Gastar Exploration Inc (NYSEMKT:GST) reported financial and operating results for the three and six months ended June 30, 2015.

Net loss attributable to Gastar’s common stockholders as reported for the second quarter of 2015 was $118.0 million, or a loss of $1.52 per share.  Excluding a $100.2 millionnon-cash, pre-tax ceiling test impairment charge and a $7.8 million loss resulting from the mark-to-market of outstanding hedge positions, adjusted net loss attributable to common stockholders was $10.1 million, or a loss of $0.13 per share.  This compares to second quarter 2014 reported net income of $2.0 million, or $0.03 per share, which includes the impact of an $8.6 million net benefit related to an arbitration settlement.  Excluding the impact of a $5.4 million loss resulting from the mark-to-market of outstanding hedge positions, second quarter 2014 adjusted net income was $7.5 million, or $0.12 per diluted share. (See the accompanying reconciliation of net (loss) income to net income (loss) excluding special items at the end of this news release.)  Second quarter 2015 results compare to a first quarter 2015 net loss of $3.0 million, or a loss of$0.04 per share, and an adjusted net loss of $7.3 million, or a loss of $0.09 per share, which excludes a $4.3 million gain resulting from the mark-to-market of outstanding hedge positions.

Adjusted earnings before interest, income taxes, depreciation, depletion and amortization (“adjusted EBITDA”) for the second quarter of 2015 was $17.9 million, a decrease of 39%, compared to $29.4 million in the second quarter of 2014, which includes the impact of an $8.6 million net benefit related to an arbitration settlement, and a decrease of 11% compared to $20.0 million in the first quarter of 2015.  (See the accompanying reconciliation of net (loss) income 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, were $23.7 million in the second quarter of 2015, a decrease of 47% from $44.8 million in the second quarter of 2014 and a decline of 2% from $24.1 million in the first quarter of 2015.  The reduction in oil, condensate, natural gas and NGLs revenues from the second quarter of 2014 was primarily the result of a 53% decrease in weighted average realized equivalent prices, excluding the gross revenue benefit of $10.6 million related to an arbitration settlement in 2014, partially offset by a 47% increase in production.  The slight decrease from the first quarter of 2015 revenues was primarily due to a 12% decline in equivalent product pricing partially offset by a 10% increase in average daily production.

Revenues from liquids (oil, condensate and NGLs) represented approximately 83% of total production revenues in the second quarter of 2015, compared to 72% for the second quarter of 2014 (excluding the benefit from the arbitration settlement mentioned above) and 72% during the first quarter of 2015.  We had commodity derivatives contracts in place covering approximately 70% of our natural gas production, 47% of our NGLs production and 31% of our oil and condensate production for the second quarter of 2015.  Commodity derivative contracts settled during the period resulted in a $6.0 million increase in revenue for the second quarter of 2015, compared to a reduction in revenue of $3.5 million for the second quarter of 2014 and an increase in revenue of $6.0 million for the first quarter of 2015. Second quarter 2015 hedge benefit enhanced our barrel of oil equivalent (Boe) pricing by approximately 25%, whereas in the second quarter of 2014, hedging reduced our Boe pricing by approximately 10%.  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 second quarter of 2015 was 13,900 barrels of oil equivalent per day (“Boe/d”) as compared to 9,500 Boe/d in the second quarter of 2014 and 12,600 Boe/d in the first quarter of 2015. Liquids as a percentage of total equivalent production volumes were 53% in the second quarter of 2015 compared to 48% in the second quarter of 2014 and 52% in the first quarter of 2015.

J. Russell Porter, Gastar’s President and CEO, commented, “We are encouraged by the continued positive drilling results on our WEHLU acreage in the Mid-Continent.  During the second quarter of 2015, we brought on production two wells in the upper Hunton formation, the Blair Farms 31-1H and the Easton 22-4H, both demonstrating a 30 and 60-day average production rate substantially above our previous type curve.  With this continued demonstrated outperformance of our production estimates, our independent reservoir engineers have increased our estimated ultimate recovery (EUR) on our upper Hunton wells.  WEHLU upper Hunton wells are now assigned  an unprocessed EUR of 314 Mboe (75% oil) for our proved undeveloped wells in this area, an increase of 35% from our previous estimate of 233 Mboe (74% oil).  Due to the strong production rates and projected lower well costs of $3.3 million per 6,000 foot lateral well, we now estimate the internal rate of return (IRR), based on return on estimated drilling and completion costs at NYMEX commodity price curves, for the upper Hunton wells to be approximately 39%.”

