Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Gastar Exploration Inc. | a8-kq22014earningsaugustdi.htm |
| EX-99.2 - EXHIBIT - Gastar Exploration Inc. | ex992gstaugust2014dividend.htm |
| EX-23.1 - EXHIBIT - Gastar Exploration Inc. | ex231wrightconsent.htm |
| EX-99.3 - EXHIBIT - Gastar Exploration Inc. | ex993gst063014reservereport.htm |
Exhibit 99.1
For Immediate Release  | NEWS RELEASE Contacts: Gastar Exploration Inc. Michael A. Gerlich, Chief Financial Officer 713-739-1800 / mgerlich@gastar.com Investor Relations Counsel: Lisa Elliott / Anne Pearson Dennard▪Lascar Associates: 713-529-6600 lelliott@DennardLascar.com/apearson@DennardLascar.com | |
GASTAR EXPLORATION INC. REPORTS
SECOND QUARTER 2014 RESULTS
• | Liquids as a percentage of production grow to 48% |
• | 19 Mid-Continent Hunton wells completed or in progress during 2Q |
• | First Utica/Point Pleasant well fracture stimulated |
HOUSTON, August 7, 2014 - Gastar Exploration Inc. (NYSE MKT: GST) (“Gastar”) today reported financial and operating results for the three and six months ended June 30, 2014.
Net income attributable to Gastar’s common stockholders for the second quarter of 2014 was $2.0 million, or $0.03 per diluted share. Excluding the impact of a $5.4 million loss resulting from the mark-to-market of outstanding hedge positions, adjusted net income attributable to common stockholders was $7.5 million, or $0.12 per diluted share. Second quarter 2014 net income and adjusted net income include a net benefit of $8.6 million, or $0.14 per diluted share, related to an arbitration settlement. This compares to second quarter 2013 net income of $51.8 million, or $0.81 per diluted share, and adjusted net income of $3.4 million, or $0.05 per diluted share, excluding the impact of a $7.5 million gain resulting from the mark-to-market of outstanding hedge positions, non-recurring charges of $2.8 million and a $43.7 million non-cash fair value gain on the acquisition of assets. (See the accompanying reconciliation of net income to net income excluding special items at the end of this news release.)
Adjusted earnings before interest, income taxes, depreciation, depletion and amortization (“adjusted EBITDA”) for the second quarter of 2014 was $29.4 million, an increase of 75% compared to $16.8 million for the second quarter of 2013 and a 13% increase over the first quarter 2014 results. (See the accompanying reconciliation of net income to adjusted EBITDA at the end of this news release.)
Revenues from oil, condensate, natural gas and natural gas liquids (“NGLs”) before the impact of hedging activities increased 88% to $44.8 million in the second quarter of 2014, up from $23.9 million for the
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same period of 2013. Current quarter oil, condensate, natural gas and NGLs revenues include a gross revenue benefit of $10.6 million related to a West Virginia natural gas contract arbitration settlement. Excluding the arbitration settlement, second quarter 2014 oil, condensate, natural gas and NGLs revenues increased 43% over the second quarter 2013. The increase in oil, condensate, natural gas and NGLs revenues was primarily the result of substantially higher weighted average equivalent realized prices due to increased liquids production. Excluding the benefit of the arbitration settlement, weighted average realized prices increased 45% for the second quarter of 2014 compared to the same period in 2013.
Revenues from liquids (oil, condensate and NGLs) represented approximately 61% of total production revenues in the second quarter, or 72% of revenues excluding the benefit from the arbitration settlement. This compares to 48% for the second quarter of 2013 and 60% for the first quarter of 2014. We had hedges in place covering approximately 99% of our natural gas production, 60% of our oil and condensate production and 82% of our NGLs production for the second quarter of 2014. Commodity derivative contracts settled during the periods resulted in a $3.5 million reduction in revenue for the second quarter of 2014 compared to a $449,000 decrease in revenue for the second quarter of 2013 and a first quarter of 2014 decrease in revenue of $3.4 million. 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”).
Average daily production for the second quarter of 2014 was 9.5 thousand barrels of oil equivalent per day (“MBoe/d”), a 1% decrease compared to the same period in 2013 and a 2% decrease compared to the first quarter of 2014. Oil, condensate and NGLs as a percentage of production volumes were 48% in the second quarter of 2014 compared to 30% in the second quarter of 2013 and 41% in the first quarter of 2014. The arbitration settlement had no impact on production volumes.
