Gastar Exploration Inc.
May 7, 2015

Gastar Exploration Announces First Quarter 2015 Results

- First Quarter Production Increased 30% Year-Over-Year to 12.6 MBoe/d
- Announced Improved Liquidity Through Agreement to Sell Non-Core Mid-Continent Assets

HOUSTON, May 7, 2015 /PRNewswire/ -- Gastar Exploration Inc. (NYSE MKT: GST) ("Gastar") today reported financial and operating results for the three months ended March 31, 2015.

Net loss attributable to Gastar's common stockholders as reported for the first quarter of 2015 was $3.0 million, or a loss of $0.04 per share.  Excluding a $4.3 million gain resulting from the mark-to-market of outstanding hedge positions, adjusted net loss attributable to common stockholders was $7.3 million, or a loss of $0.09 per share.  This compares to a first quarter 2014 reported net loss of $2.0 million, or a loss of $0.03 per share, a first quarter 2014 adjusted net income of $1.4 million, or $0.02 per diluted share, which excludes the impact of a $3.2 million loss resulting from the mark-to-market of outstanding hedge positions, $30,000 of acquisition costs and non-recurring corporate restructuring charges of $205,000 and a fourth quarter 2014 adjusted net income of $1.8 million, or $0.02 per diluted share, which excludes a $24.9 million gain resulting from the mark-to-market of outstanding hedge positions. (See the accompanying reconciliation of net loss to net income (loss) excluding special items at the end of this news release.)

Adjusted earnings before interest, income taxes, depreciation, depletion and amortization ("adjusted EBITDA") for the first quarter of 2015 was $20.0 million, a decrease of 23% compared to $25.9 million for both the first quarter of 2014 and the fourth quarter of 2014.  (See the accompanying reconciliation of net loss to adjusted EBITDA, a non-GAAP number, at the end of this news release.)

Revenues from oil, condensate, natural gas and natural gas liquids ("NGLs"), before the impact of hedging activities, declined 38% to $24.1 million in the first quarter of 2015 from $38.8 million in the first quarter of 2014 and decreased 27% from $33.1 million in the fourth quarter of 2014.  The decrease in oil, condensate, natural gas and NGLs revenues from first quarter of 2014 to first quarter of 2015 was primarily the result of a 52% decrease in weighted average realized equivalent prices partially offset by a 30% increase in production.  The decrease from fourth quarter of 2014 revenues was primarily due to a 31% decline in equivalent product pricing partially offset by an 8% increase in average daily production.

Revenues from liquids (oil, condensate and NGLs) represented approximately 72% of total production revenues in the first quarter of 2015, compared to 60% for the first quarter of 2014 and 77% during the fourth quarter of 2014.  We had commodity derivatives contracts in place covering approximately 56% of our natural gas production and 62% of our liquids production for the first quarter of 2015.  Commodity derivative contracts settled during the period resulted in a $6.0 million increase in revenue for the first quarter of 2015, compared to a reduction in revenue of $3.4 million for the first quarter of 2014 and an increase in revenue of $3.5 million for the fourth quarter of 2014.  First quarter 2015 hedge benefit enhanced our barrel of oil equivalent pricing by approximately 25%, while in the first quarter of 2014, it reduced our oil equivalient pricing by approximately 9%.  We continue to maintain an active hedging program covering a portion of estimated future production, which is reported in our periodic filings with the U.S. Securities and Exchange Commission ("SEC").

Average daily production for the first quarter of 2015 was 12,600 barrels of oil equivalent per day ("Boe/d") (on a 6:1 gas (Mcf) to liquids (barrel) equivalent basis) as compared to 9,700 Boe/d in the first quarter of 2014 and 11,700 Boe/d in the fourth quarter of 2014. Oil, condensate and NGLs as a percentage of total equivalent production volumes were 52% in the first quarter of 2015 compared to 41% in the first quarter of 2014 and 53% in the fourth quarter of 2014.

