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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
FOURTH QUARTER 2013 RESULTS
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| • | 4Q revenue nearly doubles, production up 30% year over year |
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| • | Liquids represent 65% of total revenue |
HOUSTON, March 13, 2014 - Gastar Exploration Inc. (NYSE MKT: GST) ("Gastar") today reported financial and operating results for the three months and the year ended December 31, 2013.
Net loss attributable to Gastar’s common stockholders for the fourth quarter of 2013 was $3.3 million, or a loss of $0.06 per share. Excluding the impact of a $2.8 million loss resulting from the mark-to-market of outstanding hedge positions at December 31, 2013 and non-recurring corporate restructuring charges of $1.2 million, adjusted net income attributable to common stockholders was $0.7 million, or $0.01 per diluted share.
This compares to fourth quarter 2012 net income of $2.9 million, or $0.05 per diluted share, and adjusted net income of $4.6 million, or $0.07 per diluted share, excluding the impact of a $1.4 million loss resulting from the mark-to-market of outstanding hedge positions at December 31, 2012 and non-recurring charges of $206,000. (See the accompanying reconciliation of net income (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 fourth quarter of 2013 was $21.2 million, or $0.35 per diluted share, an increase of 59% compared to adjusted EBITDA of $13.4 million, or $0.21 per diluted share, for the fourth quarter of 2012 and a 24% increase over adjusted third quarter 2013 results. (See the accompanying reconciliation of net income (loss) to adjusted EBITDA at the end of this news release.)
Natural gas, oil, condensate and natural gas liquids (NGLs) revenues before the impact of hedging activities increased 99% to $29.2 million in the fourth quarter of 2013, up from $14.7 million for the same
period of 2012. The increase was primarily the result of 30% growth in production volumes and a 53% increase in the weighted average sales price per thousand cubic feet of natural gas equivalent (Mcfe) before the positive impact of commodity derivative contracts settled during the period. Revenues from liquids (oil, condensate and NGLs) represented approximately 65% of our total production revenues for the fourth quarter of 2013 compared to 58% for the third quarter of 2013 and 44% for the fourth quarter of 2012. Commodity derivative contracts settled during the periods resulted in additional revenues for the fourth quarter of 2013 and 2012 of $288,000 and $4.1 million, respectively.
Average daily production was 55.2 million cubic feet of natural gas equivalent per day (MMcfe/d), or 9,200 barrels of oil equivalent per day (Boe/d), for the fourth quarter of 2013, a 30% increase compared to 42.5 MMcfe/d (7,080 Boe/d) for the same period in 2012. Oil, condensate and NGLs as a percentage of production volumes was 39% in the fourth quarter of 2013 compared to 24% in the fourth quarter of 2012. Higher year-over-year production volumes were primarily driven by our horizontal drilling activity in the Marcellus Shale and Hunton Limestone as well as the acquisition of producing assets in the Mid-Continent, partially offset by the sale of producing assets in East Texas. Sequentially, average daily production decreased 7% due to the sale of East Texas assets on October 2, 2013, partially offset by new Hunton well completions and production from our WEHLU acquisition in Oklahoma which closed on November 15, 2013. Oil, condensate and NGLs as a percentage of production volumes increased 10% sequentially.
The following table provides a summary of Gastar’s production volumes and average commodity prices for the three-months and years ended December 31, 2013 and 2012:
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| | | | | | | | | | | | | | | | |
| | | For the Three Months Ended December 31, | | For the Years Ended December 31, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | | |
| Production: | | | | | | | | |
| Natural gas (MMcf) | | 3,108 |
| | 2,980 |
| | 13,366 |
| | 10,564 |
|
| Oil and condensate (MBbl) | | 182 |
| | 71 |
| | 515 |
| | 177 |
|
| NGLs (MBbl) | | 147 |
| | 84 |
| | 494 |
| | 270 |
|
| Total production by equivalent: | | | | | | | | |
| MMcfe | | 5,080 |
| | 3,908 |
| | 19,417 |
| | 13,247 |
|
| MBoe | | 847 |
| | 651 |
| | 3,236 |
| | 2,208 |
|
| | | | | | | | | |
| Average daily production by equivalent: | | | | | | | | |
| MMcfe/d | | 55.2 |
| | 42.5 |
| | 53.2 |
| | 36.2 |
|
| MBoe/d | | 9.2 |
| | 7.1 |
| | 8.9 |
| | 6.0 |
|
| | | | | | | | | |
| Average sales price per unit: | | | | | | | | |
Natural gas per Mcf, including impact of hedging(1) | | $ | 3.58 |
| | $ | 3.80 |
| | $ | 3.43 |
| | $ | 3.20 |
|
Natural gas per Mcf, excluding impact of hedging(1) | | $ | 3.31 |
| | $ | 2.77 |
| | $ | 3.02 |
| | $ | 2.21 |
|