J. Russell Porter, Gastar's President and CEO, stated, “During the second quarter, we spud several important wells that, if successful, could substantially increase both our remainder of the year 2014 production and year-end proved reserves, while also increasing our drilling inventory. On our Mid-Continent WEHLU acreage that we acquired in November 2013, we completed our first horizontal well, the Easton 22-1H, in the Lower Hunton oil formation. After less than two weeks on flow back operations and the recovery of less than 2% of the completion fluids, the well's most recent five day average gross production is 460 barrels of oil equivalent per day (Boe/d), of which 88% is oil. We are optimistic that this well could be the first step in significantly de-risking the Lower Hunton formation on a portion of our 24,000 WEHLU net acres and allow us to start booking additional proved undeveloped oil reserves. We also completed our first Upper Hunton well, the Easton 22-2H, on our WEHLU acreage. Early results
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from the flow back of the Easton 22-2H are also encouraging, as the well has been on for less than two days and is currently producing 224 Boe/d, of which 93% is oil. In West Virginia, we just completed the fracture stimulation of our first Utica/Point Pleasant well, the Simms U-5H, with a 25-stage fracture stimulation. We are very encouraged by how the 92 feet of high porosity pay zone in the well responded to fracture stimulation. We are currently allowing the well to soak and anticipate commencing flow back operations in about three weeks. If successful, this well could confirm our first Utica/Point Pleasant proved reserve potential and value and also add significantly to our West Virginia drilling inventory.”
The following table provides a summary of Gastar’s production volumes and average commodity prices for the three and six months ended June 30, 2014 and 2013:
For the Three Months Ended June 30, | For the Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Production: | ||||||||||||||||
Oil and condensate (MBbl) | 207 | 127 | 410 | 205 | ||||||||||||
Natural gas (MMcf) | 2,680 | 3,692 | 5,752 | 6,391 | ||||||||||||
NGLs (MBbl) | 208 | 130 | 363 | 210 | ||||||||||||
Total production (MBoe) | 861 | 873 | 1,732 | 1,481 | ||||||||||||
Daily Production: | ||||||||||||||||
Oil and condensate (MBbl/d) | 2.3 | 1.4 | 2.3 | 1.1 | ||||||||||||
Natural gas (MMcf/d) | 29.5 | 40.6 | 31.8 | 35.3 | ||||||||||||
NGLs (MBbl/d) | 2.3 | 1.4 | 2.0 | 1.2 | ||||||||||||
Total daily production (MBoe/d) | 9.5 | 9.6 | 9.6 | 8.2 | ||||||||||||
Average sales price per unit(1): | ||||||||||||||||
Oil and condensate per Bbl, including impact of hedging(2) | $ | 87.30 | $ | 62.97 | $ | 83.47 | $ | 68.93 | ||||||||
Oil and condensate per Bbl, excluding impact of hedging | $ | 92.84 | $ | 63.36 | $ | 87.77 | $ | 65.07 | ||||||||
Natural gas per Mcf, including impact of hedging(2) | $ | 3.03 | $ | 3.26 | $ | 3.73 | $ | 3.64 | ||||||||
Natural gas per Mcf, excluding impact of hedging | $ | 3.52 | $ | 3.36 | $ | 4.32 | $ | 3.13 | ||||||||
NGLs per Bbl, including impact of hedging(2) | $ | 21.92 | $ | 25.93 | $ | 29.07 | $ | 32.92 | ||||||||
NGLs per Bbl, excluding impact of hedging | $ | 26.88 | $ | 26.17 | $ | 33.69 | $ | 27.54 | ||||||||
Average sales price per Boe, including impact of hedging(2) | $ | 35.67 | $ | 26.85 | $ | 38.23 | $ | 29.95 | ||||||||
Average sales price per Boe, excluding impact of hedging | $ | 39.72 | $ | 27.36 | $ | 42.19 | $ | 26.44 | ||||||||
_____________________________
(1) | The three and six months ended June 30, 2014 pricing exclude the benefit of a 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. |
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Lease operating expenses (“LOE”) were $4.9 million for the second quarter of 2014, including a one-time reduction of $185,000 related to the arbitration settlement, compared to $2.2 million in the second quarter of 2013 and $4.0 million in the first quarter of 2014. The increase in LOE compared to the prior-year period was primarily due to additional expenses resulting from new wells and higher overall costs associated with producing liquids versus natural gas. Additionally, the second quarter of 2014 includes approximately $350,000 of costs associated with pump repair and scale removal. LOE per Boe of production increased to $5.66 in the second quarter of 2014 - or $5.88 excluding the benefit of the arbitration settlement -- versus $2.48 in the second quarter of 2013 and $4.65 in the first quarter of 2014.
