ECR Eclipse Resources Corp.

Eclipse Resources Corporation (NYSE:ECR) (the “Company” or “Eclipse Resources”) today announced its third quarter 2017 financial and operational results and provided updated full year 2017 guidance. In conjunction with this release, the Company has posted an updated investor presentation to its website at www.eclipseresources.com.

Third Quarter 2017 Highlights:

• Placed two new Utica Condensate “Super-Lateral” wells into sales with initial average production rates of approximately 3,300 BOE per day per well (48% condensate, 68% liquids) on a restricted choke during the fourth quarter of 2017.
• Average net daily production was 353 MMcfe per day, in line with the Company’s previously issued production guidance range of 350 to 355 MMcfe per day.
• Realized an average natural gas price, before the impact of cash settled derivatives and firm transportation expenses, of $2.47 per Mcf, a $0.53 per Mcf discount to the average monthly NYMEX settled natural gas price during the quarter, exceeding the Company’s previously issued natural gas differential discount guidance of $0.60 to $0.70 per Mcf.
• Realized an average oil price, before the impact of cash settled derivatives, of $42.08 per barrel, a $6.10 per barrel discount to the average WTI oil price during the quarter, exceeding the Company’s previously issued oil differential guidance range of $6.50 to $7.00 per barrel.
• Realized an average natural gas liquids (“NGL”) price, before the impact of cash settled derivatives, of $20.34 per barrel, or approximately 42% of the average WTI oil price during the quarter and exceeding the Company’s previously issued NGL guidance range of 30% to 35% of the WTI oil price.
• Per unit cash production costs (including lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.18 per Mcfe, including $0.28 per Mcfe in firm transportation expenses, which was below the Company’s previously issued per unit cash production cost guidance range of $1.20 to $1.25 per Mcfe.
• Net loss for the third quarter of 2017 was $(16.7) million; and Adjusted EBITDAX1 for the third quarter of 2017 was $45.9 million.

1 Non-GAAP measure. See reconciliation for details.

Benjamin W. Hulburt, Chairman, President and CEO, commented on the Company’s third quarter 2017 results, “Eclipse Resources has continued to build on its strong track record and has delivered another solid quarter. We continue to challenge ourselves to provide incremental enhancements to our drilling and completions capabilities by embracing new technology and data applications while striving for optimal performance throughout our processes, from planning to implementation. As of the end of the third quarter, we had drilled eleven “super-lateral” wells with an average lateral length of approximately 18,000 feet, averaging just 16 days from spud to total depth (“TD”). During the third quarter, the Company drilled 10 gross (9.7 net) wells including four “super-laterals” with an average lateral length of over 17,500 feet. Moving into the fourth quarter, we drilled our Mercury B5H, setting a new lateral length record, located in the Utica Condensate area. This well was drilled with a lateral length of approximately 20,800 feet in 13 days spud to TD with the lateral itself drilled in only five days.

“On the completion side, we are in the process of completing our “stacked pay” Stalder pad, which incorporates two Marcellus Condensate wells and three Utica Dry Gas wells. We expect that this pad will begin to turn to sales in January 2018 and anticipate that it will provide the Company with the data needed to further validate our condensate rich Marcellus play footprint in eastern Ohio. Currently we have 16 wells with average lateral lengths of 14,500 (232,000 in total lateral footage) drilled but not completed. Two of these are Marcellus Condensate wells which are currently completing, three are Utica Dry gas wells that are waiting on plug drill out, while one Utica Dry and 10 Utica Condensate wells are waiting on completion. As our drilling operations have generally been more efficient and faster than expected, we are currently planning to mobilize a second completion crew in the first quarter to reduce our drilled uncompleted well inventory.

“Lastly and perhaps most excitingly, early in the fourth quarter, we began turning to sales five wells in the Utica Condensate portion of our acreage that included our Great Scott 3H (19,200 foot completed lateral) and Outlaw C11H (19,600 foot completed lateral), along with three additional laterals averaging approximately 10,300 feet in length. The two record setting “super-laterals” have reached an average per well 24-hour production rate of approximately 3,300 Barrels of Oil Equivalent (“BOE”) to date on a restricted choke, consisting of almost 50% condensate and 68% in total liquids. We estimate that our total cost to drill and complete these two “super-lateral” wells (including all construction and facility costs) was approximately $750 per foot of lateral. We are continuing to bring all five wells up to what we believe to be a stabilized rate as the wells continue to clean up. To date, the five wells have reached a per well average daily rate of 163 BOE per day per 1,000 foot of lateral consisting of approximately 67% liquids.