Oil and condensate per Bbl, including impact of hedging(1) | | $ | 75.62 |
| | $ | 65.61 |
| | $ | 71.04 |
| | $ | 70.01 |
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Oil and condensate per Bbl, excluding impact of hedging(1) | | $ | 75.75 |
| | $ | 60.19 |
| | $ | 70.91 |
| | $ | 65.45 |
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NGLs per Bbl, including impact of hedging(1) | | $ | 31.93 |
| | $ | 34.59 |
| | $ | 31.13 |
| | $ | 34.40 |
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NGLs per Bbl, excluding impact of hedging(1) | | $ | 35.34 |
| | $ | 26.46 |
| | $ | 31.59 |
| | $ | 28.22 |
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| | | | | | | | | |
Average sales price per Mcfe, including impact of hedging(1) | | $ | 5.81 |
| | $ | 4.83 |
| | $ | 5.03 |
| | $ | 4.19 |
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Average sales price per Mcfe, excluding impact of hedging(1) | | $ | 5.76 |
| | $ | 3.77 |
| | $ | 4.76 |
| | $ | 3.21 |
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Average sales price per Boe, including impact of hedging(1) | | $ | 34.89 |
| | $ | 28.97 |
| | $ | 30.20 |
| | $ | 25.14 |
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Average sales price per Boe, excluding impact of hedging(1) | | $ | 34.55 |
| | $ | 22.61 |
| | $ | 28.58 |
| | $ | 19.26 |
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_____________________________
(1) The impact of hedging is defined as the gain (loss) on commodity derivative contracts settled during the period.
We had natural gas price hedges in place covering approximately 76% of natural gas production and oil price hedges covering approximately 82% of our combined oil, condensate and NGLs production for the fourth 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 $3.3 million for the fourth quarter of 2013, compared to $1.4 million in the fourth quarter of 2012 and $2.2 million in the third quarter of 2013. The increase in LOE compared to the prior-year period was primarily due to the additional expenses associated with the Chesapeake acquisition, the oil dominated WEHLU acquisition and with higher overall costs associated with producing higher-value oil versus natural gas. LOE per Boe of production increased to $3.85 in the fourth quarter of 2013 from $2.18 in the fourth quarter of 2012 and $2.41 in the third quarter of 2013.
Depreciation, depletion and amortization (DD&A) was $11.0 million in the fourth quarter of 2013, up from $5.7 million in the prior-year period and $8.5 million in the third quarter of 2013. The year-over-year increase in DD&A expense was the result of the purchase of the WEHLU oil producing properties in Oklahoma. The DD&A rate for the fourth quarter of 2013 was $13.02 per Boe compared to $8.72 per Boe for the same period in 2012 and $9.31 in the third quarter of this year.
General and administrative (G&A) expense was $5.0 million in the fourth quarter of 2013, compared to $2.9 million in the prior-year period. G&A expense for the most recent quarter included $1.2 million of non-recurring expenses related to acquisitions and to the reorganization to eliminate Gastar's holding company corporate structure and $895,000 of non-cash, stock-based compensation expense; whereas the prior-year period included $206,000 related to the reorganization of Gastar's corporate structure and $720,000 for stock-based compensation. Excluding these items, recurring cash G&A expense increased to $2.9 million for the fourth quarter of 2013 compared to $2.0 million in the fourth quarter of 2012. The increase in 2013 recurring cash G&A expense was primarily related to additional staff costs associated with the operation and administration of our growing property base.
With the completion of the Chesapeake acquisition asset valuation during the fourth quarter of 2013, the gain on acquisition of assets at fair value was reduced by the application of a deferred tax liability of $16.0 million resulting in the presentation of a fourth quarter 2013 fair market value loss. This was directly offset by the recognition of a corresponding deferred income tax benefit of $16.0 million arising from the resulting decrease in our valuation allowance for deferred tax assets.
Interest expense totaled $5.6 million in the fourth quarter of 2013, compared with $184,000 in the fourth quarter of 2012. The increase was the result of the issuance in 2013 of $325 million aggregate principal amount of new 8 5/8% Senior Secured Notes Due 2018.
J. Russell Porter, Gastar's President and CEO, stated, “Gastar’s fourth quarter results partially reflect the benefits of our recent acquisitions and divestitures, which resulted in a more favorable production mix with 39% of total volumes comprised of higher-value liquids. As a result, revenue from production and adjusted EBITDA were up sharply quarter over quarter, as well as year over year. We believe our recent acquisitions will result in significant future production growth that will yield solid returns going forward.