Depreciation, depletion and amortization expense (“DD&A”) was $10.3 million in the second quarter of 2014, up from $7.6 million in the prior-year period and down from $12.4 million in the first quarter of 2014. The year-over-year increase in DD&A expense is the result of higher cost liquids-focused acquisitions and drilling. The DD&A rate for the second quarter of 2014 was $11.94 per Boe compared to $8.70 per Boe for the same period in 2013 and $14.23 in the first quarter of 2014.
General and administrative (“G&A”) expense was $3.9 million in the second quarter of 2014, down from $5.0 million in the same period of 2013. G&A expense for the second quarter of 2014 included $1.0 million of non-cash, stock-based compensation expense, versus $1.1 million a year ago. Excluding stock compensation expense, cash G&A expense declined to $2.9 million from $3.9 million in the second quarter of 2013. This decrease was primarily the result of $1.4 million of acquisition-related costs incurred in the second quarter of 2013, partially offset by the current year’s higher personnel costs due to our growing asset base.
Interest expense totaled $6.9 million in the second quarter of 2014, compared with $3.5 million in the second quarter of 2013. The increase was the result of the issuance in May and November of 2013 of $325.0 million of 8 5/8% Senior Secured Notes due May 2018.
Operations Review and Update
Mid-Continent
Currently, we have one operated rig running outside of our AMI acreage and four non-operated rigs running on our AMI acreage. Net production from the Mid-Continent area averaged 4.1 MBoe/d in the second quarter of 2014, compared to 0.6 MBoe/d for the second quarter of 2013 and 3.3 MBoe/d in the first quarter of 2014, a 26% sequential quarter growth rate. Mid-Continent production consisted of approximately 45% oil, 28% natural gas and 27% NGLs, yielding a liquids to total equivalent production
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percentage of 72% in the second quarter of 2014. Within our AMI acreage, Gastar participated in 14 gross (5.4 net) non-operated wells during the second quarter of 2014. Subsequent to the end of the first quarter of 2014, six gross (2.7 net) non-operated wells were placed on production, four gross (1.5 net) wells were drilled and are awaiting completion and four gross (1.3 net) wells are currently being drilled. The table below shows wells brought on production or commenced drilling operations since the beginning of the second quarter of 2014 within our original AMI in the Hunton Limestone formation:
Cumulative Production Averages(2) | ||||||||||||||
Well Name | Current Working Interest | Approximate Lateral Length (in feet) | Initial Production Rates(1) (BOE/d) | BOE/d | % Oil | Date of First Production or Status (3) | Approximate Gross Costs to Drill & Complete ($ millions) | |||||||
Gamebird 1-7H | 48.4% | 4,400 | 653 | 427 | 87% | April 3, 2014 | $5.5 | |||||||
Sieber 1-31H | 33.7% | 4,400 | 1,013 | 697 | 80% | April 13, 2014 | $5.2 | |||||||
Kodiak 1-29H | 45.3% | 4,300 | 1,666 | 1,042 | 80% | May 4, 2014 | $5.1 | |||||||
Anna Lee 1-30H | 50.0% | 4,400 | N/A | 62 | 88% | May 20, 2014 | $5.1 | |||||||
Vaverka 1-20H | 46.9% | 4,400 | N/A | N/A | N/A | July 10, 2014 | $5.1 | |||||||
Sasquatch 1-23H | 43.4% | 4,800 | N/A | N/A | N/A | July 27, 2014 | $5.0 | |||||||
Hobbs Ranch 1-19H | 29.5% | 4,400 | N/A | N/A | N/A | WOC | N/A | |||||||
Yeti 1-29H | 32.8% | 5,300 | N/A | N/A | N/A | WOC | N/A | |||||||
Jam 1-4H | 25.0% | 4,700 | N/A | N/A | N/A | WOC | N/A | |||||||
Cline 1-13H | 54.3% | 5,100 | N/A | N/A | N/A | WOC | N/A | |||||||
Michael J 1-18H | 33.3% | 5,000 | N/A | N/A | N/A | Drilling | N/A | |||||||
Snowman 1-19H | 36.1% | 5,000 | N/A | N/A | N/A | Drilling | N/A | |||||||
Danny Ray 1-30H | 31.7% | 5,000 | N/A | N/A | N/A | Drilling | N/A | |||||||
Shimanek 1-2H | 33.7% | 5,000 | N/A | N/A | N/A | Drilling | N/A | |||||||
_________________________________
(1) | Represents highest daily gross BOE rate to date. |
(2) | Represents average for actual producing days through July 31, 2014. |
(3) | WOC - waiting on completion. |
Within our operated acreage in Oklahoma, we currently have five gross (4.7 net) wells producing. The Easton 22-1H, targeting the lower Hunton formation, as well as the Easton 22-2H, targeting the upper Hunton, have both been recently placed on production. We are also drilling an additional Lower Hunton completion, the Horseshoe 3-1H, that should commence flow back operations in early September 2014.