“Concerning our previously announced drilling joint venture commitment agreement, I am pleased to say that we believe we have substantially completed the binding documents associated with the joint venture with Sequel Energy and have commenced a preclearance process related to the accounting treatment of the transaction with the Securities and Exchange Commission (“SEC”). We hope to close the transaction, pending final discussions with the SEC during the next 30 days. I believe that I speak for both Eclipse and Sequel in saying that we are excited to begin this next step in growing our production base to achieve ultimate scale in our model while managing our business prudently in what continues to be a constantly changing environment.”

Operational Discussion

The Company’s production for the three and nine months ended September 30, 2017 and 2016 is set forth in the following table:

  Three Months Ended     Nine Months Ended September 30, September 30, 2017     2016 2017     2016 Production:         Natural gas (MMcf) 26,716.4 15,372.2 66,225.8 44,358.0 NGL sales (Mbbls) 675.6 525.5 2,002.7 1,725.1 Oil sales (Mbbls) 281.3 310.0 1,083.2 910.4 Total (MMcfe) 32,457.8 20,385.2 84,741.2 60,171.0   Average daily production volume: Natural gas (Mcf/d) 290,396 167,089 242,585 161,891 NGL sales (Bbls/d) 7,343 5,712 7,336 6,296 Oil sales (Bbls/d) 3,058 3,370 3,968 3,323 Total (Mcfe/d) 352,802 221,575 310,409 219,605  

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 NYMEX WTI prices for oil for the three and nine months ended September 30, 2017 and 2016:

  Three Months Ended     Nine Months Ended September 30, September 30, 2017     2016 2017     2016 NYMEX Henry Hub High ($/MMBtu) $ 3.18 $ 3.19 $ 3.71 $ 3.19 NYMEX Henry Hub Low ($/MMBtu) 2.76 2.67 2.44 1.49 Average Daily NYMEX Henry Hub ($/MMBtu) 2.95 2.88 3.01 2.37 Average Monthly NYMEX Settled Henry Hub ($/MMBtu) 3.00 2.81 3.17 2.29   NYMEX WTI High ($/Bbl) $ 52.14 $ 49.02 $ 54.48 $ 51.23 NYMEX WTI Low ($/Bbl) 44.25 39.50 42.48 26.19 Average NYMEX WTI ($/Bbl) 48.18 44.89 49.30 42.25  

Financial Discussion

Revenue for the third quarter of 2017 totaled $91.5 million, compared to $54.5 million for the third quarter of 2016. Adjusted Revenue2, which includes the impact of cash settled derivatives and excludes brokered natural gas and marketing revenue, totaled $93.1 million for the third quarter of 2017 compared to $59.0 million for the third quarter of 2016. Net Income (Loss) for the third quarter of 2017 was $(16.7) million, or $(0.06) per share compared to $(25.9) million or $(0.10) per share for the third quarter of 2016. Adjusted Net Income (Loss) 2 for the third quarter of 2017 was $(5.8) million, or $(0.02) per share, compared to $(20.5) million, or $(0.08) per share for the third quarter of 2016. Adjusted EBITDAX2 was $45.9 million for the third quarter of 2017 compared to $22.6 million for the third quarter of 2016.

Revenue for the nine months ended September 30, 2017 totaled $279.6 million, compared to $151.2 million for the nine months ended September 30, 2016. Adjusted Revenue2, which includes the impact of cash settled derivatives and excludes brokered natural gas and marketing revenue, totaled $272.1 million for the nine months ended September 30, 2017 compared to $176.6 million for the nine months ended September 30, 2016. Net Income (Loss) for the nine months ended September 30, 2017 was $21.6 million, or $0.08 per share compared to $(144.6) million or $(0.62) per share for the nine months ended September 30, 2016. Adjusted Net Income (Loss)2 for the nine months ended September 30, 2017 was $(3.7) million, or $(0.01) per share, compared to $(59.7) million, or $(0.25) per share for the nine months ended September 30, 2016. Adjusted EBITDAX2 was $135.7 million for the nine months ended September 30, 2017 compared to $59.9 million for the nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 are set forth in the table below:

