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Gastar Updates Asset Growth, Activity in Marcellus, Hunton Lime

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Gastar Updates Asset Growth, Activity in Marcellus, Hunton Lime

Gastar Exploration Ltd. reported financial and operating results for the three and six months ended June 30, 2013.

J. Russell Porter, Gastar's President and CEO, stated, "We are pleased with our accomplishments to date in 2013.  Through a series of recent transactions, we have greatly enhanced our acreage position in Oklahoma at a very low cost basis, further increased the liquids content of our reserves and production as well as substantially bolstering our financial liquidity to support our future growth.

"At mid-year, we are pleased to report another significant increase in our proved reserves that continues to be more heavily weighted towards high-value liquids.  Over the long term, we have been successful in achieving our stated goal of raising the percentage of oil, condensate and NGLs in our production profile and positioning the company for further growth.  Over the last two-and-a-half years, we have grown our reserves base from approximately 50 Bcfe – almost all natural gas – to almost 250 Bcfe that is 30% oil, condensate and NGLs.

"We are enthusiastic about the future development of our liquids rich acreage in the Marcellus and our expanded acreage position in the Hunton Limestone oil play in Oklahoma.  Although we are in early stages of testing and developing the Oklahoma acreage, we are confident that we can bring our demonstrated ability to systematically improve results and lower costs to our operations there.  We believe that our large inventory of attractive, high-return, liquids-focused drilling opportunities will allow us to continue to grow reserves, production and cash flow and generate further growth in shareholder value."

Operations Update

Updates for each of Gastar's E&P segments can be found below:

Q2 2013 Summary

Net income attributable to Gastar's common shareholders for the second quarter of 2013 was $51.8 million, or $0.81 per diluted share.  Excluding the impact of a $43.7 million non-cash fair value gain on the acquisition of assets, a $7.5 million unrealized hedging gain and non-recurring charges of $2.6 million, adjusted net income attributable to common shareholders was $3.2 million, or $0.05 per diluted share.  This compares to a net loss of $74.0 million, or $1.17 per share, and an adjusted net loss of $4.1 million, or $0.06 per share, excluding the impact of a non-cash impairment of natural gas and oil properties of $72.7 million and an unrealized hedging gain of $2.8 million for the second quarter of 2012.

Net cash provided by operating activities before working capital changes, reduced for dividend expense and adjusted for other special items (adjusted cash flows from operations) for the second quarter of 2013 increased to $12.3 million, or $0.19 per diluted share, compared to $3.7 million, or $0.06 per diluted share, for the second quarter of 2012. 

Natural gas, condensate, oil and natural gas liquids (NGLs) revenues increased 111% to $23.4 million in the second quarter of 2013, up from $11.1 million for the same period a year earlier.  The increase in revenues was primarily the result of 65% growth in production volumes and a 28% increase in average sales price per thousand cubic feet of natural gas equivalent (Mcfe), including the impact of realized hedging activities.  Revenues from liquids (condensate, oil and NGLs) represented approximately 49% of our total natural gas, condensate, oil and NGLs revenues for the second quarter of 2013 compared to 46% for the first quarter of 2013 and 40% for the second quarter of 2012.

Average daily production was 57.6 million cubic feet of natural gas equivalent (MMcfe) per day for the second quarter of 2013, compared to 34.8 MMcfe per day for the same period in 2012. Sequentially, average daily production increased 42% from first quarter 2013 production of 40.5 MMcfe per day.  Oil, condensate and NGLs as a percentage of production was 29% in the second quarter compared to 19% in the second quarter of 2012 and 26% in the first quarter of 2013.

Higher production volumes were primarily driven by our horizontal drilling activity in the liquids-rich area of the Marcellus Shale in Marshall County, West Virginia and in the Hunton oil play in Oklahoma, partially offset by natural declines from our dry gas wells in East Texas. Second quarter 2013 volumes also benefited from less curtailment of our Marcellus production due to reduced downtime and fewer line pressure issues on the third-party-operated gathering system that transports our Marcellus production as compared to first quarter 2013.  We estimate that gathering system issues reduced second quarter 2013 production by approximately 7.6 MMcfe/d, or 13% of total production and approximately 3.6 MMcfe/d, or 10% of total production in the second quarter of 2012.

We had hedges in place covering approximately 76% of natural gas, 29% of condensate and oil and 50% of NGLs production for the second quarter of 2013.  We continue to maintain an active hedging program covering a portion of our estimated future production, which is reported in our periodic filings with the U.S. Securities and Exchange Commission (SEC).

