Eclipse Resources Corporation Announces Third Quarter 2016 Financial And Operational Results

Eclipse Resources Corporation (NYSE:ECR) (the "Company" or "Eclipse Resources") today announced its third quarter 2016 financial and operational results.

Third Quarter 2016 Highlights:
  • Average net daily production was 221.6 MMcfe per day, exceeding the high end of the Company's previously issued guidance.
  • Realized an average natural gas price, before the impact of cash settled derivatives and firm transportation expenses, of $2.28 per Mcf, a $0.60 discount to the average NYMEX natural gas prices during the quarter.
  • Realized an average oil price, before the impact of cash settled derivatives of $39.67 per barrel, a $5.22 per barrel discount to the average WTI oil price during the quarter.
  • Realized an average natural gas liquids price, before the impact of cash settled derivatives of $13.41 per barrel, or approximately 30% of the average WTI oil price during the quarter.
  • Per unit cash production costs (includes lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.53 per Mcfe and includes $0.39 per Mcfe of firm transportation expenses.
  • Net loss for the third quarter of 2016 was $26.8 million; Adjusted EBITDAX 1 for the third quarter of 2016 was $21.7 million.
  • Completed 12 wells utilizing Eclipse's "Generation 3" completion design which incorporates increased proppant loading, tighter spacing and 100% slickwater. The Company turned 11 gross (9.6 net) wells to sales during the third quarter of 2016 and was very encouraged with the initial results of the wells as compared to the Company's previous completion designs.
  • The Company's first "Super-Lateral" well continued to outperform the Company's "type well" expectations, producing a cumulative amount of 2.4 Bcfe (38% gas, 38% condensate and 24% natural gas liquids) during the first 185 days of production while exhibiting significantly shallower pressure declines than the Company anticipated. Based on the well's performance to date, the Company currently estimates the well will outperform the Company's "type well" reserve expectations by 28% to 50%.

Subsequent to the end of the Third Quarter:
  • Commenced transporting natural gas as the only user on the 205,000 MMBtu per day Utica Access Project into the Columbia Gas Transmission "TCO" pool.
  • The Company completed its borrowing base redetermination of its revolving credit facility which resulted in no change to its $125 million borrowing base. The Company remains undrawn on its revolving credit facility, other than for letters of credit.
  • The Company added to its natural gas hedge portfolio by executing incremental hedges of 90,000 MMBtu per day.
    • The Company has 198,333 MMBtu per day of 2017 natural gas production hedged, or approximately 80% of its expected natural gas production, at an average floor price 2 of $2.86 and an average ceiling price of $3.28.
    • The Company has an average of 3,500 barrels per day of 2017 oil production hedged, or approximately 80% of its expected oil production, at an average floor price 2 of $46.00 and an average ceiling price of $59.81.
    • The Company has 140,000 MMBtu per day of 2018 natural gas production hedged at an average floor price 2 of $2.86 and an average ceiling price of $3.29.

1
 

Non-GAAP measure. See reconciliation for details

2

For the purposes of calculating three-way floor price, the higher valued put is used
 

Benjamin W. Hulburt, Chairman, President and CEO, commented on the Company's third quarter 2016 results, "The team's continuously outstanding execution and innovation has allowed us to yet again exceed the high end of our production guidance while delivering unit operating costs below our previously estimated guidance range for the quarter. During the third quarter, a team of Eclipse Resources and Halliburton personnel set a Halliburton record for the number of stages completed in a month by a single crew in the Northeast region. This record was set and then broken by the same crew in two consecutive months. Additionally, this week we learned we set their record for the total amount of proppant pumped in a month by a single crew in the Northeast, pumping over 82 million pounds of proppant in October. We have transferred some lessons learned from our ground breaking Purple Hayes "Super-Lateral" well which continues to exceed our type well expectations to date. During the quarter, we completed 12 of our DUC wells using what we refer to as our "Generation 3" completion design that incorporates tighter spacing, increased proppant loading and 100% slickwater. Due to record setting efficiencies in our completion operations, we have been able to effectively neutralize well cost inflation keeping our well costs within budget and maintaining leading edge cost metrics.