J. Russell Porter, Gastar's President and CEO, commented, "We are pleased with our first quarter operating results as they reflect our continued success in developing our Mid-Continent WEHLU acreage, as well as the contribution of wells recently completed in our Hunton AMI acreage and on our Appalachian Basin leasehold.  Our most recent WELHU wells are performing as expected or better, which reinforces our decision to focus our 2015 capital in an area that offers a solid rate of return and the opportunity to add substantial proven reserves.  We expect to continue to demonstrate impressive deliverability associated with our Utica/Point Pleasant assets by completing our second Utica/Point Pleasant well in Marshall County, West Virginia later this month."

"As announced yesterday, we are divesting 19,000 net acres of non-core leasehold in the Mid-Continent area.  This sale allows us to further enhance our liquidity position while retaining a strong acreage position with Hunton Limestone and Stack Play potential.  We are currently evaluating the possibility of drilling a Stack Play well in the Meramec Shale/Mississippi Lime formation later this year on our Mid-Continent acreage.  While we plan to maintain a conservative approach to our 2015 capital plan, we have been closely monitoring the success of other nearby operators targeting the Meramec Shale/Mississippi Lime formation and believe an operated drill test could help define the value of our Stack Play potential."

The following table provides a summary of Gastar's production volumes and average commodity prices for the three months ended March 31, 2015 and 2014:



For the Three Months Ended March 31,



2015


2014






Production:





Oil and condensate (MBbl)


367



203


Natural gas (MMcf)


3,295



3,072


NGLs (MBbl)


219



155


Total production (MBoe)


1,135



870







Daily Production:





Oil and condensate (MBbl/d)


4.1



2.3


Natural gas (MMcf/d)


36.6



34.1


NGLs (MBbl/d)


2.4



1.7


Total daily production (MBoe/d)


12.6



9.7







Average sales price per unit:





Oil and condensate per Bbl, including impact of hedging(1)


$

47.50



$

79.57


Oil and condensate per Bbl, excluding impact of hedging


$

41.82



$

82.61


Natural gas per Mcf, including impact of hedging(1)


$

2.58



$

4.34


Natural gas per Mcf, excluding impact of hedging


$

2.03



$

5.02


NGLs per Bbl, including impact of hedging(1)


$

19.10



$

38.63


NGLs per Bbl, excluding impact of hedging


$

9.58



$

42.79







Average sales price per Boe, including impact of hedging(1)


$

26.54



$

40.76


Average sales price per Boe, excluding impact of hedging


$

21.28



$

44.62













(1)

The impact of hedging includes the gain (loss) on commodity derivative contracts settled during the periods presented. 

 

Lease operating expenses ("LOE") were $6.0 million for the first quarter of 2015, versus $4.0 million in the first quarter of 2014 and $6.3 million in the fourth quarter of 2014. Compared to the first quarter of 2014, LOE in the first quarter of 2015 increased $2.0 million due to one-time workover costs of $1.4 million for production enhancement on five wells in our operated WEHLU acreage as well as higher frack water disposal costs associated with bringing new wells online and higher overall costs associated with producing oil versus natural gas.  Compared to the fourth quarter of 2014, LOE was down due to operating expense reduction initiatives regarding electrical submersible pump, or "ESP", conversions to rod pumps and lower AMI operating costs.  LOE per barrel of oil equivalent ("Boe") of production was $5.30 in the first quarter of 2015 versus $4.65 in the first quarter of 2014 and $5.83 in the fourth quarter of 2014.  Excluding workover costs, LOE per Boe for first quarter of 2015 was $4.09 compared to $4.65 per Boe for the first quarter of 2014 and $5.26 per Boe for the fourth quarter of 2014.

Depreciation, depletion and amortization expense ("DD&A") was $14.5 million in the first quarter of 2015, up from $12.4 million in both the first and fourth quarters of 2014.  The year-over-year increase in DD&A expense was the result of 30% higher production volumes partially offset by a 10% lower DD&A rate per Boe that resulted from higher year-end proved reserve volumes. DD&A increased sequentially due to an increase in the DD&A rate and higher production volumes in the first quarter of 2015. The DD&A rate per Boe for the first quarter of 2015 was $12.75 compared to $14.23 for the first quarter of 2014 and $11.53 in the fourth quarter of 2014.