“We made progress during the fourth quarter toward de-risking and delineating the oil potential of our operated Hunton acreage in Oklahoma. Our first three operated wells were spread broadly across our 126,000 net-acre position, and all encountered oil in the Lower Hunton formation. We believe the Lower Hunton will be a statistical play and should provide average results consistent with our published type
curves. While our first two operated wells are currently producing at rates below our type curve, we believe this is due to mechanical and operational complications related to the highly fractured nature of the Hunton in the areas where these wells were drilled as we encountered more fractures and larger fractures within these wells than previously found in our non-operated Hunton Area of Mutual Interest (AMI). Our third operated well was placed on flow-back last week and results should be known during the second quarter of 2014.”
“The first well drilled on our newly acquired WEHLU acreage will spud in April to test the Lower Hunton, followed immediately by the spudding of an Upper Hunton WEHLU well test. On our non-operated Hunton AMI acreage, the operator is continuing to run two rigs, which should drive steady increases in our crude oil production.”
“In addition to the Hunton potential on our 126,000 net acre position, we also believe that a meaningful amount of our acreage will be prospective for development of the Woodford Shale and Meramec Mississippian formations. We have not yet attempted to catalog the potential related to these additional development targets.”
“In Appalachia, we are ramping up activity and plan to place at least 13 Marcellus wells on production during the remainder of this year. We are also in the final stages of completing acreage trades with other operators in the area that when completed will substantially increase our future Marcellus and Utica drilling locations. We have identified 73 incremental drilling locations, including locations related to pending acreage trades, in our liquids-rich gas area, and we now have a total of 112 Marcellus Shale drilling locations identified for future development in Marshall and Wetzel Counties, West Virginia.”
“We plan to spud our first Utica Shale test well in early April, and we are highly encouraged by the results of several other operators in close proximity to our acreage. Based on the nearby activity, we believe that the Utica underlies all of our acreage in Marshall and Wetzel counties, providing Gastar with an estimated 114 gross Utica drilling locations based on 1000-foot spacing between wells. Although this is in the dry gas window of the Utica, the high production rates of nearby operators indicate that each well could contain significant recoverable reserves, providing very attractive individual well returns as well as the ability to meaningfully increase Gastar’s per share net asset value,” concluded Porter.
Operations Review and Update
Appalachia
Net production from the Marcellus Shale area averaged 41.0 MMcfe/d (6,830 Boe/d) in the fourth quarter of 2013, compared to 29.9 MMcfe/d (4,990 Boe/d) for the fourth quarter of 2012 and 43.0 MMcfe/d (7,160 Boe/d) in the third quarter of 2013. Our liquids-rich gas production, on average, yielded
approximately 30 barrels of condensate and 52 barrels of NGLs per million cubic feet (MMcf) of natural gas sold during for the fourth quarter of 2013
During October 2013, Marcellus production was negatively impacted by a leak in the third-party operated pipeline which resulted in an estimated loss of approximately 1.3 MMcfe/d of net production for the fourth quarter of 2013. Beyond this isolated issue, it appears that substantially all of the midstream-related curtailment issues we experienced in 2013 have been resolved.
We had 57 gross (27.0 net) operated wells on production in Marshall County, West Virginia during the fourth quarter of 2013, and no additional wells were completed during the period. In 2014, to develop the Marcellus Shale, we are operating a smaller rig to drill the vertical top section of wells and a larger rig to drill the horizontal lateral sections. In late February 2014, we completed drilling the top-hole sections of nine wells on the Armstrong pad and expect to drill the lateral, complete and begin producing five of those wells in the third quarter of 2014. Top-hole drilling recently commenced at the Hansen pad, where five wells are planned and are expected to be placed on production in the fourth quarter of 2014.
We anticipate our next three Marcellus Shale wells will be placed on production late in the second quarter of 2014 from our Goudy pad in Marshall County, West Virginia. We expect total gross operated wells on production in the area to be approximately 71 by year-end 2014.
Net capital expenditures in the Marcellus Shale for the fourth quarter of 2013 totaled $7.9 million. As previously announced, we have budgeted for capital expenditures in Appalachia totaling $68 million in 2014, of which $54 million is for drilling and completion, $9 million is for acreage costs and $5 million is for infrastructure costs.
