Eclipse Resources Corporation Announces Fourth Quarter 2016 and Full Year 2016 Financial and Operational Results

Tuesday, February 28, 2017 5:24 pm EST

Dateline:

STATE COLLEGE, Pa.

Public Company Information:

NYSE:
ECR

STATE COLLEGE, Pa.--(BUSINESS WIRE)--Eclipse Resources Corporation (NYSE:ECR) (the “Company” or “Eclipse Resources”) today announced its fourth quarter and full year 2016 financial and operational results, as well as issued updated guidance for the first quarter of 2017 and full year 2017.

Fourth Quarter 2016 Highlights:

  • Average net daily production was 255.3 MMcfe per day, exceeding the high end of the Company’s previously issued production guidance.
  • Realized an average natural gas price, before the impact of cash settled derivatives and firm transportation expenses, of $2.88 per Mcf, a $0.16 discount to the average NYMEX natural gas prices during the quarter, exceeding the Company’s previously issued natural gas differential guidance.
  • Realized an average oil price, before the impact of cash settled derivatives, of $44.51 per barrel, a $4.63 per barrel discount to the average WTI oil price during the quarter, exceeding the Company’s previously issued oil differential guidance.
  • Realized an average natural gas liquids (“NGL”) price, before the impact of cash settled derivatives, of $21.22 per barrel, or approximately 43% of the average WTI oil price during the quarter, beating the Company’s previously issued NGL price differential guidance.
  • Per unit cash production costs (including lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.54 per Mcfe and includes $0.41 per Mcfe of firm transportation expenses, which was below the Company’s previously issued operating expense guidance.
  • Net loss for the fourth quarter of 2016 was $63.3 million; Adjusted EBITDAX1 for the fourth quarter of 2016 was $41.3 million.
  • Capital expenditures were $57.8 million. These expenditures included $49.6 million for drilling and completions, $1.7 million for midstream expenditures, $6.0 million for land-related expenditures, and $0.5 million for corporate-level expenditures.

Full Year 2016 Highlights:

  • Average net daily production was 228.6 MMcfe per day, exceeding the midpoint of the Company’s previously issued production guidance.
  • Realized an average natural gas price, before the impact of cash settled derivatives and firm transportation expenses, of $2.21 per Mcf, a $0.31 discount to the average NYMEX natural gas prices during the year, exceeding the Company’s previously issued natural gas differential guidance.
  • Realized an average oil price, before the impact of cash settled derivatives, of $37.35 per barrel, a $5.94 per barrel discount to the average WTI oil price during the year, beating the Company’s previously issued oil differential guidance.
  • Realized an average natural gas liquids price, before the impact of cash settled derivatives, of $15.62 per barrel, or approximately 36% approximately of the average WTI oil price during the year, exceeding the Company’s previously issued NGL differential guidance.
  • Per unit cash production costs (including lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.48 per Mcfe and includes $0.36 per Mcfe of firm transportation expenses, which was below the Company’s previously issued operating expense guidance.
  • Net loss for the year was $203.8; Adjusted EBITDAX1 for the year was $105.0 million
  • Capital expenditures were $176.9 million. These expenditures included $150.5 million for drilling and completions, $3.9 million for midstream expenditures, $21.5 million for land-related expenditures, and $1.0 million for corporate-related expenditures
  • Proved Reserves grew 35% over the previous year to approximately 469 Bcfe at SEC pricing and 108% over the previous year to approximately 1.22 Tcfe at forward NYMEX strip pricing; Finding and Development costs for the year fell to $0.70 per Mcfe, utilizing drilling and completion costs, and to $0.91 per Mcfe including all capital uses.

Subsequent to the end of the Fourth Quarter:

  • The Company completed its borrowing base redetermination of its revolving credit facility, which resulted in an increase in its borrowing base from $125 million to $175 million, and extended the maturity of its revolving credit facility from January 2018 to January 2020. 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 basis hedges of 60,000 MMBtu per day.
    • The Company has approximately 226,000 MMBtu per day of 2017 natural gas production hedged at an average floor price2 of $2.87 and an average ceiling price of $3.35.
    • The Company has an average of approximately 3,500 barrels per day of 2017 oil production hedged, or approximately 75% of its expected oil production for 2017, at an average floor price2 of $46.00 and an average ceiling price of $59.79.
    • The Company has 190,000 MMBtu per day of 2018 natural gas production hedged at an average floor price2 of $2.88 and an average ceiling price of $3.37.

