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Eclipse Resources Corporation Announces First Quarter 2017 Results: Higher Production, Production Guidance Raised, Operating Expense Guidance Reduced, Increased Utica Shale Dry Gas Type Curve and New 19,300 Foot “Super-Lateral” Drilled

Thursday, May 4, 2017 4:46 pm EDT

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 first quarter 2017 financial and operational results, along with updated guidance for the second quarter of 2017 and full year 2017. In conjunction with this release, the Company has posted an updated investor presentation to its website at www.eclipseresources.com with additional first quarter results and operational detail.

First Quarter 2017 Highlights:

  • Average net daily production was 290.0 MMcfe per day, exceeding the high end of the Company’s previously issued production guidance range of 275 to 280 MMcfe per day.
  • Realized an average natural gas price, before the impact of cash settled derivatives and firm transportation expenses, of $3.17 per Mcf, a $0.15 discount to the average monthly NYMEX settled natural gas price during the quarter.
  • Realized an average oil price, before the impact of cash settled derivatives, of $46.13 per barrel, a $5.49 per barrel discount to the average WTI oil price during the quarter, exceeding the Company’s previously issued oil differential guidance range of $7.50 to $8.50 per barrel.
  • Realized an average natural gas liquids (“NGL”) price, before the impact of cash settled derivatives, of $25.66 per barrel, or approximately 50% of the average WTI oil price during the quarter, beating the Company’s previously issued NGL differential guidance of 42% to 46% of the average WTI oil price.
  • Per unit cash production costs (including lease operating, transportation, gathering and compression, production and ad valorem taxes) were $1.43 per Mcfe and include $0.42 per Mcfe in firm transportation expenses, which was below the Company’s previously issued operating expense guidance range of $1.65 to $1.70 per Mcfe.
  • Net income for the first quarter of 2017 was $26.8 million; Adjusted EBITDAX1 for the first quarter of 2017 was $50.2 million.

Subsequent to the end of the First Quarter:

  • The Company updated its Utica Dry Gas type curve assumptions, resulting in an increase in EUR of approximately 13% to approximately 2.2 Bcf per 1,000 foot of lateral based on the results of extended flow testing on its completed Dry Gas Utica Shale wells using the Company’s “Gen3” completion design, which is expected to generate a before tax internal rate of return of approximately 70% at today’s forward natural gas strip pricing.
  • The Company successfully drilled its newest record setting “Super-Lateral” well, the Great Scott 3H, with a total measured depth of 27,400 feet and completable lateral extension of 19,300 feet in less than 17 days from spud to TD in the Company’s Utica Shale Condensate area.
  • The Company completed drilling its first of two planned Marcellus Shale Condensate wells with a completable lateral extension of 10,000 feet.
  • The Company finished completions operations on a seven well Dry Gas Utica pad testing several innovative “Gen4” completion techniques, including testing increased proppant levels, diversion chemicals and engineered frack stages.
  • The Company issued second quarter 2017 production and expense guidance and updated its full year production and expense guidance, resulting in an increase in its expected average daily production guidance range for 2017 to between 315 and 320 MMcfe per day and a reduction in its 2017 per unit operating expenses for 2017 to between $1.40 and $1.50 per Mcfe.
             

1

 

Non-GAAP measure. See reconciliation for details

 

Benjamin W. Hulburt, Chairman, President and CEO, commented on the Company’s first quarter 2017 results, “This was another tremendous quarter for us as we continued our track record of exceeding production expectations, while expanding our operating margin by keeping our per unit operating expenses and our general & administrative expenses low. This now marks the tenth consecutive reporting period in which the Company has met or exceeded its production and operating expense guidance, continuing our streak representing every single reporting period since our initial public offering in June of 2014.