Mid-Continent
Net production from the Mid-Continent area averaged 14.1 MMcfe/d (2,350 Boe/d) in the fourth quarter of 2013, compared to 0.1 MMcfe/d (20 Boe/d) for the fourth quarter of 2012 and 7.0 MMcfe/d (1,170 Boe/d) in the third quarter of 2013. Our fourth quarter 2013 Mid-Continent production consisted of approximately 49% oil, 43% natural gas and 8% NGLs, yielding a liquids to total equivalent production percentage of 57%.
At December 31, 2013, we held leases covering approximately 209,100 gross (126,000 net) acres in Major, Garfield, Canadian, Kingfisher, Logan, Blaine and Oklahoma Counties, Oklahoma within the Hunton Limestone horizontal oil play.
Our first three operated wells have been completed and placed on production. The Burton 16-1H started flowback in early December 2013 and achieved peak production of 111 Boe/d (65% oil) in January 2014.
The Townsend 06-1H started flowback in early January 2014 and production is continuing to increase with its most recently reported five-day production average rate at 271 Boe/d (53% oil). The wells continue to flow back completion fluid at a combined average rate of approximately 600 barrels per day. The Taborek 22-1H was completed using a different completion technique in order to minimize reservoir damage and flowback has just commenced.
Within the Hunton AMI, Gastar participated in two gross (1.0 net) non-operated wells that were completed and placed on production during the fourth quarter of 2013. The previously announced Mid-Con 6H and 7H wells average initial production rates were 1,442 (86% oil) and 906 (72% oil) Boe/d, respectively, and the most recent 10-day average production was 852 (45% oil) and 123 (50% oil) Boe/d, respectively. The Mid-Con 7H, which flowed naturally for approximately three months, was just recently placed on gas lift and operations are in process to calibrate artificial lift and maximize production flow. Subsequent to year-end, two gross (1.0 net) non-operated wells were placed on production and four gross (1.7 net) wells within the AMI are in various stages of completion or drilling.
During the first quarter of 2014, we anticipate three gross (1.1 net) non-operated AMI wells and one gross (0.9 net) operated well being placed on production.
In the Mid-Continent, net capital expenditures in the fourth quarter of 2013, excluding acquisition costs and divestment proceeds, totaled $25.1 million. We expect to spend approximately $114 million during 2014 on our Mid-Continent play, of which approximately $87 million is for drilling and completion related expenses.
Guidance for the First Quarter of 2014
We are reaffirming previously issued guidance for the full-year 2014 and providing the following guidance for the first quarter of 2014:
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| | | |
| Production | First Quarter 2014 | | Full-Year 2014 |
| | | | |
Net average daily (MBoe/d)(1) | 9.3 - 9.7 | | 9.7 - 11.0 |
| Liquids percentage | 39% - 41% | | 40% - 44% |
| | | | |
| Cash Operating Expenses ($ / Boe) | First Quarter 2014 | | Full-Year 2014 |
| Production taxes | $2.10 - $2.30 | | $1.95 - $2.25 |
| Direct lease operating | $4.65 - $5.10 | | $4.55 - $5.10 |
| Transportation, treating & gathering | $0.70 - $0.80 | | $0.60 - $0.65 |
| Cash general & administrative | $3.40 - $3.70 | | $2.90 - $3.20 |
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(1) Based on equivalent of 6 thousand cubic feet (Mcf) of natural gas to one barrel of oil, condensate or NGLs.
Liquidity
At December 31, 2013 we had $32.4 million in available cash and an undrawn $100 million revolving credit facility. We expect to fund our 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.
2013 Proved Reserves
As previously reported, proved reserves as of December 31, 2013 increased by 81% to 327.8 Bcfe (54.6 MMBoe), composed of 14.7 million barrels of crude oil and condensate, 9.8 million barrels of natural gas liquids and 180.7 Bcf of natural gas. Of the total proved reserves, 45% are liquids and 57% are classified as proved developed. The pre-tax SEC-priced present value of future cash flows of these reserves, discounted at 10% ("PV-10") (a non-GAAP financial measure defined below in Information on Reserves and PV-10 Value), grew 187% to $592.5 million as compared to year-end 2012.
The year-over-year net increase in proved reserves consisted of:
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| • | 92.9 Bcfe (15.5 MMBoe) of proved reserve additions (pre-tax PV-10 value of $196.4 million); plus |
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| • | 87.8 Bcfe (14.6 MMBoe) of proved reserves purchased (pre-tax PV-10 value of $247.2 million); plus |
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| • | 10.4 Bcfe (1.7 MMBoe) of positive performance and price revisions; less |
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| • | 24.8 Bcfe (4.1 MMBoe) of proved reserves that were divested in 2013. |
We replaced 857% of production from all sources including reserve additions from drilling activity, price and performance revisions, and proved acquisitions less divestments. We replaced 532% of production through drilling activity and price and performance revisions. Capital expenditures for 2013 totaled $292.5 million, comprised of $24.0 million for unproved acreage and related costs, $90.0 million for drilling expenditures and $178.5 million for property acquisition costs. Acquisition costs are net of proceeds of $58.6 million received for the sale of certain unproven properties acquired in the Chesapeake acquisition.