General and administrative ("G&A") expense was $4.2 million in the first quarter of 2015 compared to $4.8 million in the first quarter of 2014 and $3.8 million in the fourth quarter of 2014. G&A expense for the first quarter of 2015 included $1.5 million of non-cash, stock-based compensation expense, consistent with the first quarter of 2014 and compared to $1.2 million in the fourth quarter of 2014.  Excluding stock-based compensation expense, cash G&A expense decreased to $2.7 million in the first quarter of 2015 from $3.2 million in the first quarter of 2014 and increased slightly from $2.6 million in the fourth quarter of 2014. The decrease from the first quarter of 2014 was primarily due to reduced legal costs.

Interest expense totaled $7.6 million in the first quarter of 2015, compared to $6.9 million in the first quarter of 2014 and $6.8 million in the fourth quarter 2014.  The increase was the result of additional interest and charges related to increased borrowings under our revolving credit facility.

Operations Review and Update

Mid-Continent

Net production from the Mid-Continent area increased to an average of 5,900 Boe/d in the first quarter of 2015, compared to 3,300 Boe/d in the first quarter of 2014 and 5,600 Boe/d in the fourth quarter of 2014.  First quarter 2015 Mid-Continent equivalent production consisted of approximately 57% oil, 25% natural gas and 18% NGLs.

Within our AMI acreage, six gross (3.1 net) non-operated wells were placed on production during the first quarter of 2015.  We expect to complete and bring on production a total of four gross (2.0 net) wells in the second quarter of 2015, of which two gross (1.1 net) non-operated wells have already been placed on production.

The table below shows wells brought on production or for which drilling operations have commenced since the beginning of the first quarter of 2015 within our original AMI in the Hunton Limestone formation (all of which are operated by our joint venture partner):









Cumulative Production
Averages(2)





Well Name


Current
Working
Interest


Approximate
Lateral
Length
(in feet)


Peak
Production
Rates(1)
(Boe/d)


Boe/d


% Oil


Date of First
Production or
Status


Approximate
Gross Costs
to Drill &
Complete
($ millions)
















LB 1-1H


47.6%


4,400


791


356


69%


January 23, 2015


$5.0

Boss Hogg 1-14H


54.3%


4,400


129


68


66%


February 21, 2015


$7.4

Hubbard 1-23H(3)


57.0%


4,600


N/A


19


100%


March 6, 2015


$6.1

The River 1-22H


43.1%


4,400


1,250


1,109


46%


March 14, 2015


$5.0

Bo 1-23H


54.3%


4,900


547


398


55%


March 15, 2015


$5.0

Bigfoot 1-9H


51.5%


4,800


N/A


127


67%


March 17, 2015


$5.0

Falcon 1-5H


51.5%


4,700


770


616


87%


April 1, 2015


$5.0

Dorothy 1-12H


53.7%


5,000


N/A


N/A


N/A


April 10, 2015


$5.0

Polar Bear 1-20H


47.7%


4,400


N/A


N/A


N/A


Awaiting completion


$5.0

Unruh 1-34H


49.0%


4,900


N/A


N/A


N/A


Awaiting re-drill


$7.1


















(1)

Represents highest daily gross Boe rate. 

(2)

Represents gross cumulative production divided by actual producing days through April 22, 2015.

(3)

After payout working interest is 49.9%.