To date, our wells turned to sales using the "Generation 3" completion design have exhibited higher initial flowing tubing pressures as compared to Generation 1 and 2 completions employed previously. These wells are being produced using our managed pressure drawdown method and have demonstrated flat production with very encouraging pressure declines similar to what we've seen on our Purple-Hayes well.

We are continuing to drill on our Utica Shale dry gas acreage in eastern Monroe County, Ohio where we are currently drilling a 7 well pad. Additionally, we are currently completing our first "Generation 3" completion in the dry gas window on a five well pad with average lateral extensions of 10,891 feet in which we are successfully placing proppant concentrations of 2,600 to 3,000 pounds per foot using 100% slickwater. We expect to begin putting these exciting test wells to sales starting late in the fourth quarter.

With the commencement of our Utica Access capacity in mid-October, we can now transport up to 205,000 MMBtu per day of our gas to the "TCO" pool. With this capacity now in place, we have seen an immediate uplift to our realized natural gas prices and expect to realize a differential of ($0.30) to ($0.35) per Mcf on natural gas sales during the fourth quarter of 2016. Based on forward basis pricing, this capacity could allow for an estimated basis uplift of approximately $1.08 per MMBtu 3 for 2017 relative to selling natural gas at Dominion South Point. This valuable natural gas firm transport capacity coupled with our recently added ability to access capacity on the Mariner East I pipeline for a portion of our ethane should enable us to achieve a higher overall realized price per unit moving forward.

We have taken advantage of the recent price improvement in natural gas markets to finish out our 2017 gas hedging program, which now covers approximately 80% of our currently expected natural gas production of 2017, and to commence our 2018 natural gas hedging program which now totals 140,000 MMBtu per day. We expect to continue to opportunistically add to our 2018 hedge portfolio as prices allow, while attempting to retain upside participation if the natural gas price increases."

3
 

Based on the full year 2017 calendar spread between Dominion South Point and the TCO pool
 

Operational Discussion

The Company's production for the three months ended September 30, 2016 and 2015 is set forth in the following table:
  Three Months Ended

September 30,
2016     2015
Production:    
Natural gas (MMcf) 15,372.2 13,412.4
NGL sales (Mbbls) 525.5 663.2
Oil sales (Mbbls) 310.0 554.6
Total (MMcfe) 20,385.2 20,719.2
 
Average daily production volume:
Natural gas (Mcf/d) 167,089 145,787
NGL sales (Bbls/d) 5,712 7,209
Oil sales (Bbls/d) 3,370 6,028
Total (Mcfe/d) 221,575 225,209
 

The table below summarizes year to date activity as of September 30, 2016 and the number of wells expected to be turned to sales for the remainder of 2016:
Area   Wells Spud YTD     Wells Completed YTD     Wells to Sales YTD    

Planned Wells to Sales in Q4 2016
Condensate/Rich Gas   2      
Dry Gas East 5 2 5
Lean Condensate 1 15 14 3
 

Financial Discussion

GAAP Revenues for the third quarter of 2016 totaled $54.5 million, compared to $71.2 million for the third quarter of 2015. Adjusted Revenues 4, which includes the impact of cash settled derivatives and excludes brokered natural gas and marketing revenue, totaled $59.0 million for the third quarter of 2016 compared to $71.3 million for the third quarter of 2015. Net loss for the third quarter of 2016 was $26.8 million, or ($0.10) per share. Adjusted Net Loss 4 for the third quarter of 2016 was $21.4 million, or ($0.08) per share. Adjusted EBITDAX 4 was $21.7 million for the third quarter of 2016.

4
 

Adjusted Revenue, Adjusted Net Loss and Adjusted EBITDAX are non-GAAP financial measures. Tables reconciling Adjusted Revenue, Adjusted Net 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 are set forth in the table below:
  Three Months Ended

September 30,
    Nine Months Ended

September 30,
2016     2015 2016     2015
Average Sales Price (excluding cash settled derivatives)
Natural gas ($/Mcf) $ 2.28 $ 2.86 $ 1.96 $ 2.76
NGLs ($/Bbl) 13.41 4.16 13.28 11.42
Oil ($/Bbl) 39.67 37.52 33.95 40.25
Total average prices ($/Mcfe) 2.67 2.99 2.34 3.26
 