Our previously announced 2014 capital budget for the Mid-Continent play has been increased by $19 million to $133 million to fund additional Hunton AMI wells. The new capital expenditure budget is comprised of $108 million for drilling, completion and infrastructure costs and $25 million for automatic
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lease extensions and leasing. In the Mid-Continent, net capital expenditures in the second quarter of 2014 totaled $24 million, resulting in current year to date total capital expenditures of $51 million.
Appalachia
Net production from the Marcellus Shale area averaged 5.4 MBoe/d in the second quarter of 2014, compared to 7.4 MBoe/d for the second quarter of 2013 and 6.4 MBoe/d in the first quarter of 2014. Second quarter 2014 production was reduced by approximately 0.4 MBoe/d due to previously announced third-party pipeline issues. Volumes were down sequentially due to natural production declines, the temporary shut-in of four producing Goudy Marcellus Shale wells and three Simms Marcellus Shale wells in April 2014 in anticipation of completion or drilling operations on their respective pads. The four Goudy wells were returned to production in July 2014 and the Simms wells should be returned to production by late August 2014.
In Marshall County, West Virginia, we had anticipated completing three additional gross (1.5 net) Marcellus Shale wells on the Goudy pad late in the first quarter of 2014, but completion continues to be delayed pending the resolution of a non-lessee surface owner dispute. Currently, we plan to complete seven gross (3.5 net) wells on the Armstrong pad and three gross (1.5 net) wells from the Hansen pad in the fourth quarter of 2014. The completion of these wells has been delayed while the designated rig was drilling the Utica/Point Pleasant well. By year-end 2014, we expect 67 total gross operated Marcellus wells to be capable of production in the area.
Our previously announced 2014 capital budget for Appalachia has been increased by $17 million to $86 million to fund additional Utica/Point Pleasant and Marcellus Shale drilling. The new capital expenditure budget is comprised of $77 million for drilling, completion and infrastructure costs and $9 million for acreage. Net capital expenditures in Appalachia for the second quarter of 2014 totaled $12 million, resulting in current year to date total capital expenditures of $20 million.
Guidance for the Third Quarter of 2014
We are updating previously issued guidance for the full-year 2014 and providing the following guidance for the third quarter of 2014:
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Production | Third Quarter 2014 | Full-Year 2014 | |
Net average daily (MBoe/d)(1) | 9.5 - 9.9 | 10.2 - 10.6 | |
Liquids percentage | 44% - 47% | 45% - 48% | |
Cash Operating Expenses ($ / Boe) | Third Quarter 2014 | Full-Year 2014 | |
Production taxes | $1.60 - $1.70 | $1.70 - $1.90 | |
Direct lease operating | $5.25 - $5.50 | $5.00 - $5.30 | |
Transportation, treating & gathering | $0.60 - $0.70 | $0.60 - $0.70 | |
Cash general & administrative | $3.20 - $3.35 | $3.00 - $3.30 | |
________________
(1) | Based on equivalent of 6 thousand cubic feet (“Mcf”) of natural gas to one barrel of oil, condensate or NGLs. |
Liquidity
At June 30, 2014 we had $24.8 million in available cash and cash equivalents and an undrawn $100.0 million on our revolving credit facility. We expect to fund our remaining 2014 capital program through existing cash balances, internally generated cash flow from operating activities, borrowings under the revolving credit facility, possible divestiture of assets and the possible issuance of debt or equity securities or some combination thereof.