We have increased our Utica Dry Gas type curve expectations as a result of the outperformance we have seen to date on our recent Dry Gas type curve area wells. These wells utilized our “Gen3” completion design and managed pressure drawdown methodology. The Utica Dry Gas type curve area EUR has increased to 2.2 Bcfe per 1,000 foot of lateral or by approximately 13%. The “Gen3” Dry Gas wells we have tested to date are projected to exceed this new type curve EUR, as they are on the eastern side of our Utica Shale Dry Gas acreage, while our Utica Shale Dry Gas type curve is intended to represent the mid-point of expected results rather than the highest possible recovery we believe is possible. However, as excited as we are with these results, we continue to strive to be a leader in innovation in our region. As such, we have commenced a series of trials on what may become our “Gen4” completion design. These approaches include testing combinations of tighter stages, higher proppant intensity, engineered stage lengths and the use of diversion chemicals, all of which were tested on a recently completed seven well Dry Gas Utica pad that is expected to begin turning to sales at the end of the second quarter. Because of the need to take several producing wells offline due to offsetting completion activities and the timing of the turn to sales of these new “Gen4” wells at the very end of the second quarter, we expect second quarter production to be down relative to the first and to achieve very strong production growth as we move into the third and fourth quarters. This was part of our annual plan and as you can see from our updated guidance, we now expect to achieve full year production levels that are in excess of our previously issued guidance.

Our second operated rig commenced drilling at the end of the first quarter 2017 and we now have a rig again focused on our Utica Condensate type curve area as our team continues to demonstrate its operational excellence in the Appalachian basin. In the Utica Condensate area, I am extremely happy to announce that we successfully drilled what we believe is the world’s longest onshore lateral ever drilled with a total measured depth of 27,400 feet and completable lateral extension of 19,300 feet, almost 1,000 feet longer than the previous record held by our Purple Hayes well. Remarkably, our team drilled this well in less than 17 days from spud to TD. We are currently drilling a direct offset to this well with a similar planned lateral extension and expect to begin completions on these exciting wells late in the third quarter of this year. Additionally, we have drilled the first of two planned Marcellus Condensate wells with a completable lateral extension of 10,000 feet and are currently drilling the second, along with three Utica Dry Gas wells on the same pad. Considering the catalysts we discussed at our analyst day early in the year, we are tracking at or better than planned and remain excited for continued operational improvement and value enhancements from our assets.”

Operational Discussion

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

  Three Months Ended

March 31,

2017     2016
Production:    
Natural gas (MMcf) 19,381.6 13,687.3
NGL sales (Mbbls) 665.0 513.7
Oil sales (Mbbls) 454.1 255.3
Total (MMcfe) 26,096.2 18,301.3
 
Average daily production volume:
Natural gas (Mcf/d) 215,351 150,410
NGL sales (Bbls/d) 7,389 5,645
Oil sales (Bbls/d) 5,046 2,805
Total (Mcfe/d) 289,958 201,113
 

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, high, low and average monthly settled NYMEX Henry Hub prices for natural gas and NYMEX WTI prices for oil for the three months ended March 31, 2017 and 2016:

  Three Months Ended

March 31,

2017     2016
NYMEX Henry Hub High ($/MMBtu) $ 3.71 $ 2.54
NYMEX Henry Hub Low ($/MMBtu) 2.44 1.49
Average Daily NYMEX Henry Hub ($/MMBtu) 3.02 2.02
Average Monthly NYMEX Settled Henry Hub ($/MMBtu) 3.32 2.09
 
NYMEX WTI High ($/Bbl) $ 54.48 $ 41.45
NYMEX WTI Low ($/Bbl) 47.00 26.19
Average NYMEX WTI ($/Bbl) 51.62 33.67
 

Financial Discussion

Revenue for the first quarter of 2017 totaled $101.9 million, compared to $49.6 million for the first quarter of 2016. Adjusted Revenue2, which includes the impact of cash settled derivatives and excludes brokered natural gas and marketing revenue, totaled $95.4 million for the first quarter of 2017 compared to $58.9 million for the first quarter of 2016. Net Income for the first quarter of 2017 was $26.8 million, or $0.10 per share compared to a net loss of $45.5 million or $0.20 per share for the first quarter of 2016. Adjusted Net Income2 for the first quarter of 2017 was $4.8 million, or $0.02 per share. Adjusted EBITDAX2 was $50.2 million for the first quarter of 2017.