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 fourth quarter and full year 2016 results, “During the fourth quarter, we were able to once again set record production levels for the Company while keeping our per unit operating expenses below our previously announced guidance range. This now marks the ninth consecutive reporting period in which the Company has met or exceeded its production and operating expense guidance, representing every reporting period the Company had since our initial public offering in June of 2014.

As we highlighted in our analyst day, we recently increased our type curve expectations in our Utica Shale Condensate and Rich Gas areas as a result of the outperformance we have seen to date on the wells which were completed with our “Gen3” completion design in these areas. Although we have not yet increased our Utica Shale Dry Gas type curve, our first “Gen3” pad in the Utica Shale Dry Gas area continues to produce at an average rate of approximately 30% above our Utica Dry Gas type curve using our managed pressure drawdown methodology. Largely as a result of the performance of our “Gen3” producing wells, we have increased our first quarter 2017 production guidance to between 275 and 280 MMcfe per day.

As 2017 continues to unfold, we will again endeavor to lower our cost structure and build on our accomplishments. During 2017, we plan to drill 24 wells with an average lateral length of approximately 13,300, eleven of which are expected to be “Super-Laterals” with lateral extensions exceeding 15,000 feet. 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 by negotiating lower day rates on our drilling rigs and locking in flat-to-modest increases on our pressure pumping and proppant costs for the next two years.

Despite a significant amount of volatility during the quarter in natural gas prices, we have again been able to deliver a strong natural gas realized price, exceeding our guidance for both the fourth quarter 2016 and the full year 2016. We have also taken advantage of this volatility by adding to our 2018 hedge portfolio as prices allowed, with the goal of retaining upside participation if the natural gas price increases. Lastly, I’m very happy to announce we have negotiated a new condensate marketing contract which fixes our discount to the West Texas Intermediate price for the period beginning in April of this year through the end of 2018, and as a consequence, we have updated our annual oil price differential guidance resulting in an estimated improvement on our oil differentials of approximately 15%.”

Operational Discussion

The Company’s production for the three months and years ended December 31, 2016 and 2015 is set forth in the following table:

  Three Months Ended

December 31,

    Year Ended

December 31,

2016     2015 2016     2015
Production:        
Natural gas (MMcf) 16,563.9 15,814.0 60,921.9 49,477.6
NGL sales (Mbbls) 721.1 709.9 2,446.2 2,450.3
Oil sales (Mbbls) 433.4 442.3 1,343.8 1,950.5
Total (MMcfe) 23,490.9 22,727.2 83,661.9 75,882.4
 
Average daily production volume:
Natural gas (Mcf/d) 180,042 171,891 166,453 135,555
NGL sales (Bbls/d) 7,838 7,716 6,684 6,713
Oil sales (Bbls/d) 4,711 4,808 3,672 5,344
Total (Mcfe/d) 255,336 247,035 228,589 207,897
 

Financial Discussion

Revenues for the fourth quarter of 2016 totaled $83.9 million, compared to $65.9 million for the fourth quarter of 2015. Adjusted Revenues4, which includes the impact of cash settled derivatives and excludes brokered natural gas and marketing revenue, totaled $85.1 million for the fourth quarter of 2016 compared to $74.4 million for the fourth quarter of 2015. Net loss for the fourth quarter of 2016 was $63.3 million, or $(0.23) per share. Adjusted Net Loss4 for the fourth quarter of 2016 was $5.7 million, or $(0.02) per share. Adjusted EBITDAX4 was $41.3 million for the fourth quarter of 2016.