“We also continue to experience solid production results from our lower Hunton WEHLU drilled wells and have increased our unprocessed EUR by 25% to 395 Mboe (82% oil), from 316 Mboe (87% oil).  Based on NYMEX commodity price curves and estimated well costs of $5.5 million per 6,000 foot lateral well, the IRR is estimated at approximately 22%.”

“Due to our encouraging WEHLU drilling results and enhanced liquidity following the recent sale of non-core acreage in Oklahoma, our Board of Directors has approved an increase of our total 2015 capital expenditure program.  We are increasing our budgeted capital expenditures from $103 million to $120 million, which will allow for oneMeramec Shale/Mississippi Lime test on our Mid-Continent acreage, an additional lower Hunton WEHLU well and additional costs incurred to date in our non-operated AMI and other operated areas.  With this additional capital, the mid-point of our projected 2015 full-year production has been increased 8% to 13.5 Mboe/d, representing a 32% increase in year-over-year production from 2014.  We are increasingly more enthusiastic about the potential of the STACK – Meramec Shale formation on our Mid-Continent acreage as we observe the high performance rates from wells being drilled by offset and nearby operators.  Our plan is to drill and complete our first test by the end of 2015, which will be our first step toward planning further exploration and development of the play in 2016,” said Porter.

The following table provides a summary of Gastar’s production volumes and average commodity prices for the three and six months ended June 30, 2015 and 2014:

For the Three Months Ended June 30,

For the Six Months Ended June 30,

2015

2014

2015

2014

(In thousands, except per unit amounts)

Net Production:  

Oil and condensate (MBbl)

369

207

736

410

Natural gas (MMcf)

3,575

2,680

6,870

5,752

NGLs (MBbl)

297

208

516

363

Total net production (MBoe)

1,262

861

2,397

1,732

Net Daily production:

Oil and condensate (MBbl/d)

4.1

2.3

4.1

2.3

Natural gas (MMcf/d)

39.3

29.5

38.0

31.8

NGLs (MBbl/d)

3.3

2.3

2.9

2.0

Total net daily production (MBoe/d)

13.9

9.5

13.2

9.6

Average sales price per unit(1):

Oil and condensate per Bbl, including impact of hedging activities (2)

$

52.20

$

87.30

$

49.86

$

83.47

Oil and condensate per Bbl, excluding impact of hedging activities

$

47.68

$

92.84

$

44.76

$

87.77

Natural gas per Mcf, including impact of hedging activities (2)

$

1.68

$

3.03

$

2.11

$

3.73

Natural gas per Mcf, excluding impact of hedging activities

$

1.10

$

3.52

$

1.55

$

4.32

NGLs per Bbl, including impact of hedging activities (2)

$

14.97

$

21.92

$

16.72

$

29.07

NGLs per Bbl, excluding impact of hedging activities

$

7.34

$

26.88

$

8.29

$

33.69

Average sales price per Boe, including impact of hedging activities(1)(2)

$

23.54

$

35.67

$

24.96

$

38.23

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

$

18.79

$

39.72

$

19.97

$

42.19

(1)

The three and six months ended June 30, 2014 exclude the benefit of a one-time revenue adjustment related to an arbitration settlement. 

(2)

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

Lease operating expenses (“LOE”) were $7.2 million in the second quarter of 2015, versus $4.9 million in the second quarter of 2014 and $6.0 million in the first quarter of 2015. Compared to the second quarter of 2014, LOE in the second quarter of 2015 increased $2.3 million primarily due to one-time workover costs of $1.3 million for production enhancement on five wells in our operated WEHLU acreage,  $449,000 in insurance expenses and an increase in costs as a result of higher production volumes.  Compared to the first quarter of 2015, LOE was higher primarily due to approximately $755,000 of higher expenses related to increased production volumes, water hauling costs for new wells in the Mid-Continent and the Appalachian Basin and costs for production enhancing electric submersible pumps in WEHLU coupled with $455,000 of higher insurance expenses.  LOE per Boe of production was $5.74 in the second quarter of 2015 versus $5.66 in the second quarter of 2014 and $5.30 in the first quarter of 2015.  Excluding workover costs as well as the impact of an arbitration settlement in 2014, LOE per Boe for second quarter of 2015 was $4.64 compared to $5.82 per Boe for the second quarter of 2014 and $4.09 per Boe for the first quarter of 2015.