Average Sales Price (including cash settled derivatives)
Natural gas ($/Mcf) $ 2.50 $ 3.50 $ 2.57 $ 3.42
NGLs ($/Bbl) 13.21 4.16 13.36 11.42
Oil ($/Bbl) 43.60 38.98 43.56 41.24
Total average prices ($/Mcfe) 2.89 3.44 2.94 3.71
 
Average Sales Price (including firm transportation)
Natural gas ($/Mcf) $ 1.77 $ 2.56 $ 1.49 $ 2.49
NGLs ($/Bbl) 13.41 4.16 13.28 11.42
Oil ($/Bbl) 39.67 37.52 33.95 40.25
Total average prices ($/Mcfe) 2.28 2.80 1.99 3.09
 
Average Sales Price (including cash settled derivatives and firm transportation)
Natural gas ($/Mcf) $ 2.00 $ 3.20 $ 2.10 $ 3.15
NGLs ($/Bbl) 13.21 4.16 13.36 11.42
Oil ($/Bbl) 43.60 38.98 43.56 41.24
Total average prices ($/Mcfe) 2.51 3.25 2.59 3.54
 

The Company's primary operating expenses decreased by 38% compared to the prior year's quarter and are shown below. Per unit cash production costs (includes lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.53 per Mcfe for the third quarter 2016.
  Three Months Ended

September 30,
    Nine Months Ended

September 30,
2016     2015 2016     2015
Operating expenses (in thousands):
Lease operating $ 2,186 $ 3,212 $ 7,111 $ 10,147
Transportation, gathering and compression 26,888 22,811 78,279 57,896
Production and ad valorem taxes 1,980 3,175 1,747 8,353
Depreciation, depletion and amortization 28,225 67,172 64,287 170,245
General and administrative 8,036 13,710 29,712 38,370
Operating expenses per Mcfe:
Lease operating $ 0.11 $ 0.16 $ 0.12 $ 0.19
Transportation, gathering and compression 1.32 1.10 1.30 1.09
Production, severance and ad valorem taxes 0.10 0.15 0.03 0.16
Depreciation, depletion and amortization 1.38 3.24 1.07 3.20
General and administrative 0.39 0.66 0.49 0.72
 

Capital Expenditures

Third quarter 2016 capital expenditures were $76.6 million. These expenditures included $67.3 million for drilling and completions (operated drilling and completions of $65.3 million and non-operated drilling and completions of $2.0 million), ($0.1) million for midstream expenditures, $9.3 million for land related expenditures, and $0.1 million for corporate related expenditures.

Financial Position and Liquidity

As of September 30, 2016, the Company's liquidity was $272 million consisting of $178 million in cash and cash equivalents and available borrowing capacity under the Company's revolving credit facility of $94 million (after giving effect to outstanding letters of credit issued by the Company of $31 million).

Subsequent to the end of the third quarter of 2016, the Company completed its semi-annual borrowing base redetermination process with the lending group under its revolving credit facility. Through that process, the lending group determined that the Company's borrowing base will remain at $125 million. The next borrowing base redetermination under the revolving credit facility is scheduled to occur in the spring of 2017 under the terms of the Company's credit agreement.

Matthew R. DeNezza, Executive Vice President and Chief Financial Officer, commented, "With the closing of our equity offering early in the quarter and the recent completion of our borrowing base redetermination, we continue to maintain a strong liquidity position based on a sizable, quarter end cash position of $178 million and an undrawn revolver with availability of over $90 million after giving effect to our currently outstanding letters of credit. We believe this liquidity position as well as our continued cash flow outperformance will create the foundation used to generate a robust growth profile as we move out of this year and into next."

