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GeoMet, Inc. is an independent energy company primarily engaged in the exploration for and the development and production of natural gas from coal seams (coalbed methane or CBM) and non-conventional shallow gas. Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the Central Appalachian Basin in West Virginia. We also control additional coalbed methane and oil and gas development rights, principally in Alabama, British Columbia, Virginia and West Virginia.
We pursue those projects with large, high impact resource potential that leverage our substantial CBM expertise. We have a history of developing large scale projects with low finding and development costs and low project life operating costs. Our Technical staff has developed 5 large scale CBM projects in four separate basins in the United States (Black Warrior, Raton, Central Appalachia, and Cahaba basins.
Who We Are
GeoMet, Inc. was founded in 1985 as a consulting company to the coalbed methane (CBM) industry. Since 1993 we have been active as a developer and operator of coalbed methane properties. We, or our principals, have been responsible for the development of five successful large scale coalbed methane projects in four separate basins in the United States. Our CBM management, professional, and project management team has an average of more than 19 years of CBM experience and has participated in the drilling and operation of more than 2,700 CBM wells worldwide since 1977.
Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the central Appalachian Basin in West Virginia and Virginia. At December 31, 2010, we controlled a total of approximately 160,000 net acres of coalbed methane and oil and natural gas development rights, primarily in Alabama, West Virginia, Virginia, Louisiana, Colorado, and British Columbia. Our major holdings consist of approximately 39,000 net acres in the Gurnee field in the Cahaba Basin in Alabama, approximately 50,000 net acres in the Garden City prospect in Alabama, approximately 30,000 net acres in the Pond Creek field in the central Appalachian Basin, approximately 8,000 net acres in the Lasher field in the central Appalachian Basin, and approximately 25,000 net acres in the Peace River field in British Columbia.
Our proved reserves as of December 31, 2010, as estimated by DeGolyer and MacNaughton, an independent reservoir engineering firm, were approximately 215.9 Bcf. The 2010 proved reserves were 100% coalbed methane and 76% were developed. Approximately 36% of year-end 2010 proved reserves are in the Gurnee field in Alabama and 61% in the Pond Creek and Lasher fields in West Virginia and Virginia.
Competitive Strengths
We primarily explore for, develop and produce CBM and non-conventional shallow gas.. We believe that substantial expertise and experience is required to develop, produce, and operate coalbed methane and non-conventional shallow gas fields in an efficient manner. We believe that the inherent geologic and production characteristics of coalbed methane and non-conventional shallow gas offer significant operational advantages compared to conventional gas production, including:
Our Strategy
Our objective is to create the premier non-conventional shallow gas company in North America (emphasizing coalbed methane) while maximizing stockholder value through the efficient investment of capital to increase reserves, production, cash flow and earnings. We intend to focus on the following strategies:
Our History
GeoMet was founded as a consulting firm in 1985 by three geologists with backgrounds in the coal mining and related coal degasification industry. The GeoMet staff has been directly involved with coalbed methane since 1977, working for USX Corporation in developing the first large-scale degasification field in the United States at the Oak Grove Mine in Alabama. This project became the model for subsequent coalbed methane projects in the Black Warrior basin. Our staff has been involved in the development of over thirty percent of the coalbed methane wells currently producing in the Black Warrior basin.
During our early years, our staff consulted extensively with the Gas Research Institute (GRI) in the research and development of new technology for the industry with many of the companies involved in the early development of coalbed methane, including Taurus (now Energen), Amoco, Chevron and River Gas Corporation. In addition to work done in the United States, our staff has evaluated or consulted on coalbed methane projects in Australia, Bangladesh, Canada, China, Colombia, Czechoslovakia, Hungary, Israel, Poland, South Africa, Switzerland, the United Kingdom, Venezuela and Zimbabwe.
In 1986, the GeoMet founders acquired an equity interest in the River Gas Corporation and provided the technical expertise in connection with the development of the Blue Creek field in the Black Warrior Basin of Alabama. Dominion Energy acquired the Blue Creek field from River Gas in 1992.