Conference Call
Gastar has scheduled a conference call for 10:00 a.m. Eastern Time (9:00 a.m. Central Time) tomorrow. Investors may participate in the call either by phone or audio webcast.
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| By Phone: | Dial 1-888-450-9962 at least 10 minutes before the call. A telephone replay will be available through March 21 by dialing 1-800-804-7944 and using the conference ID 41261. |
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| By Webcast: | Visit the Investor Relations page of Gastar's website at www.gastar.com. 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.
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For more information, please contact Donna Washburn at Dennard-Lascar Associates at 713-529-6600 or e-mail dwashburn@DennardLascar.com.
About Gastar
Gastar Exploration Inc. is an independent energy company engaged in the exploration, development and production of oil, natural gas, condensate 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. Gastar is currently pursuing the development of liquids-rich natural gas in the Marcellus Shale in West Virginia and is also in the early stages of exploring and developing the Hunton Limestone horizontal oil play in Oklahoma. For more information, visit Gastar's website at www.gastar.com.
Information on Reserves and PV-10 Value
For the years ended December 31, 2013 and 2012 future cash inflows were computed using the 12-month un-weighted arithmetic average of the first-day-of-the-month prices for natural gas and oil (the "benchmark base prices") adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials, relating to the Company's proved reserves. Benchmark base prices are held constant in accordance with SEC guidelines for the life of the wells but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression, and gathering fees and regional price differentials. PV-10 Value is a non-GAAP measure and is different than the Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure"), which measure totals $515.8 million and will be
presented in Gastar's upcoming Form 10-K, in that PV-10 Value is a pre-tax number, while the Standardized Measure includes the effect of estimated future income taxes.
The Company's 2013 year-end total proved reserves estimates were prepared by Wright & Company, Inc.
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 U.S. Securities and Exchange Commission (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.
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 -
GASTAR EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended December 31, | | For the Years Ended December 31, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | (in thousands, except share and per share data) |
| REVENUES: | | | | | | | |
| Natural gas | $ | 10,303 |
| | $ | 8,254 |
| | $ | 40,416 |
| | $ | 23,318 |
|
| Oil and condensate | 13,749 |
| | 4,247 |
| | 36,480 |
| | 11,570 |
|
| NGLs | 5,196 |
| | 2,223 |
| | 15,611 |
| | 7,630 |
|
| Total natural gas, condensate and oil and NGLs revenues | 29,248 |
| | 14,724 |
| | 92,507 |
| | 42,518 |
|
| (Loss) gain on commodity derivatives contracts | (2,523 | ) | | 2,698 |
| | (4,752 | ) | | 7,422 |
|
| Total revenues | 26,725 |
| | 17,422 |
| | 87,755 |
| | 49,940 |
|
| EXPENSES: | | | | | | | |
| Production taxes | 1,539 |
| | 775 |
| | 4,651 |
| | 2,269 |
|
| Lease operating expenses | 3,260 |
| | 1,420 |
| | 9,456 |
| | 6,174 |
|
| Transportation, treating and gathering | 620 |
| | 1,250 |
| | 4,006 |
| | 4,965 |
|
| Depreciation, depletion and amortization | 11,021 |
| | 5,680 |
| | 32,449 |
| | 25,424 |
|
| Impairment of natural gas and oil properties | — |
| | — |
| | — |
| | 150,787 |
|
| Accretion of asset retirement obligation | 110 |
| | 104 |
| | 468 |
| | 388 |
|
| General and administrative expense | 4,997 |
| | 2,948 |
| | 16,961 |
| | 12,211 |
|