       

2

 

Adjusted Revenue, Adjusted Net Income and Adjusted EBITDAX are non-GAAP financial measures. Tables reconciling Adjusted Revenue, Adjusted Net Income 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 ended March 31, 2017 and 2016 are set forth in the table below:

  Three Months Ended

March 31,

2017     2016

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

Natural gas ($/Mcf) $ 3.17 $ 2.05
NGLs ($/Bbl) 25.66 12.70
Oil ($/Bbl) 46.13 23.21
Total average prices ($/Mcfe) 3.81 2.21
 

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

Natural gas ($/Mcf) $ 3.01 $ 2.93
NGLs ($/Bbl) 24.07 13.43
Oil ($/Bbl) 46.28 46.42
Total average prices ($/Mcfe) 3.66 3.20
 

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

Natural gas ($/Mcf) $ 2.60 $ 1.61
NGLs ($/Bbl) 25.66 12.70
Oil ($/Bbl) 46.13 23.21
Total average prices ($/Mcfe) 3.39 1.88
 

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

Natural gas ($/Mcf) $ 2.44 $ 2.49
NGLs ($/Bbl) 24.07 13.43
Oil ($/Bbl) 46.28 46.42
Total average prices ($/Mcfe) 3.23 2.89
 

The Company’s operating expenses per Mcfe for the first quarter of 2017 decreased by 6% 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 $1.43 per Mcfe for the first quarter 2017 and includes $0.42 per Mcfe of firm transportation expenses.

  Three Months Ended

March 31,

2017     2016
Operating expenses (in thousands):
Lease operating $ 2,343 $ 2,677
Transportation, gathering and compression 32,877 23,137
Production and ad valorem taxes 1,931 2,563
Depreciation, depletion and amortization 26,189 15,113
General and administrative 10,132 11,274
Operating expenses per Mcfe:
Lease operating $ 0.09 $ 0.15
Transportation, gathering and compression 1.27 1.26
Production, severance and ad valorem taxes 0.07 0.14
Depreciation, depletion and amortization 1.00 0.83
General and administrative 0.39 0.62
 

Capital Expenditures

First quarter 2017 capital expenditures were $78.7 million. These expenditures included $55.0 million for drilling and completions, $2.5 million for midstream expenditures, $21.0 million for land-related expenditures, and $0.2 million for corporate-related expenditures.

During the first quarter 2017, the Company drilled 4 gross (3.9 net) operated Utica Shale wells, all of which were in the Dry Gas type curve area. In addition, the Company completed 7 gross (7.0 net) wells and turned to sales 5 gross (4.7 net) wells.

Financial Position and Liquidity

As of March 31, 2017, the Company’s liquidity was $301.9 million, consisting of $160.5 million in cash and cash equivalents and $141.4 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).

As previously announced, 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 to January 2020. The Company remains undrawn on its revolving credit facility, other than for letters of credit.

Matthew R. DeNezza, Executive Vice President and Chief Financial Officer, commented, “As we continue to increase our activity levels with the addition of the second operated rig, we remain focused on our liquidity and balance sheet strength. At quarter end, our liquidity was approximately $302 million, and included a cash position of approximately $161 million and undrawn revolver availability of approximately $141 million. From a gas marketing perspective, the Company has continued to work to maximize realized pricing through our access to both in and out of basin markets, and we are pleased to see the improvement in Appalachian basis differentials which we had predicted would occur as new transportation capacity is now coming on line.”

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 March 31, 2017:

Natural Gas Derivatives

Description   Volume

(MMBtu/d)

    Production Period   Weighted Average

Price ($/MMBtu)

Natural Gas Swaps:  
10,000 April 2017 – December 2017 $ 2.98
10,000 March 2017 – December 2017 $ 3.21
Natural Gas Collars:
Floor purchase price (put) 60,000 April 2017 – December 2017 $ 2.75
Ceiling sold price (call) 60,000 April 2017 – December 2017 $ 3.27
Floor purchase price (put) 20,000 April 2017 – December 2018 $ 2.90
Ceiling sold price (call) 20,000 April 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) 30,000 April 2017 – December 2017 $ 2.75
Ceiling sold price (call) 30,000 April 2017 – December 2017 $ 3.57
Floor sold price (put) 30,000 April 2017 – December 2017 $ 2.25
Floor purchase price (put) 50,000 April 2017 – December 2017 $ 3.00
Ceiling sold price (call) 50,000 April 2017 – December 2017 $ 3.40
Floor sold price (put) 50,000 April 2017 – December 2017 $ 2.25
Floor purchase price (put) 20,000 April 2017 – December 2017 $ 2.75
Ceiling sold price (call) 20,000 April 2017 – December 2017 $ 3.29
Floor sold price (put) 20,000 April 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) 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) 20,000 January 2018 – December 2018 $ 2.90
Ceiling sold price (call) 20,000 January 2018 – December 2018 $ 3.50
Floor sold price (put) 20,000 January 2018 – December 2018 $ 2.20
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 April 2017 – December 2017 $ (0.19 )
Appalachia - Dominion 40,000 June 2017 – November 2017 $ (1.01 )
Appalachia - Dominion 20,000 May 2017 – November 2017 $ (1.04 )
 