Conference Call
Gastar has scheduled a conference call for 11:00 a.m. Eastern Time (10:00 a.m. Central Time) on Friday, August 8. Investors may participate in the call either by phone or audio webcast.
By Phone: | Dial 1-888-450-9962 at least 10 minutes before the call. A telephone replay will be available through August 15 by dialing 1-800-804-7944 and using the conference ID 47755. |
By Webcast: | Visit the Investor Relations page of Gastar's website at www.gastar.com under “Events & Presentations.” Please log on at least 10 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.
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About Gastar
Gastar Exploration Inc. is an independent energy company engaged in the exploration, development and production of oil, natural gas, condensate and NGLs 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. Gastar is currently pursuing development within the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play in Oklahoma and the development of liquids-rich natural gas in the Marcellus Shale play and dry gas in the Utica Shale play in West Virginia. For more information, visit Gastar's website at www.gastar.com.
Forward Looking Statements
This news release 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 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 with respect to natural gas and oil prices, a material decline in which could cause Gastar to delay or suspend planned drilling operations or reduce production levels; 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 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 fourth party consents; risks relating to our ability to integrate acquired assets with ours and to realize the anticipated benefits from such acquisitions; 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
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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.
Gastar’s capital budget is subject to revision and reevaluation dependent upon future developments including drilling results, availability of crews, supplies and production capacity, weather delays, significant changes in commodities prices or drilling costs.
- Financial Tables Follow -
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GASTAR EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, | For the Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2013 | 2012 | ||||||||||||
(in thousands, except share and per share data) | |||||||||||||||
REVENUES: | |||||||||||||||
Oil and condensate | $ | 22,342 | $ | 8,065 | $ | 39,120 | $ | 13,350 | |||||||
Natural gas | 17,559 | 12,413 | 32,978 | 20,014 | |||||||||||
NGLs | 4,906 | 3,412 | 11,550 | 5,792 | |||||||||||
Total oil, condensate, natural gas and NGLs revenues | 44,807 | 23,890 | 83,648 | 39,156 | |||||||||||
(Loss) gain on commodity derivatives contracts | (8,910 | ) | 7,036 | (15,424 | ) | 3,034 | |||||||||
Total revenues | 35,897 | 30,926 | 68,224 | 42,190 | |||||||||||
EXPENSES: | |||||||||||||||
Production taxes | 2,037 | 1,150 | 3,931 | 1,793 | |||||||||||
Lease operating expenses | 4,877 | 2,169 | 8,921 | 4,006 | |||||||||||
Transportation, treating and gathering | 2,146 | 1,124 | 2,771 | 2,288 | |||||||||||
Depreciation, depletion and amortization | 10,280 | 7,596 | 22,662 | 12,961 | |||||||||||
Accretion of asset retirement obligation | 125 | 114 | 247 | 216 | |||||||||||
General and administrative expense | 3,893 | 4,964 | 8,656 | 7,966 | |||||||||||
Litigation settlement expense | — | — | — | 1,000 | |||||||||||
Total expenses | 23,358 | 17,117 | 47,188 | 30,230 | |||||||||||
INCOME FROM OPERATIONS | 12,539 | 13,809 | 21,036 | 11,960 | |||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||
Gain on acquisition of assets at fair value | — | 43,712 | — | 43,712 | |||||||||||
Interest expense | (6,912 | ) | (3,545 | ) | (13,803 | ) | (4,154 | ) | |||||||
Investment income and other | 4 | 5 | 11 | 8 | |||||||||||
Foreign transaction loss | (4 | ) | (11 | ) | (6 | ) | (12 | ) | |||||||
INCOME BEFORE PROVISION FOR INCOME TAXES | 5,627 | 53,970 | 7,238 | 51,514 | |||||||||||
Provision for income taxes | — | — | — | — | |||||||||||
NET INCOME | 5,627 | 53,970 | 7,238 | 51,514 | |||||||||||