GeoMet's focus changed in 1993 as it ceased to provide consulting services and began to utilize its expertise and accumulated years of experience to participate for its own account in the initiation and development of coalbed methane projects. Due to capital constraints, this participation usually was in the form of relatively small "earned interests." The White Oak Creek field in the Black Warrior Basin and the Apache Canyon field in the Raton Basin were developed in this manner.
In December 2000 GeoMet's principals sold 80% of the equity of the Company to an entity formed by J. Darby Seré, William C. Rankin, and Yorktown Energy Partners IV, L.P. which committed additional equity to fund future coalbed methane development and Messrs. In July, 2006, we completed our initial public offering and became listed on the NASDAQ Global Exchange under the ticker symbol GMET.
Coalbed Methane Background
CBM development has its roots in the coal mining industry. Underground coal mines have long been recognized as hazardous environments. Methane gas can displace oxygen within coal mining tunnels and lead to suffocation or explosion. Initial attempts to extract CBM from coal mines were an effort to improve mine safety, but evolved into a commercial enterprise. CMB has been produced in commercial quantities since 1981. CBM is recognized, both domestically and internationally, as a significant source of gas reserves.
Characteristics of Coalbed Methane
The source rock in conventional natural gas is usually different from the reservoir rock, while in coalbed methane the coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional natural gas, but in coalbed methane, most and frequently all, of the gas is stored by adsorption. Adsorption allows large quantities of gas to be stored at relatively low pressures. A unique characteristic of coalbed methane is that the gas flow can be increased by reducing the reservoir pressure. Frequently the coalbed pore space, which is in the form of cleats or fractures, is filled with water. The reservoir pressure is reduced by pumping out the water, releasing the methane from the molecular structure, which allows the methane to flow through the cleat structure to the well bore. While a conventional natural gas well typically decreases in flow as the reservoir pressure is drawn down, a coalbed methane well will typically increase in production for up to five years from initial production depending on well spacing.
Coalbed methane and conventional natural gas both have methane as their major component. While conventional natural gas often has more complex hydrocarbon gases, coalbed methane rarely has more than 2% of the more complex hydrocarbons. In the eastern coal fields of the United States, coalbed methane is generally 98 to 99% pure methane and requires only dehydration of the gas to remove moisture to achieve pipeline quality. In the western coal fields of the United States, it is also sometimes necessary to strip out either carbon dioxide or nitrogen. Once coalbed methane has been produced, it is gathered, transported, marketed, and priced in the same manner as conventional natural gas.
The content of gas within a coal seam is measured through gas desorption testing. The ability to flow gas and water to the well bore in a coalbed methane well is determined by the fracture or cleat network in the coal. While at shallow depths of less than 500 feet these fractures are sometimes open enough to produce the fluids naturally, at greater depths the networks are progressively squeezed shut, reducing the ability to flow. It is necessary to provide other avenues of flow such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened in the coal and a slurry of fluid and sand propant is pumped into the fractures so that the fractures remain open after the release of pressure, thereby enhancing the flow of both water and gas to allow the economic production of gas.
Gurnee Field, Cahaba Basin
We have the development rights to approximately 39,000 net CBM acres throughout the Gurnee field in the Cahaba Basin of central Alabama. At December 31, 2010, approximately 36% of our estimated proved reserves, or 77.5 Bcf, were located in the Gurnee field, of which approximately 82% were classified as proved developed. At such time, we had developed approximately 44% of our net Gurnee field CBM acreage. We are the operator and own a 100% working interest in the area. As of December 31, 2010, we had 246 productive wells in the Gurnee field. Net daily sales of gas averaged approximately 5,090 Mcf for 2010.
We extract gas from six coal groups within the Pottsville coal formation at depths ranging from 700 feet to 3,400 feet. At these depths, overall seam thickness in this area averages approximately 50 feet of high volatile bituminous rank coal. A total of 33 core holes have been drilled and over 600 gas desorption tests have been conducted on our acreage to determine the gas content of the coal and to define the coalbed methane resource under a substantial portion of the acreage in our leasehold position.