Oil Derivatives

Description   Volume

(Bbls/d)

    Production Period   Weighted Average

Price ($/Bbl)

Oil Swaps:  
Floor purchase price (put) 2,000 April 2017 – September 2017 $ 46.00
Ceiling sold price (call) 2,000 April 2017 – September 2017 $ 59.50
Floor sold price (put) 2,000 April 2017 – September 2017 $ 38.00
Floor purchase price (put) 2,000 April 2017 – December 2017 $ 46.00
Ceiling sold price (call) 2,000 April 2017 – December 2017 $ 60.00
Floor sold price (put) 2,000 April 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 April 2017 – December 2017 $ 0.60
 

Subsequent to March 31, 2017, the Company entered into the following derivative instruments:

Description   Volume

(MMbtu/d)

    Production Period   Weighted Average

Price ($/MMbtu)

Natural Gas Swaps:  
30,000 October 2017 – March 2018 $ 3.46
 

Guidance

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

  Q2 2017     FY 2017
Production MMcfe/d 265 - 275 315 - 320
% Gas 73% - 77% 77% - 82%
% NGL 14% - 16% 9% - 14%
% Oil 9% - 11% 7% - 11%
Gas Price Differential ($/Mcf)1,2 $(0.15) - $(0.20) $(0.25) - $(0.35)
Oil Differential ($/Bbl)1 $(6.50) - $(7.50) $(6.50) - $(7.50)
NGL Prices (% of WTI)1 30% - 35% 33% - 38%
Cash Production Costs ($/Mcfe)3 $1.45 - $1.50 $1.40 - $1.50
Cash G&A ($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 first quarter 2017 earnings is scheduled for Friday, May 5, 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 First Quarter Earnings Call. A replay of the call will be available through June 5, 2017. To access the phone replay dial 877-660-6853 or 201-612-7415 for international callers. The conference ID is 13660399. 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)

   
March 31,

2017

December 31,

2016

ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 160,458 $ 201,229
Accounts receivable 33,823 44,423
Assets held for sale 468 468
Other current assets   3,352   4,295
Total current assets 198,101 250,415
 
PROPERTY AND EQUIPMENT AT COST
Oil and natural gas properties, successful efforts method:
Unproved properties 513,314 526,270
Proved oil and gas properties, net 476,676 414,482
Other property and equipment, net   6,433   6,748
Total property and equipment, net 996,423 947,500
 
OTHER NONCURRENT ASSETS
Other assets   5,766   729
TOTAL ASSETS $ 1,200,290 $ 1,198,644
 
LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES
Accounts payable $ 51,472 $ 44,049
Accrued capital expenditures 14,769 11,083
Accrued liabilities 38,864 55,044
Accrued interest payable 9,823 21,098
Liabilities held for sale   245   245
Total current liabilities 115,173 131,519
 
NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs 492,964 492,278
Asset retirement obligations 5,054 4,806
Other liabilities   3,270   13,434
Total liabilities 616,461 642,037
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, 262,239,978 and 260,591,893 shares issued and outstanding, respectively

2,631 2,607
Additional paid in capital 1,960,788 1,958,731
Treasury stock, shares at cost; 837,635 and 72,704 shares, respectively (1,767 ) (61 )
Accumulated deficit   (1,377,823 )   (1,404,670 )
Total stockholders' equity   583,829   556,607
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,200,290 $ 1,198,644
 

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

 
For the Three Months Ended March 31,
2017   2016
REVENUES
Natural gas, oil and natural gas liquids sales $ 99,432 $ 40,488
Brokered natural gas and marketing revenue   2,431   9,118
Total revenues 101,863 49,606
 