  Three Months Ended     Nine Months Ended September 30, September 30, 2017     2016 2017     2016

Average Sales Price (excluding cash settled derivatives and firm transportation)

Natural gas ($/Mcf) $ 2.47 $ 2.28 $ 2.83 $ 1.96 NGLs ($/Bbl) 20.34 13.41 20.95 13.28 Oil ($/Bbl) 42.08 39.67 44.26 33.95 Total average prices ($/Mcfe) 2.82 2.67 3.27 2.34  

Average Sales Price (including cash settled derivatives, excluding firm transportation)

Natural gas ($/Mcf) $ 2.55 $ 2.50 $ 2.78 $ 2.57 NGLs ($/Bbl) 19.52 13.21 19.99 13.36 Oil ($/Bbl) 42.42 43.60 44.41 43.56 Total average prices ($/Mcfe) 2.87 2.89 3.21 2.94  

Average Sales Price (including firm transportation, excluding cash settled derivatives)

Natural gas ($/Mcf) $ 2.13 $ 1.77 $ 2.39 $ 1.49 NGLs ($/Bbl) 20.34 13.41 20.95 13.28 Oil ($/Bbl) 42.08 39.67 44.26 33.95 Total average prices ($/Mcfe) 2.54 2.28 2.93 1.99  

Average Sales Price (including cash settled derivatives and firm transportation)

Natural gas ($/Mcf) $ 2.20 $ 2.00 $ 2.34 $ 2.10 NGLs ($/Bbl) 19.52 13.21 19.99 13.36 Oil ($/Bbl) 42.42 43.60 44.41 43.56 Total average prices ($/Mcfe) 2.59 2.51 2.87 2.59  

The Company’s operating expenses per Mcfe for the third quarter of 2017 decreased by 19% compared to the third quarter of 2016 and are shown in the table below. Per unit cash production costs (includes lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.18 per Mcfe for the third quarter 2017 and includes $0.28 per Mcfe of firm transportation expenses.

General and administrative expense was $11.3 million for the three months ended September 30, 2017 compared to $8.0 million for the three months ended September 30, 2016 and are shown in the table below. General and administrative expense per Mcfe was $0.35 in the three months ended September 30, 2017 compared to $0.39 in the three months ended September 30, 2016. The increase of $3.3 million during the three months ended September 30, 2017 when compared to three months ended September 30, 2016 was primarily due to higher salaries and benefits associated with increased headcount for the three months ended September 30, 2017. The decrease of $0.04 per Mcfe is due to fixed costs being spread across higher production as of September 30, 2017 as compared to September 30, 2016. General and administrative expense includes $2.4 million and $1.8 million of stock-based compensation expense for the three months ended September 30, 2017 and 2016, respectively.

  Three Months Ended     Nine Months Ended September 30, September 30, 2017     2016 2017     2016 Operating expenses (in thousands): Lease operating $ 5,032 $ 2,186 $ 11,943 $ 7,111 Transportation, gathering and compression 30,869 26,888 92,715 78,279 Production and ad valorem taxes 2,427 1,128 6,391 5,894 Depreciation, depletion and amortization 35,588 28,225 86,929 64,287 General and administrative 11,347 8,036 32,209 29,712 Operating expenses per Mcfe: Lease operating $ 0.16 $ 0.11 $ 0.14 $ 0.12 Transportation, gathering and compression 0.95 1.32 1.10 1.30 Production, severance and ad valorem taxes 0.07 0.06 0.08 0.10 Depreciation, depletion and amortization 1.10 1.38 1.03 1.07 General and administrative 0.35 0.39 0.38 0.49  

Capital Expenditures

Third quarter 2017 capital expenditures were $104.5 million. These expenditures included $88.8 million for drilling and completions, $2.7 million for midstream expenditures, $12.4 million for land-related expenditures, and $0.6 million for corporate-related expenditures.

During the third quarter of 2017, the Company commenced drilling 10 gross (9.7 net) operated Utica Shale wells. In addition, the Company commenced completions of 6 gross (6.0 net) operated wells and turned to sales 2 gross (2.0 net) operated wells.