Our acreage is roughly evenly divided between a northern block, largely on the east side of the Cahaba River, and a southern block, largely on the west side of the river. The geology is generally more complex on the east side of the river with beds dipping from northwest to southeast. The geological setting west of the river tends to be less complex with more gently dipping beds. Most of the development to date in the Gurnee field has been on the east side of the river which is near existing infrastructure. We have recently begun drilling on the less geologically complex west side of the river in the southern acreage block. Initial results are encouraging with early initial gas production inclines and average gas production rates higher than elsewhere in the field. However, it is too early to reach any definitive conclusions. Future production growth in the field could come from several sources, including; new drilling, especially from the west side of the river if initial positive results continue; the dewatering of the high water production wells; and from increased gas production from existing wells, either as a natural occurrence or from improved treatment or re-completion techniques.
We have constructed and operate an approximate 38.5-mile pipeline from the Cahaba Basin to the Black Warrior River for the disposal of produced water under a permit issued by the Alabama Department of Environmental Management. This pipeline has a maximum design capacity of approximately 45,000 barrels of water per day, but would require additional pump stations and looping a portion of the line in order to reach the maximum design capacity, if needed. We also operate a water treatment facility in the Gurnee field to condition the produced water prior to injection into the pipeline and a discharge pond at the river to aerate the water prior to disposal. We believe that our disposal pipeline and water treatment facility will meet all of our future water disposal requirements for the Gurnee field.
Pond Creek Field, Appalachian Basin
In the Pond Creek field in the central Appalachian Basin of southern West Virginia and southwestern Virginia, we have the rights to develop approximately 30,000 net CBM acres. At December 31, 2010, approximately 61% of our estimated proved reserves, or 131.5 Bcf, were located within the Pond Creek field, of which approximately 73% were classified as proved developed. At such time, we had developed approximately 56% of our net Pond Creek CBM acreage.
As of December 31, 2010, we are the operator and own a working interest in 262 net productive wells in the Pond Creek field. Net daily sales of gas averaged approximately 14,580 Mcf for 2010.
We extract gas from up to an average of 12 coal seams within the Pocahontas and New River coal formations at depths ranging from 430 feet to 2,400 feet. At these depths overall coal thickness in this area ranges from 10 to 30 feet of low-medium volatile bituminous rank Pennsylvanian Age coal. Prior mining activity revealed that these coal groups are gas rich. A total of 42 core holes have been drilled on and in the area of our acreage in the central Appalachian Basin and a geographically extensive gas desorption testing program has been conducted to determine the gas content of the coal and to define the coalbed methane resource under a substantial portion of our leasehold position.
CBM wells in the Pond Creek field produce comparatively lower levels of water. Produced water is either used in our operations or injected into a disposal well that we own and operate.
Lasher Project, Appalachian Basin
In the Lasher field in the central Appalachian Basin of southern West Virginia, we have the rights to develop approximately 8,000 net CBM acres. At December 31, 2010, approximately 3% of our estimated proved reserves, or 6.8 Bcf, were located within the Lasher field, of which approximately 57% were classified as proved developed. We are the operator and own a 100% working interest in the area. As of December 31, 2010, we had drilled 18 production wells. The proximity of the Lasher field to the Pond Creek field in southwestern West Virginia presents several advantages which helps reduce cost and provides operational efficiencies.
| | Stock Information
Popupmsg The stock information provided is for informational purposes only and is not intended for trading purposes. The stock information is provided by eSignal, stock charts are provided by EDGAR Online, both third party services, and GeoMet, Inc. does not maintain or provide information directly to this service. Stock information is delayed approximately 20 minutes. Week of October 31, 2011
Year End Stock Prices The historical stock information provided is for informational purposes only and is not intended for trading purposes. The historical stock information is provided by Mergent, a third party service, and GeoMet, Inc. does not maintain or provide information directly to this | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Market Value1 | $516,284 | a/o May 09, 2014 |
| Shares Outstanding | 40,652,317 | a/o Mar 01, 2014 |
| Float | Not Available | |
| Authorized Shares | Not Available | |
| Par Value | 0.001 |
Wells Fargo acted as financial advisor, and Paul Hastings LLP acted as legal advisor on the transaction.
Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production master limited partnership which owns an interest in over 13,000 producing natural gas and oil wells, located primarily in Appalachia, the Barnett Shale (TX), the Mississippi Lime (OK), the Raton Basin (NM) and Black Warrior Basin (AL). ARP is also the largest sponsor of natural gas and oil investment partnerships in the U.S. For more information, please visit our website at www.atlasresourcepartners.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.