OPERATING EXPENSES
Lease operating 2,343 2,677
Transportation, gathering and compression 32,877 23,137
Production and ad valorem taxes 1,931 2,563
Brokered natural gas and marketing expense 2,460 9,402
Depreciation, depletion and amortization 26,189 15,113
Exploration 11,581 15,656
General and administrative 10,132 11,274
Rig termination and standby 2,663
Impairment of proved oil and gas properties 17,665
Accretion of asset retirement obligations 124 86
(Gain) loss on sale of assets   (5 )   (22 )
Total operating expenses   87,632   100,214
OPERATING INCOME (LOSS) 14,231 (50,608 )
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments 25,097 10,550
Interest expense, net (12,462 ) (13,461 )
Gain (loss) on early extinguishment of debt 8,664
Other income (expense)   (19 )   (139 )
Total other expense, net   12,616   5,614
INCOME (LOSS) BEFORE INCOME TAXES 26,847 (44,994 )
INCOME TAX BENEFIT (EXPENSE)     (540 )
NET INCOME (LOSS) $ 26,847 $ (45,534 )
 
NET INCOME (LOSS) PER COMMON SHARE
Basic $ 0.10 $ (0.20 )
Diluted $ 0.10 $ (0.20 )
 
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic 261,105 222,784
Diluted 264,215 222,784
 

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 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

March 31,

2017   2016
Total revenues $ 101,863 $ 49,606

Net cash receipts (payments) on derivative instruments

(3,989 ) 18,378
Brokered natural gas and marketing revenue   (2,431 )   (9,118 )
Adjusted revenue $ 95,443 $ 58,866
 

Adjusted Net Income

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

  Three Months Ended March 31,
2017   2016
Income (loss) before income taxes, as reported $ 26,847 $ (44,994 )
(Gain) loss on derivative instruments (25,097 ) (10,550 )
Net cash receipts (payments) on derivative instruments (3,989 ) 18,378
Rig termination and standby 2,663
Impairment of proved oil and gas properties 17,665
Dry hole and other 864 37
Stock-based compensation 2,081 1,473
Impairment of unproved properties 4,125 9,360
Other (income) expense 19 139
Gain on early extinguishment of debt (8,664 )
(Gain) loss on sale of assets   (5 )   (22 )
Loss before income taxes, as adjusted 4,845 (14,515 )
Income tax benefit (expense)     (540 )
Adjusted net income (loss) $ 4,845 $ (15,055 )
 
Net income (loss) per Common Share
Basic $ 0.10 $ (0.20 )
Diluted $ 0.10 $ (0.20 )
 
Adjusted net income (loss) per Common Share
Basic $ 0.02 $ (0.07 )
Diluted $ 0.02 $ (0.07 )
 
Weighted Average Common Shares Outstanding
Basic 261,105 222,784
Diluted 264,215 222,784
 

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

March 31,

2017   2016
Net income (loss) $ 26,847 $ (45,534 )
Depreciation, depletion and amortization 26,189 15,113
Exploration expense 11,581 15,656
Rig termination and standby 2,663
Impairment of proved oil and gas properties 17,665
Stock-based compensation 2,081 1,473
Accretion of asset retirement obligations 124 86
(Gain) loss on derivative instruments (25,097 ) (10,550 )
Net cash receipts (payments) on settled derivatives (3,989 ) 18,378
Interest expense, net 12,462 13,461
(Gain) loss on sale of assets (5 ) (22 )
Gain (loss) on early extinguishment of debt (8,664 )
Other (income) expense 19 139
Income tax (benefit) expense     540
Adjusted EBITDAX $ 50,212 $ 20,404
 

Cash General and Administrative Expenses

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

        Guidance
$ thousands

For the Three
Months Ended
March 31, 2017

For the Three Months
Ending June 30, 2017

   

For the Year Ending
December 31, 2017

General and administrative expenses, estimated to be reported

$ 10,132 $10,500-$12,500 $44,500-$47,500
Stock-based compensation expense   (2,081 ) (2,000-3,000) (9,500-10,500)
Cash general and administrative expenses $ 8,051 $8,500-$9,500 $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 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; 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 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.

Contact:

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

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