Financial Position and Liquidity

As of September 30, 2017, the Company’s liquidity was $220.2 million, consisting of $28.8 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, “We believe our current liquidity position coupled with the drilling joint venture agreement will allow us the financial flexibility to navigate the current commodity price volatility without adding stress to our balance sheet. Assuming the closing of our pending drilling joint venture is completed before year-end, we would expect to receive a significant reimbursement of the third and fourth quarter’s drilling and completion capital expenditures, and as such, we continue to anticipate that we will end the full year 2017 with an undrawn revolver.”

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 September 30, 2017:

Natural Gas Derivatives

  Volume       Weighted Average Description (MMBtu/d) Production Period Price ($/MMBtu) Natural Gas Swaps:   10,000 October 2017 – December 2017 $ 2.98 10,000 October 2017 – December 2017 $ 3.21 30,000 October 2017 – March 2018 $ 3.46 Natural Gas Three-way Collars: Floor purchase price (put) 160,000 October 2017 – December 2017 $ 2.83 Ceiling sold price (call) 160,000 October 2017 – December 2017 $ 3.37 Floor sold price (put) 160,000 October 2017 – December 2017 $ 2.31 Floor purchase price (put) 30,000 October 2017 – March 2019 $ 3.00 Ceiling sold price (call) 30,000 October 2017 – March 2019 $ 3.40 Floor sold price (put) 20,000 October 2017 – March 2019 $ 2.40 Floor sold price (put) 10,000 October 2017 – March 2019 $ 2.20 Floor purchase price (put) 40,000 October 2017 – December 2018 $ 2.90 Ceiling sold price (call) 40,000 October 2017 – December 2018 $ 3.38 Floor sold price (put) 40,000 October 2017 – December 2018 $ 2.30 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 $ 2.40 Floor purchase price (put) 60,000 April 2018 – December 2018 $ 2.90 Ceiling sold price (call) 60,000 April 2018 – December 2018 $ 3.25 Floor sold price (put) 60,000 April 2018 – December 2018 $ 2.40 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 $ 2.33 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: TCO - Columbia 20,000 October 2017 – December 2017 $ (0.19 ) Appalachia - Dominion 80,000 October 2017 – November 2017 $ (1.02 ) Appalachia - Dominion 50,000 December 2017 $ (0.56 ) Appalachia - Dominion 50,000 January 2018 – March 2018 $ (0.43 ) Appalachia - Dominion 12,500 April 2019 – October 2019 $ (0.52 ) Appalachia - Dominion 12,500 April 2020 – October 2020 $ (0.52 )  

Oil Derivatives

  Volume       Weighted Average Description (Bbls/d) Production Period Price ($/Bbl) Oil Three-way Collars:   Floor purchase price (put) 2,000 October 2017 – December 2017 $ 46.00 Ceiling sold price (call) 2,000 October 2017 – December 2017 $ 60.00 Floor sold price (put) 2,000 October 2017 – December 2017 $ 38.00  

NGL Derivatives

  Volume       Weighted Average Description (Gal/d) Production Period Price ($/Gal)

Propane Swaps:                     

  84,000 October 2017 – December 2017 $ 0.60  

Guidance

The Company has reiterated the following full year 2017 guidance in the table below:

                  FY 2017 Production MMcfe/d 315 - 320 % Gas 77% - 81% % NGL 11% - 15% % Oil 7% - 9% Gas Price Differential ($/Mcf)1,2 $(0.30) - $(0.40) Oil Differential ($/Bbl)1 $(5.50) - $(6.00) NGL Prices (% of WTI)1 40% - 45% Cash Production Costs ($/Mcfe)3 $1.35 - $1.40 Cash G&A ($mm)4 $35 - $37 CAPEX ($mm)5 ~$300

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.5 Excludes potential acquisitions and payments of approximately $18 million for land leased in 2016 which was paid in 2017.

Conference Call

A conference call to review the Company’s financial third quarter 2017 earnings is scheduled for Thursday, November 9, 2017, at 10:00 a.m. (Eastern). To participate in the call, please dial 877-709-8150, or 201-689-8354 for international callers, and reference Eclipse Resources Third Quarter Earnings Call. A replay of the call will be available through January 9, 2017. To access the phone replay dial 877-660-6853 or 201-612-7415 for international callers. The conference ID is 13672214. A live webcast of the call may be accessed through the “Investors” section of the Company’s website at www.eclipseresources.com.