Atlas Energy, L.P. (NYSE: ATLS) is a master limited partnership which owns all of the general partner Class A units and incentive distribution rights and an approximate 34% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through all of the general partner interest, all the incentive distribution rights and an approximate 6% limited partner interest. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.
Cautionary Note Regarding Forward-Looking Statements
This document contains forward-looking statements that involve a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those contained in the forward-looking statements. ARP cautions readers that any forward-looking information is not a guarantee of future performance. Such forward-looking statements include, but are not limited to, statements about future financial and operating results, resource potential, ARP's plans, objectives, expectations and intentions and other statements that are not historical facts. Risks, assumptions and uncertainties that could cause actual results to materially differ from the forward-looking statements include, but are not limited to, those associated with general economic and business conditions; ARP's ability to close its pending acquisitions; changes in commodity prices; changes in the costs and results of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain capital needed for operations; ARP's level of indebtedness; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; tax consequences of business transactions; and other risks, assumptions and uncertainties detailed from time to time in ARP's reports filed with the U.S. Securities and Exchange Commission, including quarterly reports on Form 10-Q, reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and ARP assumes no obligation to update such statements, except as may be required by applicable law.
SOURCE Atlas Resource Partners, L.P.
(3.636%)
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KEYWORD: Pennsylvania West Virginia Virginia INDUSTRY KEYWORD: OIL UTI GAS SUBJECT CODE: TNM -- The acquisition provides stable, high margin cash flow, low-decline production, as well as potential valuable development opportunities in the position
-- The transaction will be immediately accretive on a fully financed basis to distributable cash flow per unit
-- The acquisition of GeoMet natural gas properties in West Virginia was recently approved by GeoMet shareholders
-- ARP's development activities in the liquids rich Mississippi Lime and Marble Falls plays continue to yield significant levels of oil and liquids production
-- Adjusted earnings before interest, income taxes, depreciation and amortization ("Adjusted EBITDA"), a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, increased to $64.5 million(1) for the first quarter 2014
-- First quarter 2014 financial and operational results to be discussed on a conference call at 9AM ET on Thursday, May 8th
Atlas Resource Partners, L.P. (NYSE: ARP) ("ARP" or "the Company") has reported operating and financial results for the first quarter 2014.
Matthew A. Jones, President of ARP, said, "This quarter highlights the diligence and expertise of our company's operating teams as we were able to withstand one of the most challenging winter seasons on record and move forward with our development activities particularly in our liquids rich development areas. As a result, our company's net oil production has increased by approximately 15 percent in the first five weeks of the second quarter, our current quarter, compared to the first quarter average, and we anticipate further growth. Entirely through the organic development of our liquids rich assets, we've grown our net oil production by more than 60 percent since the first quarter of 2013. Lastly, our recently announced acquisition of oil properties in Colorado is a tremendous addition to our existing asset portfolio, providing to us stable cash flow and high production margins, and we look forward to additional opportunities to expand our business."
-- First quarter 2014 Adjusted EBITDA, a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, was $64.5 million(1), compared to $62.6 million for the fourth quarter 2013, and $31.4 million for the prior year comparable quarter. Results during the quarter were adversely impacted by approximately $3.5 million due to constrained production volumes caused by severe winter weather conditions.
-- Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner, a non-GAAP measure, was $42.3 million(1), or $0.53 per common unit, for the first quarter 2014, compared to $41.0 million for the fourth quarter 2013 and $25.1 million for the prior year comparable quarter. Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner was unfavorably impacted during the quarter by approximately $3.5 million, or $0.05 per unit, due to weather-related issues mentioned above. ARP's first quarter 2014 cash distribution coverage would have been approximately 1.0x inclusive of the weather impact.
-- ARP paid monthly cash distributions totaling $0.58 per limited partner unit for the first quarter 2014, an approximate 14% increase over the prior year first quarter distribution. The most recent ARP distribution for the month of March 2014 will be paid on May 15, 2014 to holders of record as of May 7, 2014.
-- On a GAAP basis, net loss was $10.8 million for the first quarter 2014 compared to a net loss of $5.4 million for the prior year comparable period. The loss for each period was caused principally by non-cash expenses, specifically depreciation, depletion and amortization in the current period from the larger amount of producing oil & gas assets compared to the prior year period.
