure of net income (loss) as determined by GAAP.  See the table below for a reconciliation of Adjusted net income (loss) and net income (loss).

	Three Months Ended December 31,						Year Ended December 31,
$ thousands	2017			2016			2017			2016
Income (loss) before income taxes, as reported	$	(13,122	)	$	(62,083	)	$	8,525		$	(206,189	)
(Gain) loss on derivative instruments		(3,980	)		43,931			(45,365	)		52,338
Net cash receipts (payments) on derivative instruments		2,824			2,826			(2,224	)		38,696
Rig termination and standby		1			3			1			3,846
Impairment of proved oil and gas properties		—			—			—			17,665
Dry hole and other		1,295			156			3,126			1,029
Stock-based compensation		2,444			752			9,301			6,216
Impairment of unproved properties		15,916			1,744			28,291			29,824
Other (income) expense		—			12			19			149
Gain on early extinguishment of debt		—			—			—			(14,489	)
(Gain) loss on sale of assets		(167	)		7,880			(179	)		6,936
Loss before income taxes, as adjusted		5,211			(4,779	)		1,495			(63,979	)
Income tax benefit (expense)		—			(6	)		—			(546	)
Adjusted net income (loss)	$	5,211		$	(4,785	)	$	1,495		$	(64,525	)
Net income (loss) per Common Share
Basic	$	(0.05	)	$	(0.24	)	$	0.03		$	(0.86	)
Diluted	$	(0.05	)	$	(0.24	)	$	0.03		$	(0.86	)
Adjusted net income (loss) per Common Share
Basic	$	0.02		$	(0.02	)	$	0.01		$	(0.27	)
Diluted	$	0.02		$	(0.02	)	$	0.01		$	(0.27	)
Weighted Average Common Shares Outstanding
Basic		262,587			258,812			262,181			241,434
Diluted		266,570			258,812			265,182			241,434

Adjusted EBITDAX

Adjusted EBITDAX is a supplemental non-GAAP measure that is used by the Company to evaluate its financial results. The Company defines Adjusted EBITDAX as net income or loss before interest expense; income taxes; impairments; depreciation, depletion and amortization (“DD&A”); gain (loss) on derivative instruments, net cash receipts (payments on settled derivative instruments, and premiums (paid) received on options that settled during the period); non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items set forth in the table below. Adjusted EBITDAX is not a measure of net income or loss as determined by GAAP.  See the table below for a reconciliation of Adjusted EBITDAX to net income or net loss.

	Three Months Ended December 31,						Year Ended December 31,
$ thousands	2017			2016				2017		2016
Net income (loss)	$	(13,122	)	$	(62,089	)	$	8,525		$	(206,735	)
Depreciation, depletion and amortization		31,889			28,661			118,818			92,948
Exploration expense		20,695			7,592			50,208			52,775
Rig termination and standby		1			3			1			3,846
Stock-based compensation		2,444			752			9,301			6,216
Impairment of proved oil and gas properties		—			—			—			17,665
Accretion of asset retirement obligations		148			116			544			391
(Gain) loss on sale of assets		(167	)		7,880			(179	)		6,936
(Gain) loss on derivative instruments		(3,980	)		43,931			(45,365	)		52,338
Net cash receipts (payments) on settled derivatives		2,824			2,826			(2,224	)		38,696
Interest expense, net		12,727			12,496			49,490			50,789
(Gain) loss on early extinguishment of debt		—			—			—			(14,489	)
Other (income) expense		—			12			19			149
Income tax benefit (expense)		—			6			—			546
Adjusted EBITDAX	$	53,459		$	42,186		$	189,138		$	102,071

Cash General and Administrative Expenses

Cash General and Administrative Expenses is a non-GAAP financial measure used by the Company in the Guidance Table to provide a measure of administrative expenses used by many investors and published research in making investment decisions and evaluating operational trends of the Company. See the table below for a reconciliation of Cash General and Administrative Expenses and General and Administrative Expenses.

							Guidance
$ thousands	For the Three Months Ended December 31, 2017			For the Year Ended December 31, 2017			For the Three Months Ending March 31, 2018	For the Year Ending December 31, 2018
General and administrative expenses, estimated to be    reported	$	12,344		$	44,553		$10,500-$13,000	$46,500-$50,000
Stock-based compensation expense		(2,444	)		(9,301	)	(1,000 - 3,000)	(8,500 - 10,500)
Cash general and administrative expenses	$	9,900		$	35,252		$9,500-$10,000	$38,000-$40,000

About Eclipse Resources

Eclipse Resources is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin, including the Utica and Marcellus Shales. For more information, please visit the Company’s website at www.eclipseresources.com.

Forward-Looking Statements

This press release 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 press release, regarding Eclipse Resources’ strategy, future operations, financial position, estimated revenues and income/losses, projected costs and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this press release, the words “plan,” “endeavor,” “will,” “would,” “could,” “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 based on Eclipse Resources’ current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” in Eclipse Resources’ Annual Report on Form 10-K filed with the Securities Exchange Commission on March 3, 2017 (the “2016 Annual Report”), and in “Item 1A. Risk Factors” of Eclipse Resources’ Quarterly Reports on Form 10-Q.

Forward-looking statements may include, but are not limited to, statements about Eclipse Resources’ business strategy; reserves; general economic conditions; financial strategy, liquidity and capital required for developing its properties and timing related thereto; realized prices for natural gas, natural gas liquids and oil and the volatility of those prices; timing and amount of future production of natural gas, NGLs and oil; its hedging strategy and results; future drilling plans; competition and government regulations, including those related to hydraulic fracturing; the anticipated benefits under its commercial agreements; marketing of natural gas, NGLs and oil; leasehold and business acquisitions; the costs, terms and availability of gathering, processing, fractionation and other midstream services; credit markets; uncertainty regarding its future operating results, including initial production rates and liquid yields in its type curve areas; and plans, objectives, expectations and intentions contained in this press release that are not historical, including, without limitation, the guidance set forth herein..

Eclipse Resources cautions you that all these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s 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 flow and access to capital, risks associated with the Company’s level of indebtedness, the timing of development expenditures, and the other risks described under the heading “Risk Factors” in the 2016 Annual Report and in “Item 1A. Risk Factors” of Eclipse Resources’ Quarterly Reports on Form 10-Q.

All forward-looking statements, expressed or implied, included in this press release 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 Eclipse Resources or persons acting on the Company’s behalf may issue. Except as otherwise required by applicable law, Eclipse Resources disclaims any duty to update any forward-looking statements to reflect events or circumstances after the date of this press release.

Contact:

Eclipse Resources Corporation

Douglas Kris, Investor Relations

814-325-2059

dkris@eclipseresources.com