Revenues for the full year 2016 totaled $235.0 million, compared to $255.3 million for the full year 2015. Adjusted Revenues4, which includes the impact of cash settled derivatives and excludes brokered natural gas and marketing revenue, totaled $261.7 million for the full year 2016 compared to $271.7 million for the full year 2015. Net loss for the full year 2016 was $203.8 million, or $(0.84) per share. Adjusted Net Loss4 for the full year 2016 was $61.6 million, or $(0.26) per share. Adjusted EBITDAX4 was $105.0 million for the full year 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 for the three months and years ended December 31, 2016 and 2015 are set forth in the table below:

  Three Months Ended

December 31,

    Year Ended

December 31,

2016     2015 2016     2015
Average Sales Price (excluding cash settled derivatives)
Natural gas ($/Mcf) $ 2.88 $ 2.32 $ 2.21 $ 2.62
NGLs ($/Bbl) 21.22 14.50 15.62 12.32
Oil ($/Bbl) 44.51 32.03 37.35 38.38
Total average prices ($/Mcfe) 3.50 2.69 2.67 3.09
 
Average Sales Price (including cash settled derivatives)
Natural gas ($/Mcf) $ 3.00 $ 2.98 $ 2.69 $ 3.27
NGLs ($/Bbl) 20.78 14.50 15.55 12.32
Oil ($/Bbl) 46.97 38.25 44.66 40.92
Total average prices ($/Mcfe) 3.62 3.27 3.13 3.58
 
Average Sales Price (including firm transportation)
Natural gas ($/Mcf) $ 2.29 $ 1.99 $ 1.71 $ 2.31
NGLs ($/Bbl) 21.22 14.50 15.62 12.32
Oil ($/Bbl) 44.51 32.03 37.35 38.38
Total average prices ($/Mcfe) 3.09 2.46 2.30 2.89
 
Average Sales Price (including cash settled derivatives and firm transportation)
Natural gas ($/Mcf) $ 2.42 $ 2.65 $ 2.19 $ 2.95
NGLs ($/Bbl) 20.78 14.50 15.55 12.32
Oil ($/Bbl) 46.97 38.25 44.66 38.38
Total average prices ($/Mcfe) 3.21 3.04 2.76 3.38
 

The Company’s primary operating expenses per Mcfe for the fourth quarter of 2016 decreased by 39% compared to the prior year’s quarter 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 $1.54 per Mcfe for the fourth quarter 2016 and includes $0.41 per Mcfe of firm transportation expenses.

The Company’s primary operating expenses per Mcfe for the year ended December 31, 2016 decreased by 42% compared to the prior year’s and are shown below. Per unit cash production costs (includes lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.48 per Mcfe for the full year 2016 and includes $0.36 per Mcfe of firm transportation expenses.

  Three Months Ended

December 31,

    Year Ended

December 31,

2016     2015 2016     2015
Operating expenses (in thousands):
Lease operating $ 1,912 $ 3,757 $ 9,023 $ 13,904
Transportation, gathering and compression 30,947 27,950 109,226 85,846
Production and ad valorem taxes 3,251 3,268 4,998 11,621
Depreciation, depletion and amortization 28,661 74,505 92,948 244,750
General and administrative 9,719 8,039 39,431 46,409
Operating expenses per Mcfe:
Lease operating $ 0.08 $ 0.17 $ 0.11 $ 0.18
Transportation, gathering and compression 1.32 1.23 1.31 1.13
Production, severance and ad valorem taxes 0.14 0.14 0.06 0.15
Depreciation, depletion and amortization 1.22 3.28 1.11 3.23
General and administrative 0.41 0.35 0.47 0.61
 

Capital Expenditures

Fourth quarter 2016 capital expenditures were $57.8 million. These expenditures included $49.6 million for drilling and completions, $1.7 million for midstream expenditures, $6.0 million for land-related expenditures, and $0.5 million for corporate-related expenditures.

Full Year 2016 capital expenditures were $176.9 million. These expenditures included $150.5 million for drilling and completions, $3.9 million for midstream expenditures, $21.5 million for land-related expenditures, and $1.0 million for corporate-related expenditures.

Financial Position and Liquidity

Subsequent to the end of the fourth 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 increase from $125 million to $175 million, and extended the maturity of the Company’s revolving credit facility to January of 2020.