 

During the first quarter of 2015, we completed three gross (2.9 net) operated wells on our WEHLU acreage. These included one gross (1.0 net) vertical well, the Warsaw 33-1H, and two gross (2.0 net) horizontal wells, the Warsaw 33-2H targeting the upper Hunton and the Warsaw 33-3H targeting the lower Hunton, all of which are located on the southern portion of our WEHLU acreage. We have three gross (2.9 net) wells awaiting completion.  We expect to commence production operations on these wells over the next couple of weeks.  Additionally, we have begun drilling operations on the Jetson 8-1H targeting the upper Hunton and the Davis 9-2H targeting the lower Hunton.  On both the Jetson and Davis pads, we plan to drill an additional horizontal well targeting the lower and upper Hunton, respectively.  The two Davis wells are projected to be on production in July 2015 and the two Jetson wells in August 2015.  We expect to complete and bring on production three gross (2.9 net) operated wells in the second quarter of 2015 and seven gross (6.9 net) operated wells in the third quarter of 2015.

The table below shows wells brought on production or for which drilling operations have commenced since the beginning of the first quarter of 2015 within our operated acreage in the Hunton Limestone formation, all of which are located within WEHLU:









Cumulative Production Averages(2)





Well Name


Current
Working
Interest


Approximate
Lateral
Length
 (in feet)


Peak
Production
Rates(1)

(BOE/d)


BOE/d


% Oil


Date of First Production
or
Status


Approximate
Gross Costs
to Drill &
Complete 
($ millions)
















Warsaw 33-2H


98.3%


4,900


615


348


72%


February 12, 2015


$3.8

Warsaw 33-3H


98.3%


5,800


663


297


67%


February 13, 2015


$6.2

Warsaw 33-1(3)


98.3%


N/A  


30


21


60%


March 13, 2015


$3.5

Easton 22-3H


98.3%


6,500


N/A


N/A


N/A


Awaiting completion


$5.0

Easton 22-4H


98.3%


6,500


N/A


N/A


N/A


Awaiting completion


$3.1

Blair Farms 31-1H


98.3%


6,500


N/A


N/A


N/A


Awaiting completion


$3.3

Davis 9-2H


98.3%


6,800


N/A


N/A


N/A


Drilling


$4.5

Jetson 8-1H


98.3%


6,800


N/A


N/A


N/A


Drilling


$5.5


















(1)

Represents highest daily gross Boe rate. 

(2)

Represents gross cumulative production divided by actual producing days through April 22, 2015.

(3)

The Warsaw 33-1 is a vertical well.

 

In the Mid-Continent, our net capital expenditures in the first quarter of 2015 totaled $29 million. Our total 2015 capital expenditure budget in the Mid-Continent is $69 million, of which $60 million has  been allocated to drilling and completion and $9 million to lease extensions.

Appalachian Basin

Net production from the Appalachian Basin area averaged 6,700 Boe/d in the first quarter of 2015, compared to 6,400 Boe/d for the first quarter of 2014 and 6,100 Boe/d in the fourth quarter of 2014.  Year-over-year and sequential production volume increases were due to seven gross (3.5 net) Armstrong Marcellus Shale wells and three gross (1.5 net) Hansen Marcellus Shale wells that were brought on production in mid-to-late December 2014 as well as three gross (1.5 net) Goudy Marcellus Shale wells that were brought online in early March 2015.

In late April 2015, the third party mid-stream gathering system incurred a leak south of our leasehold position.  During the nine days of repair operations, our existing production was curtailed by approximately 19,300 net Boe comprised of approximately 64,500 net Mcf of natural gas, approximately 2,300 net barrels of condensate and approximately 6,300 barrels of NGLs.  The leak repair also delayed the timing and flow rate of new wells being turned to sales.  The gathering system repairs have been completed.

In early April 2015, two gross (1.0 net) Marcellus Shale wells on the Hoyt pad were brought online. Additionally, two gross (1.0 net) Marcellus Shale wells and one gross (0.5 net) Utica/Point Pleasant well on the Blake pad are expected to be completed and brought on production late May 2015. The Utica/Point Pleasant well has been fracked with a lateral length of 6,600 feet, and will be brought on production at a restricted flow rate to maximize estimated ultimate recovery of reserves.  We continue to be encouraged by the high initial production rates of third party Utica Shale wells surrounding our acreage. At this time, we have no additional wells budgeted to be drilled and completed in the Appalachian Basin for the remainder of 2015. We will continue to monitor commodity prices and services costs in the area and may elect to resume drilling when economic conditions warrant.