(1) A reconciliation of GAAP net loss to Adjusted EBITDA and Distributable Cash Flow is provided in the financial tables of this release. Please see footnote 7 to the Financial Information table of this release.
Rangely Field Acquisition of Oil Properties in Colorado
On May 7, 2014, ARP announced that it entered into a definitive agreement to acquire total reserves of approximately 47 million barrels of oil equivalent ("Mmboe") of oil and natural gas liquids ("NGLs"), including proved developed producing reserves of approximately 25 Mmboe, for $420 million. The acquired position is located in the Rangely field in northwest Colorado, a mature tertiary CO2 flood with low-decline oil production. The transaction is subject to customary purchase price adjustments and is expected to close in the second quarter 2014, with an effective date of April 1, 2014. The assets generated net production of approximately 2,900 million barrels of oil equivalents ("Mmboed") in the first quarter 2014.
The acquired assets are expected to provide ARP with a stable, high margin cash flow stream with a low-decline profile (average 3-4% annual decline rate over the past 15 years). The asset position is a tertiary oil recovery project using CO2 flood activity, and the production mix is predominantly oil at 90%, with the remainder coming from NGLs. ARP will have an approximate 25% non-operating net working interest in the assets, and Chevron Corporation will continue as operator. Material capital expenditures and growth projects are subject to ARP's approval.
Approval of GeoMet Transaction
On February 14, 2014, ARP announced that it entered into a definitive agreement to acquire approximately 70 Bcfe of natural gas proved reserves in West Virginia and Virginia from GeoMet, Inc. (OTCQB: GMET) and certain of its subsidiaries (collectively, "GeoMet") for $107 million, subject to customary adjustments, with an effective date of January 1, 2014. On May 5, 2014, the transaction was approved by a majority vote of GeoMet's shareholders, and the transaction is expected to close in May 2014.
ARP expects to benefit from the mature, low-decline production from the acquired assets, which will complement the company's existing oil and gas base. The assets consist of approximately 70 Bcfe of proved reserves in West Virginia and Virginia, and are 100% natural gas and proved developed.
E&P Operating Highlights
-- Average net daily production for the first quarter 2014 was 246.6 Mmcfed, an increase of approximately 85% from the prior year comparable quarter and a decrease of approximately 5% from the fourth quarter 2013. The sequential decrease in production was due to the adverse impact from winter weather during the first quarter 2014. During much of the period, the weather impact affected the ability to service producing wells, namely in the Mid-Continent region, and also delayed the connection of newly completed wells into sales lines. As a result, oil and gas production from certain areas was restricted for periods of time, which directly affected realized production margin for the first quarter 2014. ARP has estimated the impact was approximately $3.5 million to Adjusted EBITDA from weather-related issues in the quarter. The increase in net production from the first quarter 2013 was due primarily to the acquisition of producing assets from EP Energy in July 2013, located in the Raton Basin (New Mexico), Black Warrior Basin (Alabama) and County Line region (Wyoming).
-- ARP's realized price for natural gas across all of its regions, excluding the effect of financial hedges, was $4.68 per per thousand cubic feet ("mcf") in the first quarter 2014, compared to $3.35 per mcf in the fourth quarter 2013, a sequential increase of approximately 40%. Net realized natural gas prices including the effect of hedge positions was $4.07 per mcf for the current period, an increase of $0.44, or 12%, from the fourth quarter 2013.
Hedge Positions
-- ARP continued to expand its commodity hedge positions on its existing production during the first quarter 2014. A summary of ARP's derivative positions as of May 7, 2014 is provided in the financial tables of this release.
Corporate Expenses & Capital Position
-- Cash general and administrative expense was $11.7 million for the first quarter 2014, $3.9 million higher than the fourth quarter 2013 and $2.1 million higher compared with the prior year first quarter. The increase compared with the fourth quarter 2013 was due primarily to certain administrative and marketing costs associated with ARP's 2013 partnership program that were able to capitalized in the prior quarter. ARP capitalizes certain amounts of its general and administrative costs associated with the partnership programs as a component of its capital contributions to the partnership programs. The increase in expense compared with the prior year first quarter was principally due to larger operations stemming from ARP's expanded asset position.