As of December 31, 2016, the Company’s pro forma liquidity was $341.7 million consisting of $201.2 million in cash and cash equivalents and available borrowing capacity under the Company’s revolving credit facility of $140.5 million (after giving effect to outstanding letters of credit issued by the Company of $34.5 million and pro forma the borrowing base redetermination).

Matthew R. DeNezza, Executive Vice President and Chief Financial Officer, commented, “With the closing of the asset divestiture late in the fourth quarter and our recent borrowing base redetermination, which resulted in a 40% borrowing base increase, we continue to maintain a strong liquidity position. At year end and pro forma for this recent redetermination, our liquidity was approximately $342 million, and included a cash position of approximately $201 million and undrawn revolver availability of approximately $141 million, after giving effect to outstanding letters of credit. We believe this liquidity position, as well as our internally generated cash flows, will allow us to fund our 2017 drilling program, which we anticipate will provide the groundwork for a 25% compound annual growth rate in production over the next three years.”

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, 2016:

Natural Gas Derivatives

Description   Volume

(MMBtu/d)

    Production Period   Weighted Average

Price ($/MMBtu)

Natural Gas Swaps:  
10,000 January 2017 – December 2017 $ 2.98
10,000 March 2017 – December 2017 $ 3.21
Natural Gas Collars:
Floor purchase price (put) 130,000 January 2017 – December 2017 $ 2.85
Ceiling sold price (call) 130,000 January 2017 – December 2017 $ 3.24
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 $ 3.27
Natural Gas Three-way Collars:
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
Floor purchase price (put) 30,000 April 2017 – March 2019 $ 3.00
Ceiling sold price (call) 30,000 April 2017 – March 2019 $ 3.40
Floor sold price (put) 30,000 April 2017 – March 2019 $ 2.20
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 $ 2.12
Floor purchase price (put) 20,000 October 2017 – December 2018 $ 2.90
Ceiling sold price (call) 20,000 October 2017 – December 2018 $ 3.50
Floor sold price (put) 20,000 October 2017 – December 2018 $ 2.20
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 January 2017 – December 2017 $ (0.19 )
 

Oil Derivatives

Description   Volume

(Bbls/d)

    Production Period   Weighted Average

Price ($/Bbl)

Oil Swaps:  
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:  
84,000 January 2017 – December 2017 $ 0.60
 

Subsequent to December 31, 2016, the Company entered into the following derivative instruments:

Description   Volume

(MMbtu/d)

    Production Period   Weighted Average

Price ($/MMbtu)

Natural Gas Call/Put Options:  
Call sold 60,000 January 2018 – March 2018 $ 3.75
Call purchased 60,000 January 2018 – March 2018 $ 3.25
Put sold 60,000 January 2018 – December 2018 $ 2.40
Put purchased 60,000 January 2018 – December 2018 $ 2.10
Call sold 50,000 April 2017 - December 2018 $ 3.40
Call purchased 50,000 April 2017 - December 2018 $ 3.20
Put sold 70,000 April 2017 - December 2018 $ 2.25
Basis Swaps:
Appalachia - Dominion 20,000 May 2017 – November 2017 $ (1.04 )
Appalachia - Dominion 40,000 June 2017 – November 2017 $ (1.01 )
 

Guidance

The Company issued the following first quarter and full year 2017 guidance in the table below:

  Q1 2017   FY 2017
Production MMcfe/d 275 - 280 305 - 315
% Gas 72% - 76% 77% - 82%
% NGL 14% - 16% 9% - 14%
% Oil 10% - 12% 7% - 11%
Gas Price Differential ($/Mcf)1,2 $0.05 - $(0.05) $(0.25) - $(0.35)
Oil Differential ($/Bbl)1 $(7.50) - $(8.50) $(6.50) - $(7.50)
NGL Prices (% of WTI)1 42% - 46% 33% - 38%
Cash Production Costs ($/Mcfe)3 $1.65 - $1.70 $1.45 - $1.55
Cash G&A ($mm)4 $8.5 - $9.5 $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.

5.