Dividends on preferred stock | (3,611 | ) | (2,134 | ) | (7,187 | ) | (4,264 | ) | |||||||
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ | 2,016 | $ | 51,836 | $ | 51 | $ | 47,250 | |||||||
NET INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS: | |||||||||||||||
Basic | $ | 0.03 | $ | 0.83 | $ | — | $ | 0.75 | |||||||
Diluted | $ | 0.03 | $ | 0.81 | $ | — | $ | 0.74 | |||||||
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING: | |||||||||||||||
Basic | 58,702,982 | 62,398,472 | 58,462,124 | 63,089,987 | |||||||||||
Diluted | 61,922,874 | 63,813,423 | 61,674,267 | 63,699,525 | |||||||||||
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GASTAR EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, 2014 | December 31, 2013 | ||||||
(in thousands, except share data) | |||||||
ASSETS | |||||||
CURRENT ASSETS: | |||||||
Cash and cash equivalents | $ | 24,763 | $ | 32,393 | |||
Accounts receivable, net of allowance for doubtful accounts of $0 and $507, respectively | 20,406 | 21,656 | |||||
Commodity derivative contracts | 223 | — | |||||
Prepaid expenses | 982 | 1,145 | |||||
Total current assets | 46,374 | 55,194 | |||||
PROPERTY, PLANT AND EQUIPMENT: | |||||||
Oil and natural gas properties, full cost method of accounting: | |||||||
Unproved properties, excluded from amortization | 104,545 | 96,220 | |||||
Proved properties | 1,000,211 | 935,773 | |||||
Total oil and natural gas properties | 1,104,756 | 1,031,993 | |||||
Furniture and equipment | 2,849 | 2,691 | |||||
Total property, plant and equipment | 1,107,605 | 1,034,684 | |||||
Accumulated depreciation, depletion and amortization | (539,833 | ) | (517,171 | ) | |||
Total property, plant and equipment, net | 567,772 | 517,513 | |||||
OTHER ASSETS: | |||||||
Commodity derivative contracts | 2,009 | 7,545 | |||||
Deferred charges, net | 2,901 | 2,950 | |||||
Advances to operators and other assets | 7,464 | 6,733 | |||||
Total other assets | 12,374 | 17,228 | |||||
TOTAL ASSETS | $ | 626,520 | $ | 589,935 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
CURRENT LIABILITIES: | |||||||
Accounts payable | $ | 11,921 | $ | 11,046 | |||
Revenue payable | 27,386 | 12,514 | |||||
Accrued interest | 3,528 | 3,504 | |||||
Accrued drilling and operating costs | 5,591 | 8,756 | |||||
Advances from non-operators | 9,785 | 9,259 | |||||
Commodity derivative contracts | 6,626 | 3,403 | |||||
Commodity derivative premium payable | 1,377 | 145 | |||||
Asset retirement obligation | 42 | 633 | |||||
Other accrued liabilities | 3,169 | 4,844 | |||||
Total current liabilities | 69,425 | 54,104 | |||||
LONG-TERM LIABILITIES: | |||||||
Long-term debt | 334,120 | 312,994 | |||||
Commodity derivative contracts | 234 | 378 | |||||
Commodity derivative premium payable | 5,952 | 7,000 | |||||
Asset retirement obligation | 5,767 | 5,430 | |||||
Total long-term liabilities | 346,073 | 325,802 | |||||
Commitments and contingencies | |||||||
STOCKHOLDERS' EQUITY: | |||||||
Preferred stock, 40,000,000 shares authorized | |||||||
Series A Preferred stock, $0.01 par value; 10,000,000 shares authorized; 4,045,000 and 3,958,160 shares issued and outstanding at June 30, 2014 and December 31, 2013, respectively, with liquidation preference of $25.00 per share | 41 | 40 | |||||
Series B Preferred stock, $0.01 par value; 10,000,000 shares authorized; 2,140,000 shares issued and outstanding at June 30, 2014 and December 31, 2013, respectively, with liquidation preference of $25.00 per share | 21 | 21 | |||||
Common stock, $0.001 par value; 275,000,000 shares authorized; 61,796,023 and 61,211,658 shares issued and outstanding at June 30, 2014 and December 31, 2013, respectively | 61 | 61 | |||||
Additional paid-in capital | 465,671 | 464,730 | |||||
Accumulated deficit | (254,772 | ) | (254,823 | ) | |||
Total stockholders' equity | 211,022 | 210,029 | |||||
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 626,520 | $ | 589,935 | |||
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GASTAR EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
(in thousands) | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||
Net income | $ | 7,238 | $ | 51,514 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 22,662 | 12,961 | |||||