Net capital expenditures in the Appalachian Basin for the first quarter of 2015 totaled $12 million. We have allocated approximately $27 million of our total 2015 capital budget to the Appalachian Basin, of which $19 million is for the completion of eight gross (4.0 net) drilled wells as noted above and $8 million is primarily for acquiring additional mineral rights in the area.

Liquidity

At March 31, 2015, we had approximately $12.1 million in available cash and cash equivalents and $135 million of availability under our $200 million revolving credit facility.  We expect to fund our remaining 2015 capital program through existing cash balances, internally generated cash flow from operating activities, borrowings under the revolving credit facility, property sales and possible capital markets transactions, or some combination thereof.

Guidance for the Second Quarter of 2015

We are reiterating our previously issued guidance for the full year 2015 and providing the following guidance for the second quarter of 2015:

Production

Second Quarter 2015(1)


Full-Year 2015(1)





Net average daily (MBoe/d)(2)

12.5 - 13.1


11.5 - 13.4

Liquids percentage

51% - 54%


51% - 55%





Cash Operating Expenses

Second Quarter 2015


Full-Year 2015

Production taxes (% of production revenues)

4.8% - 5.3%


4.3% - 4.8%

Direct lease operating ($/Boe)

$5.00 - $5.40


$4.90 - $5.50

Transportation, treating & gathering ($/Boe)

$0.40 - $0.50


$0.40 - $0.50

Cash general & administrative ($/Boe)

$2.70 - $3.00


$2.60 - $2.90







(1)

Includes adjustment for Oklahoma non-core asset divestiture with property sale effective date of April 1, 2015

(2)

Based on equivalent of 6 thousand cubic feet (Mcf) of natural gas to one barrel of oil, condensate or NGLs.

 

Conference Call

Gastar has scheduled a conference call for 10:00 a.m. Eastern Time (9:00 a.m. Central Time) on Friday, May 8, 2015.  Investors may participate in the call either by phone or audio webcast.

By Phone:

Dial 1-412-902-0030 at least 10 minutes before the call. A telephone replay will be available through May 15 by dialing 1-201-612-7415 and using the conference ID: 13608157.



By Webcast:

Visit the Investor Relations page of Gastar's website at www.gastar.com under "Events & Presentations." Please log on a few minutes in advance to register and download any necessary software. A replay will be available shortly after the call.

 

 

 

For more information, please contact Donna Washburn at Dennard-Lascar Associates at 713-529-6600 or e-mail dwashburn@DennardLascar.com.

About Gastar Exploration

Gastar Exploration Inc. is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and natural gas liquids in the United States. Gastar's principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. In Oklahoma, Gastar is developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal play and expects to test other prospective formations on the same acreage, including the Meramec Shale (middle Mississippi Lime) and the Woodford Shale, which Gastar refers to as the Stack Play. In West Virginia, Gastar is developing liquids-rich natural gas in the Marcellus Shale and has drilled and completed its first successful dry gas Utica Shale/Point Pleasant well on its acreage.  For more information, visit Gastar's website at www.gastar.com.