Excludes potential acquisitions and payments of approximately $17 million for land leased in 2016 and expected to be paid in 2017.

 

Conference Call

A conference call to review the Company’s financial fourth quarter 2016 and full-year 2016 earnings is scheduled for Wednesday, March 1, 2017, at 9:00 a.m. (Eastern). To participate in the call, please dial 877-709-8150, or 201-689-8354 for international callers, and reference Eclipse Resources Fourth Quarter and Full Year 2016 Earnings Call. A replay of the call will be available through May 3, 2017. To access the phone replay dial 877-660-6853 or 201-612-7415 for international callers. The conference ID is 13653954. 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)

   
December 31,

2016

December 31,

2015

ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 201,229 $ 184,405
Accounts receivable 43,638 27,476
Assets held for sale 468 21,971
Other current assets   4,295   35,532
Total current assets 249,630 269,384
 
PROPERTY AND EQUIPMENT AT COST
Oil and natural gas properties, successful efforts method:
Unproved properties 526,270 720,159
Proved oil and gas properties, net 414,482 265,838
Other property and equipment, net   6,748   7,971
Total property and equipment, net 947,500 993,968
 
OTHER NONCURRENT ASSETS
Other assets 729 2,520
Deferred taxes     540
TOTAL ASSETS $ 1,197,859 $ 1,266,412
 

LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES

Accounts payable $ 44,049 $ 34,717
Accrued capital expenditures 11,083 10,956
Accrued liabilities 64,150 25,462
Accrued interest payable 21,098 23,809
Liabilities held for sale   245   18,898
Total current liabilities 140,625 113,842
 
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs 492,278 527,248
Asset retirement obligations 4,806 3,401
Other liabilities   13,434   1,367
Total liabilities 651,143 645,858
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 1,958,731 1,829,082
Treasury stock, shares at cost; 72,704 shares at December 31, 2016 (61 )
Accumulated deficit   (1,414,561 )   (1,210,755 )
Total stockholders' equity   546,716   620,554
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,197,859 $ 1,266,412
 

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

   

For the Three Months
Ended December 31,

For the Year
Ended December 31,

2016   2015 2016   2015
REVENUES
Natural gas, oil and natural gas liquids sales $ 82,275 $ 61,075 $ 223,015 $ 234,601
Brokered natural gas and marketing revenue   1,608   4,807   12,019   20,720
Total revenues 83,883 65,882 235,034 255,321
 
OPERATING EXPENSES
Lease operating 1,912 3,757 9,023 13,904
Transportation, gathering and compression 30,947 27,950 109,226 85,846
Production and ad valorem taxes 3,251 3,268 4,998 11,621
Brokered natural gas and marketing expense 664 6,116 12,268 26,173
Depreciation, depletion and amortization 28,661 74,505 92,948 244,750
Exploration 7,592 93,271 52,775 116,211
General and administrative 9,719 8,039 39,431 46,409
Rig termination and standby 3 2,075 3,846 9,672
Impairment of proved oil and gas properties 691,334 17,665 691,334
Accretion of asset retirement obligations 116 426 391 1,623
(Gain) loss on sale of assets 7,880 446 6,936 (4,737 )
Gain on reduction of pension obligations        
Total operating expenses   90,745   911,187   349,507   1,242,806
OPERATING LOSS (6,862 ) (845,305 ) (114,473 ) (987,485 )
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments (43,931 ) 24,494 (52,338 ) 56,021
Interest expense, net (12,496 ) (13,204 ) (50,789 ) (53,400 )
Gain (loss) on early extinguishment of debt 14,489 (59,392 )
Other income (expense)   (12 )     (149 )   400
Total other expense, net   (56,439 )   11,290   (88,787 )   (56,371 )
LOSS BEFORE INCOME TAXES (63,301 ) (834,015 ) (203,260 ) (1,043,856 )
INCOME TAX BENEFIT (EXPENSE)   (6 )   20,146   (546 )   72,446
NET LOSS $ (63,307 ) $ (813,869 ) $ (203,806 ) $ (971,410 )
 