    ECLIPSE RESOURCES CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

  September 30, December 31, 2017 2016 ASSETS CURRENT ASSETS Cash and cash equivalents $ 28,795 $ 201,229 Accounts receivable 40,553 44,423 Assets held for sale 426 468 Other current assets   6,959   4,295 Total current assets 76,733 250,415   PROPERTY AND EQUIPMENT AT COST Oil and natural gas properties, successful efforts method: Unproved properties 488,260 526,270 Proved oil and gas properties, net 636,023 414,482 Other property and equipment, net   7,190   6,748 Total property and equipment, net 1,131,473 947,500   OTHER NONCURRENT ASSETS Other assets   2,040   729 TOTAL ASSETS $ 1,210,246 $ 1,198,644   LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable $ 69,914 $ 44,049 Accrued capital expenditures 19,319 11,083 Accrued liabilities 24,981 55,044 Accrued interest payable 9,973 21,098 Liabilities held for sale   189   245 Total current liabilities 124,376 131,519   NONCURRENT LIABILITIES Debt, net of unamortized discount and debt issuance costs 494,332 492,278 Asset retirement obligations 5,766 4,806 Other liabilities   2,740   13,434 Total liabilities 627,214 642,037 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 1,965,514 1,958,731

Treasury stock, shares at cost; 992,315 and 72,704 shares, respectively

(2,096 ) (61 ) Accumulated deficit   (1,383,023 )   (1,404,670 ) Total stockholders' equity   583,032   556,607 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,210,246 $ 1,198,644       ECLIPSE RESOURCES CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

  For the Three Months Ended For the Nine Months Ended September 30, September 30, 2017   2016 2017   2016 REVENUES Natural gas, oil and natural gas liquids sales $ 91,549 $ 54,351 $ 277,174 $ 140,740 Brokered natural gas and marketing revenue   —   128   2,428   10,411 Total revenues 91,549 54,479 279,602 151,151   OPERATING EXPENSES Lease operating 5,032 2,186 11,943 7,111 Transportation, gathering and compression 30,869 26,888 92,715 78,279 Production and ad valorem taxes 2,427 1,128 6,391 5,894 Brokered natural gas and marketing expense 8 42 2,474 11,604 Depreciation, depletion and amortization 35,588 28,225 86,929 64,287 Exploration 8,937 12,083 29,514 45,183 General and administrative 11,347 8,036 32,209 29,712 Rig termination and standby — (112 ) — 3,843 Impairment of proved oil and gas properties — — — 17,665 Accretion of asset retirement obligations 143 100 395 275 (Gain) loss on sale of assets   (13 )   102   (12 )   (944 ) Total operating expenses   94,338   78,678   262,558   262,909 OPERATING INCOME (LOSS) (2,789 ) (24,199 ) 17,044 (111,758 ) OTHER INCOME (EXPENSE) Gain (loss) on derivative instruments (1,889 ) 10,639 41,385 (8,407 ) Interest expense, net (12,016 ) (12,393 ) (36,763 ) (38,293 ) Gain (loss) on early extinguishment of debt — — — 14,489 Other income (expense)   —   4   (19 )   (137 ) Total other income (expense), net   (13,905 )   (1,750 )   4,603   (32,348 ) INCOME (LOSS) BEFORE INCOME TAXES (16,694 ) (25,949 ) 21,647 (144,106 ) INCOME TAX BENEFIT (EXPENSE)   —   —   —   (540 ) NET INCOME (LOSS) $ (16,694 ) $ (25,949 ) $ 21,647 $ (144,646 )   NET INCOME (LOSS) PER COMMON SHARE Basic $ (0.06 ) $ (0.10 ) $ 0.08 $ (0.62 ) Diluted $ (0.06 ) $ (0.10 ) $ 0.08 $ (0.62 )   WEIGHTED AVERAGE COMMON SHARES

OUTSTANDING

Basic 262,586 258,812 262,044 234,933 Diluted 262,586 258,812 264,717 234,933  

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   For the Nine Months Ended September 30, September 30, $ thousands 2017     2016 2017   2016 Total revenues $ 91,549 $ 54,479 $ 279,602 $ 151,151