| Litigation settlement expense | — |
| | — |
| | 1,000 |
| | 1,250 |
|
| Total expenses | 21,547 |
| | 12,177 |
| | 68,991 |
| | 203,468 |
|
| INCOME (LOSS) FROM OPERATIONS | 5,178 |
| | 5,245 |
| | 18,764 |
| | (153,528 | ) |
| OTHER INCOME (EXPENSE): | | | | | | | |
| (Loss) gain on acquisition of assets at fair value | (16,042 | ) | | — |
| | 27,670 |
| | — |
|
| Interest expense | (5,575 | ) | | (184 | ) | | (13,168 | ) | | (270 | ) |
| Investment income and other | 32 |
| | 3 |
| | 48 |
| | 9 |
|
| Foreign transaction gain (loss) | 1 |
| | — |
| | (14 | ) | | (2 | ) |
| (LOSS) INCOME BEFORE PROVISION FOR INCOME TAXES | (16,406 | ) | | 5,064 |
| | 33,300 |
| | (153,791 | ) |
| Income tax benefit | (16,042 | ) | | — |
| | (16,042 | ) | | — |
|
| NET (LOSS) INCOME | (364 | ) | | 5,064 |
| | 49,342 |
| | (153,791 | ) |
| Dividends on preferred stock attributable to non-controlling interest | (2,980 | ) | | (2,130 | ) | | (9,378 | ) | | (7,077 | ) |
| NET (LOSS) INCOME ATTRIBUTABLE TO GASTAR EXPLORATION, INC. | $ | (3,344 | ) | | $ | 2,934 |
| | $ | 39,964 |
| | $ | (160,868 | ) |
| NET (LOSS) INCOME PER COMMON SHARE ATTRIBUTABLE TO GASTAR EXPLORATION, INC. COMMON STOCKHOLDERS: | | | | | | | |
| Basic | $ | (0.06 | ) | | $ | 0.05 |
| | $ | 0.66 |
| | $ | (2.53 | ) |
| Diluted | $ | (0.06 | ) | | $ | 0.05 |
| | $ | 0.63 |
| | $ | (2.53 | ) |
| WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING: | | | | | | | |
| Basic | 57,433,550 |
| | 63,669,744 |
| | 60,220,115 |
| | 63,538,362 |
|
| Diluted | 57,433,550 |
| | 63,678,597 |
| | 63,618,401 |
| | 63,538,362 |
|
GASTAR EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS |
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| | (in thousands, except share data) |
| ASSETS | | | |
| CURRENT ASSETS: | | | |
| Cash and cash equivalents | $ | 32,393 |
| | 8,901 |
|
| Accounts receivable, net of allowance for doubtful accounts of $507 and $546, respectively | 21,656 |
| | 9,540 |
|
| Commodity derivative contracts | — |
| | 7,799 |
|
| Prepaid expenses | 1,145 |
| | 1,097 |
|
| Total current assets | 55,194 |
| | 27,337 |
|
| | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | | |
| Oil and natural gas properties, full cost method of accounting: | | | |
| Unproved properties, excluded from amortization | 96,220 |
| | 67,892 |
|
| Proved properties | 935,773 |
| | 671,193 |
|
| Total oil and natural gas properties | 1,031,993 |
| | 739,085 |
|
| Furniture and equipment | 2,691 |
| | 1,925 |
|
| Total property, plant and equipment | 1,034,684 |
| | 741,010 |
|
| Accumulated depreciation, depletion and amortization | (517,171 | ) | | (484,759 | ) |
| Total property, plant and equipment, net | 517,513 |
| | 256,251 |
|
| | | | |
| OTHER ASSETS: | | | |
| Commodity derivative contracts | 7,545 |
| | 1,369 |
|
| Deferred charges, net | 2,950 |
| | 836 |
|
| Advances to operators and other assets | 6,733 |
| | 4,275 |
|
| Total other assets | 17,228 |
| | 6,480 |
|
| TOTAL ASSETS | $ | 589,935 |
| | 290,068 |
|
| | | | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| CURRENT LIABILITIES: | | | |
| Accounts payable | $ | 11,046 |
| | $ | 23,863 |
|
| Revenue payable | 12,514 |
| | 8,801 |
|
| Accrued interest | 3,504 |
| | 151 |
|
| Accrued drilling and operating costs | 8,756 |
| | 3,907 |
|
| Advances from non-operators | 9,259 |
| | 17,540 |
|
| Commodity derivative contracts | 3,403 |
| | 1,399 |
|
| Commodity derivative premium payable | 145 |
| | — |
|
| Asset retirement obligation | 633 |
| | 358 |
|
| Other accrued liabilities | 4,844 |
| | 1,493 |
|
| Total current liabilities | 54,104 |
| | 57,512 |
|
| | | | |
| LONG-TERM LIABILITIES: | | | |
| Long-term debt | 312,994 |
| | 98,000 |
|
| Commodity derivative contracts | 378 |
| | 1,304 |
|
| Commodity derivative premium payable | 7,000 |
| | — |
|
| Asset retirement obligation | 5,430 |
| | 6,605 |
|
| Other long-term liabilities | — |