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, natural gas liquids and oil prices. Below is a table that illustrates the Company's current hedging activities:
Description   Volume

(MMBtu/d)
    Production Period   Weighted Average

Price ($/MMBtu)
Natural Gas Swaps:  
65,000 September 2016 - December 2016 $ 3.28
10,000 January 2017 - December 2017 $ 2.98
Natural Gas Collars:
Floor purchase price (put) 30,000 September 2016 - December 2017 $ 3.00
Ceiling sold price (call) 30,000 September 2016 - December 2017 $ 3.50
Floor purchase price (put) 100,000 January 2017 - December 2017 $ 2.80
Ceiling sold price (call) 100,000 January 2017 - December 2017 $ 3.17
Floor purchase price (put) 20,000 January 2017 - December 2018 $ 2.90
Ceiling sold price (call) 20,000 January 2017 - December 2018 $ 3.25
Floor purchase price (put) 40,000 January 2018 - December 2018 $ 2.75
Ceiling sold price (call) 40,000 January 2018 - December 2018 $ 3.28
Natural Gas Three-way Collars:
Floor purchase price (put) 40,000 September 2016 - December 2016 $ 2.90
Ceiling sold price (call) 40,000 September 2016 - December 2016 $ 3.24
Floor sold price (put) 40,000 September 2016 - December 2016 $ 2.35
Floor purchase price (put) 30,000 January 2017 - December 2017 $ 2.75
Ceiling sold price (call) 30,000 January 2017 - December 2017 $ 3.57
Floor sold price (put) 30,000 January 2017 - December 2017 $ 2.25
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
 

Oil Derivatives
Description   Volume

(Bbls/d)
    Production Period   Weighted Average

Price ($/Bbl)
Oil Swaps:  
850

September 2016 - December 2016
$ 45.55
Oil Three-way Collars:
Floor purchase price (put) 1,000 September 2016 - December 2016 $ 60.00
Ceiling sold price (call) 1,000 September 2016 - December 2016 $ 70.10
Floor sold price (put) 1,000 September 2016 - December 2016 $ 45.00
Floor purchase price (put) 2,000 January 2017 - September 2017 $ 46.00
Ceiling sold price (call) 2,000 January 2017 - September 2017 $ 59.50
Floor sold price (put) 2,000 January 2017 - September 2017 $ 38.00
Floor purchase price (put) 2,000 January 2017 - December 2017 $ 46.00
Ceiling sold price (call) 2,000 January 2017 - December 2017 $ 60.00
Floor sold price (put) 2,000 January 2017 - December 2017 $ 38.00
Oil Call/Put Options:
Call sold 1,000 January 2018 - December 2018 $ 50.00
 

NGL Derivatives
Description   Volume

(Gal/d)
    Production Period   Weighted Average

Price ($/Gal)
Propane Swaps:  
42,000 September 2016 - December 2016 $ 0.46
10,500 September 2016 $ 0.46
 

Subsequent to September 30, 2016, the Company entered into the following derivative instruments:
Description   Volume

(MMbtu/d)
    Production Period   Weighted Average

Price ($/MMbtu)
Natural Gas Swaps:  
10,000 March 2017 - December 2017 $ 3.21
Natural Gas Three-way Collars:
Floor purchase price (put) 80,000 January 2018 - December 2018 $ 2.90
Ceiling sold price (call) 80,000 January 2018 - December 2018 $ 3.31
Floor sold price (put) 80,000 January 2018 - December 2018 $ 2.13
 

Guidance

The Company issued the following fourth quarter and amended full year 2016 guidance in the table below:
  Q4 2016     FY 2016
Production MMcfe/d 245 - 250 225 - 230
% Gas 70% - 75% 70% - 75%
% NGL 15% - 17% 16% - 18%
% Oil 10% - 12% 9% - 11%
Gas Price Differential ($/Mcf) 1 $(0.30) - $(0.35) $(0.35) - $(0.40)
Oil Differential ($/Bbl) 1 $(7.00) - $(9.00) $(8.00) - $(9.00)
NGL Prices (% of WTI) 1 35% - 40% 30% - 33%
Cash Production Costs ($/Mcfe) 2 $1.66 - $1.71 $1.51 - $1.56
Cash G&A ($mm) 3 $6.0 - $7.0 $30
CAPEX ($mm) $196
 

1.
 

Excludes impact of hedges and cost of firm transportation

2.

Includes lease operating, transportation, gathering and compression, production and ad valorem taxes. FT expense of $0.45-$0.50 per Mcfe for the fourth quarter and $0.35-$0.40 per Mcfe for the full year is reflected in this amount.

3.