Forward-Looking Statements

This news release also includes "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward looking statements give our current expectations, opinion, belief or forecasts of future events and performance. A statement identified by the use of forward looking words including "may," "expects," "projects," "anticipates," "plans," "believes," "estimate," "will," "should," and certain of the other foregoing statements may be deemed forward-looking statements. Although Gastar believes that the expectations reflected in such forward-looking statements are reasonable, these statements involve risks and uncertainties that may cause actual future activities and results to be materially different from those suggested or described in this news release. These include risks inherent in natural gas and oil drilling and production activities, including risks with respect to continued low or further declining prices for oil and natural gas that could cause Gastar to further delay or suspend planned drilling and completion operations or reduce production levels which would adversely impact cash flow; risks relating to the availability of capital to fund drilling operations that can be adversely affected by adverse drilling results, production declines and declines in natural gas and oil prices; risks regarding our ability to meet financial covenants under our indenture or credit agreements or the ability to obtain amendments or waivers to effect such compliance; risks of fire, explosion, blowouts, pipe failure, casing collapse, unusual or unexpected formation pressures, environmental hazards, and other operating and production risks, which may temporarily or permanently reduce production or cause initial production or test results to not be indicative of future well performance or delay the timing of sales or completion of drilling operations; delays in receipt of drilling permits; risks relating to unexpected adverse developments in the status of properties; borrowing base redeterminations by our banks; risks relating to the absence or delay in receipt of government approvals or third-party consents; risks relating to our ability to realize the anticipated benefits from acquired assets; and other risks described in Gastar's Annual Report on Form 10-K and other filings with the SEC, available at the SEC's website at www.sec.gov. Our actual sales production rates can vary considerably from tested initial production rates depending upon completion and production techniques and our primary areas of operations are subject to natural steep decline rates. By issuing forward looking statements based on current expectations, opinions, views or beliefs, Gastar has no obligation and, except as required by law, is not undertaking any obligation, to update or revise these statements or provide any other information relating to such statements.

Unless otherwise stated herein, equivalent volumes of production and reserves are based upon an energy equivalent ratio of six Mcf of natural gas to each barrel of liquids (oil, condensate and NGLs), which ratio is not reflective of relative value. Our NGLs are sold as part of our wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from our wet gas production. Our reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which we are credited under our sales contracts.

Targeted expectations and guidance for 2015 are based upon the current revised 2015 capital expenditures budget, which may be subject to revision and reevaluation dependent upon future developments, including drilling results, availability of crews, supplies and production capacity, weather delays, and significant changes in commodities prices or drilling costs.

Contacts:
Gastar Exploration Inc.
Michael A. Gerlich, Chief Financial Officer
713-739-1800 / mgerlich@gastar.com

Investor Relations Counsel:
Lisa Elliott, Dennard-Lascar Associates:
713-529-6600 / lelliott@DennardLascar.com

- Financial Tables Follow -

GASTAR EXPLORATION INC.

CONSOLIDATED STATEMENTS OF OPERATIONS



For the Three Months Ended March 31,



2015


2014



(in thousands, except share and per share data)

REVENUES:





Oil and condensate

$

15,353



$

16,778



Natural gas

6,700



15,419



NGLs

2,096



6,644



Total oil and condensate, natural gas and NGLs revenues

24,149



38,841



Gain (loss) on commodity derivatives contracts

10,223



(6,514)



Total revenues

34,372



32,327



EXPENSES:





Production taxes

840



1,894



Lease operating expenses

6,019



4,044



Transportation, treating and gathering

497



625



Depreciation, depletion and amortization

14,471



12,382



Accretion of asset retirement obligation

125



122



General and administrative expense

4,248



4,763



Total expenses

26,200



23,830



INCOME FROM OPERATIONS

8,172



8,497



OTHER INCOME (EXPENSE):





Interest expense

(7,561)



(6,891)



Investment income and other

3



7



Foreign transaction loss



(2)



INCOME BEFORE PROVISION FOR INCOME TAXES

614



1,611



Provision for income taxes





NET INCOME

614



1,611



Dividends on preferred stock

(3,618)



(3,576)



NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS

$

(3,004)



$

(1,965)



NET LOSS PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:





Basic

$

(0.04)



$

(0.03)



Diluted

$

(0.04)



$

(0.03)



WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:





Basic

77,114,826



58,204,532



Diluted

77,114,826



58,204,532



 

GASTAR EXPLORATION INC.