NET LOSS PER COMMON SHARE
Basic and diluted $ (0.23 ) $ (3.66 ) $ (0.84 ) $ (4.46 )
 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING

Basic and diluted 258,812 222,534 241,434 217,897
 

Adjusted Revenue

Adjusted Revenue is a non-GAAP financial measure. The Company defines Adjusted Revenue as follows: total revenues plus net cash receipts settled derivative instruments 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

December 31,

  For the Year Ended

December 31,

2016   2015 2016   2015
Total revenues $ 83,883 $ 65,882 $ 235,034 $ 255,321

Net cash receipts (payments) on derivative instruments

2,826 13,320 38,696 37,074
Brokered natural gas and marketing revenue   (1,608 )   (4,807 )   (12,019 )   (20,720 )
Adjusted revenue $ 85,101 $ 74,395 $ 261,711 $ 271,675
 

Adjusted Net Loss

Adjusted net loss represents loss before income taxes adjusted for certain non-cash items as set forth in the table below less income taxes. We believe adjusted net 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
December 31,

 

Year Ended
December 31,

2016   2015 2016   2015
Loss before income taxes, as reported $ (63,301 ) $ (834,015 ) $ (203,260 ) $ (1,043,856 )
(Gain) loss on derivative instruments 43,931 (24,494 ) 52,338 (56,021 )
Net cash receipts (payments) on derivative instruments 2,826 13,320 38,696 37,074
Rig termination and standby 3 2,075 3,846 9,672
Impairment of proved oil and gas properties - 691,334 17,665 691,334
Dry hole and other 156 365 1,029 511
Stock based compensation 1,049 1,241 6,216 4,635
Impairment of unproved properties 1,744 88,492 29,824 95,573
Other (income) expense 12 - 149 (400 )
Gain on early extinguishment of debt - - (14,489 ) 59,392
(Gain) loss on sale of assets   7,880   446   6,936   (4,737 )
Loss before income taxes, as adjusted (5,700 ) (61,236 ) (61,050 ) (206,823 )
Income tax benefit (expense)   (6 )   20,146   (546 )   72,446
Adjusted net loss $ (5,706 ) $ (41,090 ) $ (61,596 ) $ (134,377 )
 
Net loss per Common Share $ (0.23 ) $ (3.66 ) $ (0.84 ) $ (4.46 )
 
Adjusted net loss per Common Share $ (0.02 ) $ (0.18 ) $ (0.26 ) $ (0.62 )
 
Weighted Average Common Shares Outstanding 258,812 222,534 241,434 217,897
 

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 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 as determined by GAAP. See the table below for a reconciliation of Adjusted EBITDAX to net loss.

  Three Months Ended

December 31,

  Year Ended

December 31,

2016   2015   2016   2015
Net loss $ (63,307 ) $ (813,869 ) $ (203,806 ) $ (971,410 )
Depreciation, depletion and amortization 28,661 74,505 92,948 244,750
Exploration expense 7,592 93,271 52,775 116,211
Rig termination and standby 3 2,075 3,846 9,672
Impairment of proved oil and gas properties 691,334 17,665 691,334
Stock-based compensation 1,049 1,241 6,216 4,635
Accretion of asset retirement obligations 116 426 391 1,623
(Gain) loss on derivative instruments 43,931 (24,494 ) 52,338 (56,021 )
Net cash receipts (payments) on settled derivatives 2,826 13,320 38,696 37,074
Interest expense, net 12,496 13,204 50,789 53,400
(Gain) loss on sale of assets 7,880 446 6,936 (4,737 )
Gain (loss) on early extinguishment of debt (14,489 ) 59,392
Other (income) expense 12 - 149 (400 )
Income tax (benefit) expense   6   (20,146 )   546   (72,446 )
Adjusted EBITDAX $ 41,265 $ 31,313 $ 105,000 $ 113,077
 

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 Ending
December 31, 2016

 

For the Year Ending
December 31, 2016

General and administrative expenses, estimated to be reported $ 9,719 $ 39,431
Stock-based compensation expense   (1,049 )   (6,216 )
Cash general and administrative expenses $ 8,670 $ 33,215
 

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.

Contact:

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