| | 111 |
|
| Total long-term liabilities | 325,802 |
| | 106,020 |
|
| | | | |
| Commitments and contingencies | | | |
| | | | |
| STOCKHOLDERS' EQUITY: | | | |
| Common stock, $0.001 par value; 275,000,000 shares authorized; 61,211,658 and 66,432,609 shares issued and outstanding at December 31, 2013 and 2012, respectively; no par value at December 31, 2012 | 61 |
| | 316,346 |
|
| Additional paid-in capital | 337,969 |
| | 28,336 |
|
| Accumulated deficit | (254,823 | ) | | (294,787 | ) |
| Total stockholders' equity | 83,207 |
| | 49,895 |
|
| Non-controlling interest: |
|
| |
|
|
| Preferred stock of subsidiary, aggregate liquidation preference $152,454 and $98,781 at December 31, 2013 and 2012, respectively | 126,822 |
| | 76,641 |
|
| Total equity | 210,029 |
| | 126,536 |
|
| TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 589,935 |
| | $ | 290,068 |
|
GASTAR EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | |
| | For the Years Ended December 31, |
| | 2013 | | 2012 |
| | (in thousands) |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | |
| Net income (loss) | $ | 49,342 |
| | $ | (153,791 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | |
| Depreciation, depletion and amortization | 32,449 |
| | 25,424 |
|
| Impairment of natural gas and oil properties | — |
| | 150,787 |
|
| Stock-based compensation | 3,435 |
| | 3,295 |
|
| Mark to market of commodity derivatives contracts: | | | |
| Total loss (gain) on commodity derivatives contracts | 4,752 |
| | (7,422 | ) |
| Cash settlements of matured commodity derivatives contracts, net | 5,892 |
| | 16,251 |
|
| Cash premiums paid for commodity derivatives contracts | (152 | ) | | (4,539 | ) |
| Amortization of deferred financing costs | 2,322 |
| | 224 |
|
| Accretion of asset retirement obligation | 468 |
| | 388 |
|
| Settlement of asset retirement obligation | (66 | ) | | (636 | ) |
| Gain on acquisition of assets at fair value | (27,670 | ) | | — |
|
| Deferred tax benefit | (16,042 | ) | | — |
|
| Changes in operating assets and liabilities: | | | |
| Accounts receivable | (8,431 | ) | | 2,487 |
|
| Prepaid expenses | (48 | ) | | 146 |
|
| Accounts payable and accrued liabilities | 1,563 |
| | 4,441 |
|
| Net cash provided by operating activities | 47,814 |
| | 37,055 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | |
| Development and purchase of oil and natural gas properties | (95,343 | ) | | (136,311 | ) |
| Advances to operators | (22,213 | ) | | (9,649 | ) |
| Acquisition of oil and natural gas properties | (251,096 | ) | | — |
|
| Proceeds from sale of oil and natural gas properties | 112,201 |
| | — |
|
| (Use of proceeds) proceeds from non-operators | (8,281 | ) | | (1,983 | ) |
| Purchase of furniture and equipment | (766 | ) | | (296 | ) |
| Net cash used in investing activities | (265,498 | ) | | (148,239 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | |
| Repurchase of common stock | (9,753 | ) | | — |
|
| Proceeds from revolving credit facility | 19,000 |
| | 98,000 |
|
| Repayment of revolving credit facility | (117,000 | ) | | (30,000 | ) |
| Proceeds from issuance of senior secured notes, net of discount | 312,279 |
| | — |
|
| Proceeds from issuance of preferred stock, net of issuance costs | 50,183 |
| | 49,250 |
|
| Dividends on preferred stock attributable to non-controlling interest | (9,378 | ) | | (7,077 | ) |
| Deferred financing charges | (3,785 | ) | | (450 | ) |
| Other | (370 | ) | | (285 | ) |
| Net cash provided by financing activities | 241,176 |
| | 109,438 |
|
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 23,492 |
| | (1,746 | ) |
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 8,901 |
| | 10,647 |
|
| CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 32,393 |
| | $ | 8,901 |
|
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 the directly related GAAP measures.