Stock-based compensation | 2,532 | 1,966 | |||||
Mark to market of commodity derivatives contracts: | |||||||
Total loss on commodity derivatives contracts | 15,424 | (3,034 | ) | ||||
Cash settlements of matured commodity derivatives contracts, net | (6,061 | ) | 5,596 | ||||
Cash premiums paid for commodity derivatives contracts | (155 | ) | (27 | ) | |||
Amortization of deferred financing costs | 1,491 | 1,450 | |||||
Accretion of asset retirement obligation | 247 | 216 | |||||
Settlement of asset retirement obligation | (546 | ) | — | ||||
Gain on acquisition of assets at fair value | — | (43,712 | ) | ||||
Changes in operating assets and liabilities: | |||||||
Accounts receivable | (2,827 | ) | 29 | ||||
Prepaid expenses | 112 | 259 | |||||
Accounts payable and accrued liabilities | 9,649 | 9,814 | |||||
Net cash provided by operating activities | 49,766 | 37,032 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||
Development and purchase of oil and natural gas properties | (55,295 | ) | (55,955 | ) | |||
Advances to operators | (20,657 | ) | (5,154 | ) | |||
Acquisition of oil and natural gas properties - refund (expenditure) | 4,209 | (69,775 | ) | ||||
Sale of oil and natural gas properties | 3,077 | 2,300 | |||||
Proceeds from non-operators | 526 | 12,874 | |||||
Purchase of furniture and equipment | (158 | ) | (151 | ) | |||
Net cash used in investing activities | (68,298 | ) | (115,861 | ) | |||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||
Proceeds from revolving credit facility | 35,000 | 19,000 | |||||
Repayment of revolving credit facility | (15,000 | ) | (117,000 | ) | |||
Proceeds from issuance of senior secured notes, net of discount | — | 194,500 | |||||
Repurchase of outstanding common shares | — | (9,753 | ) | ||||
Proceeds from issuance of preferred stock, net of issuance costs | 2,064 | 133 | |||||
Dividends on preferred stock | (7,187 | ) | (3,554 | ) | |||
Deferred financing charges | (319 | ) | (2,355 | ) | |||
Tax withholding related to restricted stock and PBU vestings | (3,656 | ) | (244 | ) | |||
Net cash provided by financing activities | 10,902 | 80,727 | |||||
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS | (7,630 | ) | 1,898 | ||||
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 32,393 | 8,901 | |||||
CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 24,763 | $ | 10,799 | |||
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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 Income to Net Income Excluding Special Items:
For the Three Months Ended June 30, | For the Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
(in thousands, except share and per share data) | |||||||||||||||
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS AS REPORTED (1) | $ | 2,016 | $ | 51,836 | $ | 51 | $ | 47,250 | |||||||
SPECIAL ITEMS: | |||||||||||||||
Losses (gains) related to the change in mark to market value for outstanding commodity derivatives contracts | 5,418 | (7,485 | ) | 8,573 | 2,152 | ||||||||||
Non-recurring general and administrative costs related to acquisition of assets | — | 1,418 | 30 | 1,418 | |||||||||||
Non-recurring general and administrative costs related to Parent migration | 13 | 227 | 218 | 269 | |||||||||||
Litigation settlement expense | — | — | — | 1,000 | |||||||||||
Gain on acquisition of assets at fair value | — | (43,712 | ) | — | (43,712 | ) | |||||||||
Write off of fees associated with old amended revolving credit facility | — | 1,154 | — | 1,154 | |||||||||||
Foreign transaction loss | 4 | 11 | 6 | 12 | |||||||||||
ADJUSTED NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ | 7,451 | $ | 3,449 | $ | 8,878 | $ | 9,543 | |||||||
ADJUSTED NET INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS: | |||||||||||||||
Basic | $ | 0.13 | $ | 0.06 | $ | 0.15 | $ | 0.15 | |||||||
Diluted | $ | 0.12 | $ | 0.05 | $ | 0.14 | $ | 0.15 | |||||||
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING: | |||||||||||||||
Basic | 58,702,982 | 62,398,472 | 58,462,124 | 63,089,987 | |||||||||||
Diluted | 61,922,874 | 63,813,423 | 61,674,267 | 63,699,525 | |||||||||||