Depreciation, depletion and amortization expense (“DD&A”) was $16.1 million in the second quarter of 2015, up from $10.3 million in the second quarter of 2014 and $14.5 million in the first quarter of 2015.  The year-over-year increase in DD&A expense was the result of 47% higher production volumes and a 7% increase in DD&A rate per Boe, primarily due to decreased proved reserve volumes.  The reserve volume reduction was due to lower economic limits and proved undeveloped reserves being less economically viable because of the reduced commodity price environment. DD&A increased sequentially due to higher production volumes. The DD&A rate per Boe for the second quarter of 2015 was $12.74 compared to $11.94 for the second quarter of 2014 and $12.75 in the first quarter of 2015.

General and administrative (“G&A”) expense was $4.4 million in the second quarter of 2015 compared to $3.9 million in the second quarter of 2014 and $4.2 million in the first quarter of 2015. G&A expense in the second quarter of 2015 included $1.2 million of non-cash stock-based compensation expense compared to $1.0 million in the second quarter of 2014 and $1.5 million in the first quarter of 2015.  Excluding stock-based compensation expense, cash G&A expense increased to $3.2 million in the second quarter of 2015 from $2.9 million in the second quarter of 2014 and from $2.7 million in the first quarter of 2015. This increase from the second quarter of 2014 was primarily due to higher legal costs.

Interest expense totaled $6.9 million in the second quarter of 2015, which was flat compared to the second quarter of 2014 and down from $7.6 million in the first quarter 2015.  See “Liquidity” below for more information about available borrowings under our revolving credit facility.

Operations Review and Update

Mid-Continent

Net production from the Mid-Continent area increased to an average of 6,200 Boe/d in the second quarter of 2015, compared to 4,100 Boe/d in the second quarter of 2014 and 5,900 Boe/d in the first quarter of 2015. Second quarter 2015 Mid-Continent equivalent production consisted of approximately 54% oil, 26% natural gas and 20% NGLs.

On our WEHLU acreage, we completed three gross (2.9 net) operated wells during the second quarter of 2015, consisting of two upper and one lower Hunton completions. We currently have two rigs running within WEHLU and anticipate releasing both rigs before the end of the third quarter 2015 as we evaluate our WEHLU Hunton drilling results, monitor commodity prices and assess service costs.  We plan to complete and bring on production a total of eight gross (7.9 net) operated wells on our WEHLU acreage in the third quarter of 2015, consisting of three upper Hunton and five lower Hunton completions, of which one upper and one lower Hunton completion will be located on the less drilled southern portion of our WEHLU acreage. (Original Source)

Shares of Gastar Exploration closed today at $1.55, up $0.03 or 1.97%. GST has a 1-year high of $8.24 and a 1-year low of $1.48. The stock’s 50-day moving average is $2.41 and its 200-day moving average is $2.80.

On the ratings front, Gastar Exploration has been the subject of a number of recent research reports. In a report issued on July 14, KeyBanc analyst David Deckelbaum maintained a Buy rating on GST, with a price target of $3.50, which implies an upside of 130.3% from current levels. Separately, on May 11, Wunderlich Securities’ Jason Wangler reiterated a Buy rating on the stock and has a price target of $5.

According to TipRanks.com, which ranks over 7,500 financial analysts and bloggers to gauge the performance of their past recommendations, David Deckelbaum and Jason Wangler have a total average return of -33.8% and -16.5% respectively. Deckelbaum has a success rate of 10.7% and is ranked #3706 out of 3727 analysts, while Wangler has a success rate of 28.2% and is ranked #3721.

Gastar Exploration Inc is an independent energy company. It is engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the US.