Reconciliation of Net Income (Loss) to Net Income (Loss) Excluding Special Items:
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended December 31, | | For the Years Ended December 31, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | (in thousands, except share and per share data) |
| | | | | | | | |
| NET (LOSS) INCOME ATTRIBUTABLE TO GASTAR EXPLORATION, INC. AS REPORTED | $ | (3,344 | ) | | $ | 2,934 |
| | $ | 39,964 |
| | $ | (160,868 | ) |
| SPECIAL ITEMS: | | | | | | | |
| Losses related to the change in mark to market value for outstanding commodity derivatives contracts | 2,811 |
| | 1,443 |
| | 9,967 |
| | 5,566 |
|
| Impairment of natural gas and oil properties | — |
| | — |
| | — |
| | 150,787 |
|
| Non-recurring general and administrative costs related to acquisition of assets | 639 |
| | — |
| | 2,349 |
| | — |
|
| Non-recurring general and administrative costs related to Parent migration | 593 |
| | 206 |
| | 1,196 |
| | 834 |
|
| Non-recurring severance costs related to property divestment | — |
| | — |
| | 659 |
| | — |
|
| Non-recurring stock compensation benefit related to property divestment | — |
| | — |
| | (422 | ) | | — |
|
| Litigation settlement expense | — |
| | — |
| | 1,000 |
| | 1,250 |
|
| Loss (gain) on acquisition of assets at fair value | 16,042 |
| | — |
| | (27,670 | ) | | — |
|
| Write off of fees associated with Old Amended Revolving Credit Facility | — |
| | — |
| | 1,154 |
| | — |
|
| Foreign transaction (gain) loss | (1 | ) | | — |
| | 14 |
| | 2 |
|
| Income tax benefit | (16,042 | ) | | — |
| | (16,042 | ) | | — |
|
| | | | | | | | |
| ADJUSTED NET INCOME (LOSS) ATTRIBUTABLE TO GASTAR EXPLORATION, INC. | $ | 698 |
| | $ | 4,583 |
| | $ | 12,169 |
| | $ | (2,429 | ) |
| | | | | | | | |
| ADJUSTED NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO GASTAR EXPLORATION, INC. COMMON STOCKHOLDERS: | | | | | | | |
| Basic | $ | 0.01 |
| | $ | 0.07 |
| | $ | 0.20 |
| | $ | (0.04 | ) |
| Diluted | $ | 0.01 |
| | $ | 0.07 |
| | $ | 0.19 |
| | $ | (0.04 | ) |
| | | | | | | | |
| WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING: | | | | | | | |
| Basic | 57,433,550 |
| | 63,669,744 |
| | 60,220,115 |
| | 63,538,362 |
|
| Diluted | 61,248,076 |
| | 63,678,597 |
| | 63,618,401 |
| | 63,538,362 |
|
| | | | | | | | |
Reconciliation of Net Income (Loss) to Adjusted Earnings Before Interest, Income Taxes, Depreciation, Depletion and Amortization ("Adjusted EBITDA"):
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended December 31, | | For the Years Ended December 31, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | (in thousands, except share and per share data) |
| | | | | | | | |
| NET (LOSS) INCOME ATTRIBUTABLE TO GASTAR EXPLORATION, INC. AS REPORTED | $ | (3,344 | ) | | $ | 2,934 |
| | $ | 39,964 |
| | $ | (160,868 | ) |
| Interest expense | 5,575 |
| | 184 |
| | 13,168 |
| | 270 |
|
| Dividend expense | 2,980 |
| | 2,130 |
| | 9,378 |
| | 7,077 |
|
| Depreciation, depletion and amortization | 11,021 |
| | 5,680 |
| | 32,449 |
| | 25,424 |
|
| Accretion of asset retirement obligation | 110 |
| | 104 |
| | 468 |
| | 388 |
|
| Impairment of natural gas and oil properties | — |
| | — |
| | — |
| | 150,787 |
|
| Loss (gain) on acquisition of assets at fair value | 16,042 |
| | — |
| | (27,670 | ) | | — |
|
| Losses related to the change in mark to market value for outstanding commodity derivatives contracts | 2,811 |
| | 1,443 |
| | 9,967 |
| | 5,566 |
|
| Non-cash stock compensation expense | 895 |
| | 720 |
| | 3,435 |
| | 3,295 |
|
| Litigation settlement expense | — |
| | — |
| | 1,000 |
| | 1,250 |
|
| Foreign transaction (gain) loss | (1 | ) | | — |
| | 14 |
| | 2 |
|
| Interest income and other | (32 | ) | | (3 | ) | | (48 | ) | | (9 | ) |
| Non-recurring general and administrative costs related to acquisition of assets | 639 |
| | — |
| | 2,349 |
| | — |
|
| Non-recurring general and administrative costs related to Parent migration | 593 |
| | 206 |
| | 1,196 |
| | 834 |
|
| Non-recurring severance costs related to property divestment | — |
| | — |
| | 659 |
| | — |
|
| Income tax benefit | (16,042 | ) | | — |
| | (16,042 | ) | | — |
|
| Adjusted EBITDA | $ | 21,247 |
| | $ | 13,398 |
| | $ | 70,287 |
| | $ | 34,016 |
|
| | | | | | | | |
# # #