_________________________________
(1) | The three and six months ended June 30, 2014 include the benefit of an $8.6 million one-time adjustment related to an arbitration settlement. |
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Reconciliation of Cash Flows before Working Capital Changes and as Adjusted for Special Items:
For the Three Months Ended June 30, | For the Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(in thousands) | ||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||||||
Net income (1) | $ | 5,627 | $ | 53,970 | $ | 7,238 | $ | 51,514 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Depreciation, depletion and amortization | 10,280 | 7,596 | 22,662 | 12,961 | ||||||||||||
Stock-based compensation | 999 | 1,143 | 2,532 | 1,966 | ||||||||||||
Mark to market of commodity derivatives contracts: | ||||||||||||||||
Total loss (gain) on commodity derivatives contracts | 8,910 | (7,036 | ) | 15,424 | (3,034 | ) | ||||||||||
Cash settlements of matured commodity derivatives contracts, net | (3,046 | ) | (164 | ) | (6,061 | ) | 5,596 | |||||||||
Cash premiums paid for commodity derivatives contracts | (84 | ) | — | (155 | ) | (27 | ) | |||||||||
Amortization of deferred financing costs | 758 | 1,372 | 1,491 | 1,450 | ||||||||||||
Accretion of asset retirement obligation | 125 | 114 | 247 | 216 | ||||||||||||
Settlement of asset retirement obligation | (289 | ) | — | (546 | ) | — | ||||||||||
Gain on acquisition of assets at fair value | — | (43,712 | ) | — | (43,712 | ) | ||||||||||
Cash flows from operations before working capital changes | 23,280 | 13,283 | 42,832 | 26,930 | ||||||||||||
Litigation settlement expense | — | — | — | 1,000 | ||||||||||||
Foreign transaction loss | 4 | 11 | 6 | 12 | ||||||||||||
Dividends on preferred stock | (3,611 | ) | (2,134 | ) | (7,187 | ) | (4,264 | ) | ||||||||
Non-recurring general and administrative costs related to acquisition of assets | — | 1,418 | 30 | 1,418 | ||||||||||||
Non-recurring general and administrative costs related to Parent migration | 13 | 227 | 218 | 269 | ||||||||||||
Adjusted cash flows from operations | $ | 19,686 | $ | 12,805 | $ | 35,899 | $ | 25,365 | ||||||||
_________________________________
(1) | The three and six months ended June 30, 2014 include the benefit of an $8.6 million one-time adjustment related to an arbitration settlement. |
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Reconciliation of Net Income to Adjusted Earnings Before Interest, Income Taxes, Depreciation, Depletion and Amortization ("Adjusted EBITDA"):
For the Three Months Ended June 30, | For the Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
(in thousands, except share and per share data) | |||||||||||||||
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS AS REPORTED (1) | $ | 2,016 | $ | 51,836 | $ | 51 | $ | 47,250 | |||||||
Interest expense | 6,912 | 3,545 | 13,803 | 4,154 | |||||||||||
Depreciation, depletion and amortization | 10,280 | 7,596 | 22,662 | 12,961 | |||||||||||
EBITDA | 19,208 | 62,977 | 36,516 | 64,365 | |||||||||||
Dividend expense | 3,611 | 2,134 | 7,187 | 4,264 | |||||||||||
Accretion of asset retirement obligation | 125 | 114 | 247 | 216 | |||||||||||
Gain on acquisition of assets at fair value | — | (43,712 | ) | — | (43,712 | ) | |||||||||
Losses (gains) related to the change in mark to market value for outstanding commodity derivatives contracts | 5,418 | (7,485 | ) | 8,573 | 2,152 | ||||||||||
Non-cash stock compensation expense | 999 | 1,143 | 2,532 | 1,966 | |||||||||||
Litigation settlement expense | — | — | — | 1,000 | |||||||||||
Foreign transaction loss | 4 | 11 | 6 | 12 | |||||||||||
Investment income and other | (4 | ) | (5 | ) | (11 | ) | (8 | ) | |||||||
Non-recurring general and administrative costs related to acquisition of assets | — | 1,418 | 30 | 1,418 | |||||||||||
Non-recurring general and administrative costs related to Parent migration | 13 | 227 | 218 | 269 | |||||||||||
Adjusted EBITDA | $ | 29,374 | $ | 16,822 | $ | 55,298 | $ | 31,942 | |||||||
_________________________________
(1) | The three and six months ended June 30, 2014 include the benefit of an $8.6 million one-time adjustment related to an arbitration settlement. |
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