Net cash receipts (payments) on derivative instruments

1,585 4,612 (5,048 ) 35,870

Brokered natural gas and marketing revenue

  —   (128 )   (2,428 )   (10,411 ) Adjusted revenue $ 93,134 $ 58,963 $ 272,126 $ 176,610  

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   Nine Months Ended September 30, September 30, $ thousands 2017   2016 2017   2016 Income (loss) before income taxes, as reported $ (16,694 ) $ (25,949 ) $ 21,647 $ (144,106 ) (Gain) loss on derivative instruments 1,889 (10,639 ) (41,385 ) 8,407 Net cash receipts (payments) on derivative instruments 1,585 4,612 (5,048 ) 35,870 Rig termination and standby — (112 ) — 3,843 Impairment of proved oil and gas properties — — — 17,665 Dry hole and other 889 325 1,831 872 Stock-based compensation 2,428 1,764 6,857 5,464 Impairment of unproved properties 4,125 9,360 12,375 28,080 Other (income) expense — (4 ) 19 137 Gain on early extinguishment of debt — - — (14,489 ) (Gain) loss on sale of assets   (13 )   102   (12 )   (944 ) Loss before income taxes, as adjusted (5,791 ) (20,541 ) (3,716 ) (59,201 ) Income tax benefit (expense)   —   —   —   (540 ) Adjusted net income (loss) $ (5,791 ) $ (20,541 ) $ (3,716 ) $ (59,741 )   Net income (loss) per Common Share Basic $ (0.06 ) $ (0.10 ) $ 0.08 $ (0.62 ) Diluted $ (0.06 ) $ (0.10 ) $ 0.08 $ (0.62 )   Adjusted net income (loss) per Common Share Basic $ (0.02 ) $ (0.08 ) $ (0.01 ) $ (0.25 ) Diluted $ (0.02 ) $ (0.08 ) $ (0.01 ) $ (0.25 )   Weighted Average Common Shares Outstanding Basic 262,586 258,812 262,044 234,933 Diluted 262,586 258,812 262,044 234,933  

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   Nine Months Ended September 30, September 30, $ thousands 2017   2016   2017   2016 Net income (loss) $ (16,694 ) $ (25,949 ) $ 21,647 $ (144,646 ) Depreciation, depletion and amortization 35,588 28,225 86,929 64,287 Exploration expense 8,937 12,083 29,514 45,183 Rig termination and standby — (112 ) — 3,843 Impairment of proved oil and gas properties — — — 17,665 Stock-based compensation 2,428 1,764 6,857 5,464 Accretion of asset retirement obligations 143 100 395 275 (Gain) loss on derivative instruments 1,889 (10,639 ) (41,385 ) 8,407 Net cash receipts (payments) on settled derivatives 1,585 4,612 (5,048 ) 35,870 Interest expense, net 12,016 12,393 36,763 38,293 (Gain) loss on sale of assets (13 ) 102 (12 ) (944 ) (Gain) loss on early extinguishment of debt — — — (14,489 ) Other (income) expense — (4 ) 19 137 Income tax (benefit) expense   —   —   —   540 Adjusted EBITDAX $ 45,879 $ 22,575 $ 135,679 $ 59,885  

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 For the Three Months For the Year Ending $ thousands Ended September 30, 2017 December 31, 2017

General and administrative expenses, estimated to be reported

$ 11,347 $44,500-$47,500 Stock-based compensation expense   (2,428 ) (9,500-10,500) Cash general and administrative expenses $ 8,919 $35,000-$37,000  

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 and 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 statements about Eclipse Resources’ business strategy; reserves; its proposed drilling joint venture with Sequel; general economic conditions; financial strategy, liquidity and capital required for developing its properties and timing related thereto; realized natural gas, NGLs and oil 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; pending legal matters relating to its leases; 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.

Eclipse Resources cautions 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 its 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 recent significant decline of the price of natural gas, NGLs, and oil, inflation, lack of availability of drilling, production and processing equipment and services, Eclipse Resources’ inability to successfully negotiate or enter into definitive agreements and satisfy other conditions precedent for its proposed joint venture drilling transaction with Sequel, and to effectively implement that transaction, 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, 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.

View source version on businesswire.com: http://www.businesswire.com/news/home/20171108006553/en/

Eclipse Resources CorporationDouglas Kris, Investor Relations, 814-325-2059dkris@eclipseresources.com