Lease operating expense (LOE) was $2.2 million for the second quarter of 2013, compared to $1.6 million in the second quarter of 2012 and $1.8 million in the first quarter of 2013.  The increase in LOE compared to the prior-year period was primarily due to a $695,000 increase related to additional producing wells in West Virginia and Oklahoma.  LOE per Mcfe of production declined to $0.41 in the second quarter of 2013 from $0.49 in the second quarter of 2012 and $0.50 per Mcfe in the first quarter of 2013 due to higher production volumes, partially offset by higher total LOE.

Depreciation, depletion and amortization (DD&A) was $7.6 million in the second quarter, up from $7.0 million in the prior-year period and $5.4 million in the first quarter of 2013.  The increase in DD&A expense compared to second quarter 2012 was the result of a 65% increase in production partially offset by a 34% decrease in the DD&A rate per Mcfe.  The DD&A rate for the second quarter of 2013 was $1.45 per Mcfe compared to $2.20 per Mcfe for the same period in 2012 and $1.47 in the first quarter of this year.

General and administrative expense was $5.0 million in the second quarter, compared to $3.2 million in the prior-year period.  This includes non-cash, stock-based compensation expense of $1.1 million for the second quarter of 2013 and $954,000 for the same quarter in 2012.  The second quarter 2013 general and administrative expense includes $1.4 million in non-recurring costs associated with the acquisition of the Chesapeake assets.

Reserves Update

At June 30, 2013, Gastar's proved natural gas, oil and condensate and NGLs reserves were 248.9 Bcfe, a 38% increase over December 31, 2012 proved reserves of 180.9 Bcfe, as estimated by our third-party reserve consulting engineers in accordance with SEC regulations.  Reserves estimates at June 30, 2013 include reserves acquired from Chesapeake Energy on June 7, 2013 and our East Texas assets. Of the 248.9 Bcfe mid-year reserves, 70% were natural gas, 13% were oil and condensate and 17% were NGLs, compared to 72% natural gas, 11% oil and condensate and 17% NGLs at year-end 2012.

Using the SEC pricing formula, the pre-tax present value discounted at 10% (PV-10) of the estimated proved reserves increased to $324.1 million at June 30, 2013 from $206.8 million at year-end 2012. 

At mid-year:

  • The Appalachian Basin represented 83% of proved reserve volumes and 85% of the PV-10 value.
  • Oklahoma, including the reserves acquired from Chesapeake, represented 6% of proved reserve volumes and 10% of the PV-10 value.
  • East Texas comprised 11% of the proved reserve volumes and 5% of the PV-10 value.

Proved undeveloped reserves at mid-year 2013 represented approximately 32% of total proved reserves compared to approximately 30% at year-end 2012.  Proved undeveloped reserves at mid-year 2013 were all attributable to the Appalachian Basin reserves with a PV-10 value of $89.9 million.

In accordance with SEC regulations, estimates of proved reserves as of June 30, 2013 were calculated using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period July 1, 2012 through June 30, 2013.  For natural gas volumes, the average Henry Hub price utilized was $3.44 per MMbtu, and for oil volumes, the average West Texas Intermediate price utilized was $88.13 per barrel, or $4.19 per Mcfe, compared to $3.72 per Mcfe for year-end 2012.  The natural gas and oil prices are adjusted for energy content or quality, transportation and regional price differentials by area.

Using the alternate NYMEX futures pricing formula, however, the PV-10 of the estimated proved reserves increased to $431.8 million at June 30, 2013 from $333.2 million at year-end 2012.

Reserve estimates as of June 30, 2013 for the Appalachian Basin and Oklahoma were prepared by Wright & Company, Inc., and reserve estimates for East Texas were prepared by Netherland Sewell & Associates, Inc.

Liquidity

At June 30, 2013, we had cash and cash equivalents of $10.8 million and a net working capital deficit of approximately $56.4 million. The working capital deficit includes $30.4 million of advances from non-operating partners.  We had $50 million of unused borrowing capacity on our revolving credit facility at the end of the second quarter.  During the second quarter of 2013 we issued $200 million of 8 5/8% senior secured notes due 2018 to help fund our Chesapeake transaction.  Our current borrowing based on our senior credit facility is $50.0 million with no borrowings currently outstanding.

Excluding acquisitions, capital expenditures for the remainder of 2013 are expected to be approximately $60.2 million, resulting in total annual capital expenditures of approximately $124 million.  The increase in 2013 capital expenditures of approximately $22 million, excluding acquisitions, is primarily due to increased Hunton activity.  We plan to fund our 2013 capital program through existing cash balances, internally generated cash flow from operating activities, borrowings under the revolving credit facility, and proceeds from the pending divestitures of our East Texas assets and certain non-core acreage in Oklahoma.