Includes approximately $0.9 million of severance costs in the FY 2016 guidance estimate
 

Conference Call

A conference call to review the Company's financial and operational results for the third quarter of 2016 is scheduled for Friday, November 4, 2016 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 Third Quarter 2016 Earnings Call. A replay of the call will be available through January 4, 2017. To access the phone replay dial 877-660-6853 or 201-612-7415 for international callers. The conference ID is 13647741. 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. Additionally, Eclipse Resources has updated its investor presentation with third quarter 2016 financial and operational results. Please see the Investor Center of the Company's website at www.EclipseResources.com for the presentation entitled "Company Presentation - November 2016".

ECLIPSE RESOURCES CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS(In thousands, except share and per share amounts)(Unaudited)
   
September 30,

2016
December 31,

2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 177,669 $ 184,405
Accounts receivable 25,638 27,476
Assets held for sale 184 21,971
Other current assets   5,289   35,532
Total current assets 208,780 269,384
 
PROPERTY AND EQUIPMENT AT COST
Oil and natural gas properties, successful efforts method:
Unproved properties 578,212 720,159
Proved oil and gas properties, net 407,129 265,838
Other property and equipment, net   6,933   7,971
Total property and equipment, net 992,274 993,968
 
OTHER NONCURRENT ASSETS
Other assets 1,937 2,520
Deferred taxes     540
TOTAL ASSETS $ 1,202,991 $ 1,266,412
 
LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable $ 38,741 $ 34,717
Accrued capital expenditures 20,324 10,956
Accrued liabilities 21,229 25,462
Accrued interest payable 9,690 23,809
Liabilities held for sale     18,898
Total current liabilities 89,984 113,842
 
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs 491,593 527,248
Asset retirement obligations 4,599 3,401
Other liabilities   7,480   1,367
Total liabilities 593,656 645,858
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, 260,591,893 and 222,674,270 shares issued and outstanding, respectively
2,607 2,227
Additional paid in capital 1,958,043 1,829,082
Treasury stock, shares at cost; 72,704 at September 30, 2016 (61 )
Accumulated deficit   (1,351,254 )   (1,210,755 )
Total stockholders' equity   609,335   620,554
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,202,991 $ 1,266,412
 

ECLIPSE RESOURCES CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS(In thousands, except per share data)(Unaudited)
   

For the Three Months Ended September 30,

For the Nine Months Ended September 30,
2016   2015 2016   2015
REVENUES
Natural gas, oil and natural gas liquids sales $ 54,351 $ 61,928 $ 140,740 $ 173,526
Brokered natural gas and marketing revenue   128   9,244   10,411   15,913
Total revenues 54,479 71,172 151,151 189,439
 
OPERATING EXPENSES
Lease operating 2,186 3,212 7,111 10,147
Transportation, gathering and compression 26,888 22,811 78,279 57,896
Production and ad valorem taxes 1,980 3,175 1,747 8,353
Brokered natural gas and marketing expense 42 9,262 11,604 20,057
Depreciation, depletion and amortization 28,225 67,172 64,287 170,245
Exploration 12,083 3,244 45,183 22,940
General and administrative 8,036 13,710 29,712 38,370
Rig termination and standby (112 ) 174 3,843 7,597
Impairment of proved oil and gas properties 17,665
Accretion of asset retirement obligations 100 412 275 1,197
(Gain) loss on sale of assets   102   290   (944 )   (5,183 )
Total operating expenses   79,530   123,462   258,762   331,619
OPERATING LOSS (25,051 ) (52,290 ) (107,611 ) (142,180 )
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments 10,639 23,679 (8,407 ) 31,527
Interest expense, net (12,393 ) (11,774 ) (38,293 ) (40,196 )
Gain (loss) on early extinguishment of debt (59,392 ) 14,489 (59,392 )
Other income (expense)   4     (137 )   400
Total other expense, net   (1,750 )   (47,487 )   (32,348 )   (67,661 )
LOSS BEFORE INCOME TAXES (26,801 ) (99,777 ) (139,959 ) (209,841 )
INCOME TAX BENEFIT (EXPENSE)     18,309   (540 )   52,300
NET LOSS $ (26,801 ) $ (81,468 ) $ (140,499 ) $ (157,541 )
 