CONSOLIDATED BALANCE SHEETS



March 31,


December 31,


2015


2014


(in thousands, except share data)

ASSETS




CURRENT ASSETS:




Cash and cash equivalents

$

12,143



$

11,008


Accounts receivable, net of allowance for doubtful accounts of $0, respectively

18,187



30,841


Commodity derivative contracts

18,815



19,687


Prepaid expenses

1,808



2,083


Total current assets

50,953



63,619


PROPERTY, PLANT AND EQUIPMENT:




Oil and natural gas properties, full cost method of accounting:




Unproved properties, excluded from amortization

120,341



128,274


Proved properties

1,174,581



1,124,367


Total natural gas and oil properties

1,294,922



1,252,641


Furniture and equipment

3,013



3,010


Total property, plant and equipment

1,297,935



1,255,651


Accumulated depreciation, depletion and amortization

(577,822)



(563,351)


Total property, plant and equipment, net

720,113



692,300


OTHER ASSETS:




Commodity derivative contracts

13,404



7,815


Deferred charges, net

2,682



2,586


Advances to operators and other assets

2,770



9,474


Total other assets

18,856



19,875


TOTAL ASSETS

$

789,922



$

775,794


LIABILITIES AND STOCKHOLDERS' EQUITY




CURRENT LIABILITIES:




Accounts payable

$

19,780



$

28,843


Revenue payable

8,258



9,122


Accrued interest

10,550



3,528


Accrued drilling and operating costs

6,598



5,977


Advances from non-operators

1,025



1,820


Commodity derivative contracts

56




Commodity derivative premium payable

2,472



2,481


Asset retirement obligation

84



82


Other accrued liabilities

1,975



3,175


Total current liabilities

50,798



55,028


LONG-TERM LIABILITIES:




Long-term debt

380,916



360,303


Commodity derivative contracts

340




Commodity derivative premium payable

4,809



4,702


Asset retirement obligation

5,676



5,475


Total long-term liabilities

391,741



370,480


Commitments and contingencies




STOCKHOLDERS' EQUITY:




Preferred stock, 40,000,000 shares authorized




Series A Preferred stock, par value $0.01 per share; 10,000,000 shares authorized; 4,045,000 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively, with liquidation preference of $25.00 per share

41



41


Series B Preferred stock, par value $0.01 per share; 10,000,000 shares authorized; 2,140,000 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively, with liquidation preference of $25.00 per share

21



21


Common stock, par value $0.001 per share; 275,000,000 shares authorized; 80,145,775 and 78,632,810 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively

78



78


Additional paid-in capital

568,541



568,440


Accumulated deficit

(221,298)



(218,294)


Total stockholders' equity

347,383



350,286


TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$

789,922



$

775,794


 

GASTAR EXPLORATION INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



For the Three Months Ended March 31,


2015


2014


(in thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:




Net income

$

614



$

1,611


Adjustments to reconcile net income to net cash provided by operating activities:




Depreciation, depletion and amortization

14,471



12,382


Stock-based compensation

1,526



1,533


Mark to market of commodity derivatives contracts:




Total (gain) loss on commodity derivatives contracts

(10,223)



6,514


Cash settlements of matured commodity derivative contracts, net

5,277



(3,015)


Cash premiums paid for commodity derivatives contracts



(71)


Amortization of deferred financing costs

822



733


Accretion of asset retirement obligation

125



122


Settlement of asset retirement obligation



(257)


Changes in operating assets and liabilities:




Accounts receivable

14,279



(750)


Prepaid expenses

275



81


Accounts payable and accrued liabilities

5,957



4,169


Net cash provided by operating activities

33,123



23,052


CASH FLOWS FROM INVESTING ACTIVITIES:




Development and purchase of oil and natural gas properties

(46,121)



(25,812)


Advances to operators

(1,753)



(5,001)


Acquisition of oil and natural gas properties - refund



4,209


Proceeds from (payment related to) sale of oil and natural gas properties

2,008



(341)


(Payments to) proceeds from non-operators

(795)



4,930


Purchase of furniture and equipment

(3)



(148)


Net cash used in investing activities

(46,664)



(22,163)


CASH FLOWS FROM FINANCING ACTIVITIES:




Proceeds from revolving credit facility

25,000




Repayment of revolving credit facility

(5,000)




Proceeds from issuance of preferred stock, net of issuance costs



886


Dividends on preferred stock

(3,618)



(3,576)


Deferred financing charges

(281)