NET LOSS PER COMMON SHARE
Basic and diluted $ (0.10 ) $ (0.37 ) $ (0.60 ) $ (0.73 )
 
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic and diluted 258,812 222,537 234,933 216,332
 

Adjusted Revenue

Adjusted Revenue is a non-GAAP financial measure. The Company defines Adjusted Revenue as follows: total revenues plus cash settled derivatives less brokered 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

September 30,
2016   2015
Total revenues $ 54,479 $ 71,172

Net cash receipts (payments) on derivative instruments
4,612 9,332
Brokered natural gas and marketing   (128 )   (9,244 )
Adjusted revenue $ 58,963 $ 71,260
 

Adjusted Net Loss

Adjusted net income or loss represents income or loss before income taxes adjusted for certain non-cash items less income taxes. We believe adjusted net income or 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 Loss is not a measure of net income as determined by GAAP. See the table below for a reconciliation of Adjusted Net Loss and net loss.
 

Three Months Ended September 30,
 

Nine Months Ended September 30,
2016   2015 2016   2015
Loss before income taxes, as reported $ (26,801 ) $ (99,777 ) $ (139,959 ) $ (209,841 )
(Gain) loss on derivative instruments (10,639 ) (23,679 ) 8,407 (31,527 )
Net cash receipts (payments) on derivative instruments 4,612 9,332 35,870 23,754
Rig termination and standby (112 ) 174 3,843 7,597
Impairment of proved oil and gas properties - - 17,665 -
Dry hole and other 325 8 872 38
Stock based compensation 1,764 1,237 5,464 3,394
Impairment of unproved properties 9,360 1,037 28,080 7,080
Other (income) expense (4 ) - 137 (400 )
Gain on early extinguishment of debt - 59,392 (14,489 ) 59,392
Gain on sale of assets   102   290   (944 )   (5,183 )
Loss before income taxes, as adjusted (21,393 ) (51,986 ) (55,054 ) (145,696 )
Income tax benefit (expense)   -   18,309   (540 )   52,300
Adjusted net loss $ (21,393 ) $ (33,677 ) $ (55,594 ) $ (93,396 )
 
Adjusted net loss per Common Share $ (0.08 ) $ (0.15 ) $ (0.24 ) $ (0.43 )
 
Weighted Average Common Shares Outstanding 258,812 222,537 234,933 216,332
 

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 (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion and amortization ("DD&A"); amortization of deferred financing costs; 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. Adjusted EBITDAX is not a measure of net income as determined by GAAP. See the table below for a reconciliation of Adjusted EBITDAX to net loss.
  Three Months Ended

September 30,
  Nine Months Ended

September 30,
2016   2015   2016   2015
Net loss $ (26,801 ) $ (81,468 ) $ (140,499 ) $ (157,541 )
Depreciation, depletion and amortization 28,225 67,172 64,287 170,245
Exploration expense 12,083 3,244 45,183 22,940
Rig termination and standby (112 ) 174 3,843 7,597
Impairment of proved oil and gas properties 17,665
Stock-based compensation 1,764 1,237 5,464 3,394
Accretion of asset retirement obligations 100 412 275 1,197
(Gain) loss on derivative instruments (10,639 ) (23,679 ) 8,407 (31,527 )
Net cash receipts (payments) on settled derivatives 4,612 9,332 35,870 23,754
Interest expense, net 12,393 11,774 38,293 40,196
(Gain) loss on sale of assets 102 290 (944 ) (5,183 )
Gain on early extinguishment of debt 59,392 (14,489 ) 59,392
Other (income) expense (4 ) - 137 (400 )
Income tax (benefit) expense     (18,309 )   540   (52,300 )
Adjusted EBITDAX $ 21,723 $ 29,571 $ 64,032 $ 81,764
 

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.
 

For the Three Months Ended September 30, 2016
 

For the Three Months Ending December 31, 2016
 

For the Year Ending December 31, 2016
General and administrative expenses, as reported $ 8,036 $7 - $8 million $36 - $37 million
Stock-based compensation expense   (1,764 ) (1) - (2) million (6) - (7) million
Cash general and administrative expenses $ 6,272 $6 - $7 million $30 million
 

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 4, 2016 (the "2015 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; 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; general economic conditions; 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, 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 2015 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.

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