(135)


Tax withholding related to restricted stock and PBU vestings

(1,425)



(3,544)


Net cash provided by (used in) financing activities

14,676



(6,369)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

1,135



(5,480)


CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

11,008



32,393


CASH AND CASH EQUIVALENTS, END OF PERIOD

$

12,143



$

26,913


 

NON-GAAP FINANCIAL INFORMATION AND RECONCILIATION

We use both GAAP and certain non-GAAP financial measures to assess performance.  Generally, a non-GAAP financial measure is a numerical measure of a company's performance, financial position or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with GAAP.  Our management believes that these non-GAAP measures provide useful supplemental information to investors in order that they may evaluate our financial performance using the same measures as management.  These non-GAAP financial measures should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP.  In evaluating these measures, investors should consider that the methodology applied in calculating such measures may differ among companies and analysts.  A reconciliation is provided below outlining the differences between these non-GAAP measures and their most directly comparable financial measure calculated in accordance with GAAP.

Reconciliation of Net Loss to Net Income (Loss) Excluding Special Items:



For the Three Months Ended March 31,


2015


2014


(in thousands, except share and per share data)





NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS AS REPORTED

$

(3,004)



$

(1,965)


SPECIAL ITEMS:




(Gains) losses related to the change in mark to market value for outstanding commodity derivatives contracts

(4,252)



3,155


Non-recurring general and administrative costs related to acquisition of assets



30


Non-recurring general and administrative costs related to Parent migration



205


Foreign transaction loss



2






ADJUSTED NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS

$

(7,256)



$

1,427






ADJUSTED NET (LOSS) INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:




Basic

$

(0.09)



$

0.02


Diluted

$

(0.09)



$

0.02






WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:




Basic

77,114,826



58,204,532


Diluted

77,114,826



61,438,875






 

Reconciliation of Cash Flows before Working Capital Changes and as Adjusted for Special Items:




For the Three Months Ended March 31,



2015


2014



(in thousands)






CASH FLOWS FROM OPERATING ACTIVITIES:





Net income


$

614



$

1,611


Adjustments to reconcile net income to net cash provided by operating activities:





Depreciation, depletion and amortization


14,471



12,382


Stock-based compensation


1,526



1,533


Mark to market of commodity derivatives contracts:





Total (gain) loss on commodity derivatives contracts


(10,223)



6,514


Cash settlements of matured commodity derivatives contracts, net


5,277



(3,015)


Cash premiums paid for commodity derivatives contracts




(71)


Amortization of deferred financing costs


822



733


Accretion of asset retirement obligation


125



122


Settlement of asset retirement obligation




(257)


Cash flows from operations before working capital changes


12,612



19,552


Foreign transaction loss




2


Dividends on preferred stock


(3,618)



(3,576)


Non-recurring general and administrative costs related to acquisition of assets




30


Non-recurring general and administrative costs related to Parent migration




205


Adjusted cash flows from operations


$

8,994



$

16,213







 

Reconciliation of Net Loss to Adjusted Earnings Before Interest, Income Taxes, Depreciation, Depletion and Amortization ("Adjusted EBITDA"):



For the Three Months Ended  March 31,


2015


2014


(in thousands, except share and per share data)





NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS AS REPORTED

$

(3,004)



$

(1,965)


Interest expense

7,561



6,891


Depreciation, depletion and amortization

14,471



12,382


EBITDA

19,028



17,308


Dividend expense

3,618



3,576


Accretion of asset retirement obligation

125



122


(Gains) losses related to the change in mark to market value for outstanding commodity derivatives contracts

(4,252)



3,155


Non-cash stock compensation expense

1,526



1,533


Foreign transaction loss



2


Investment income and other

(3)



(7)


Non-recurring general and administrative costs related to acquisition of assets



30


Non-recurring general and administrative costs related to Parent migration



205


Adjusted EBITDA

$

20,042



$

25,924






 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/gastar-exploration-announces-first-quarter-2015-results-300079877.html

SOURCE Gastar Exploration Inc.

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