-- Cash interest expense was $11.4 million for the first quarter 2014, consistent with the fourth quarter 2013 and $9.1 million higher than the prior year first quarter. The increase compared with the prior year quarter was primarily due to higher levels of borrowing used to expand ARP's operations over the last year.
-- As of March 31, 2014, ARP had $889 million of total debt, including $366 million outstanding under its revolving credit facility. ARP had approximately $365 million available on its revolving credit facility as of the end of the first quarter 2014.
Interested parties are invited to access the live webcast of an investor call with management regarding Atlas Resource Partners, L.P.'s first quarter 2014 results on Thursday, May 8, 2014 at 9:00 am ET by going to the Investor Relations section of Atlas Resource's website at www.atlasresourcepartners.com. For those unavailable to listen to the live broadcast, the replay of the webcast will be available following the live call on the Atlas Resource website and telephonically beginning at 1:00 p.m. ET on May 8, 2014 by dialing 855-859-2056, passcode: 30755727.
Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production master limited partnership which owns an interest in over 13,000 producing natural gas and oil wells, located primarily in Appalachia, the Barnett Shale (TX), the Mississippi Lime (OK), the Raton Basin (NM) and Black Warrior Basin (AL). ARP is also the largest sponsor of natural gas and oil investment partnerships in the U.S. For more information, please visit our website at www.atlasresourcepartners.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.
Atlas Energy, L.P. (NYSE: ATLS) is a master limited partnership which owns all of the general partner Class A units and incentive distribution rights and an approximate 34% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through all of the general partner interest, all the incentive distribution rights and an approximate 6% limited partner interest. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.
Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In Oklahoma, southern Kansas, Texas, and Tennessee, APL owns and operates 15 active gas processing plants, 18 gas treating facilities, as well as approximately 11,200 miles of active intrastate gas gathering pipeline. For more information, visit the Partnership's website at www.atlaspipeline.com or contact IR@atlaspipeline.com.
Cautionary Note Regarding Forward-Looking Statements
This press release contains forward-looking statements that involve a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those contained in the forward-looking statements. ARP cautions readers that any forward-looking information is not a guarantee of future performance. Such forward-looking statements include, but are not limited to, statements about future financial and operating results, resource and production potential, ARP's plans, objectives, expectations and intentions and other statements that are not historical facts. Risks, assumptions and uncertainties that could cause actual results to materially differ from the forward-looking statements include, but are not limited to, those associated with general economic and business conditions; ARP's ability to close the GeoMet acquisition, on the terms described or at all; ARP's ability to obtain required consents in order to permit the transfer of the assets included in the GeoMet acquisition; ARP's ability to obtain the required financing for the GeoMet acquisition, on desirable terms or at all; ARP's ability to realize the anticipated benefits of the GeoMet transaction; changes in commodity prices and hedge positions; changes in the estimates of maintenance capital expense; changes in the costs and results of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain capital needed for operations; ARP's level of indebtedness; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; tax consequences of business transactions; and other risks, assumptions and uncertainties detailed from time to time in ARP's reports filed with the U.S. Securities and Exchange Commission, including quarterly reports on Form 10-Q, reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and ARP assumes no obligation to update such statements, except as may be required by applicable law.
GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
|
| December 31, |
| ||||
|
|
| 2013 |
| 2012 |
| ||
| ASSETS |
|
|
|
|
| ||
| Current Assets: |
|
|
|
|
| ||
| Cash and cash equivalents |
| $ | 8,108,272 |
| $ | 7,234,225 |
|
| Accounts receivable, net of allowance of $14,744 and $17,634 at December 31, 2013 and 2012, respectively |
| 2,900,807 |
| 6,248,819 |
| ||
| Inventory |
| — |
| 262,885 |
| ||
| Derivative asset—natural gas contracts |
| — |
| 3,929,767 |
| ||
| Other current assets |
| 692,740 |
| 1,437,819 |
| ||
| Total current assets |
| 11,701,819 |
| 19,113,515 |
| ||
| Natural gas properties—utilizing the full cost method of accounting: |
|
|
|
|
| ||
| Proved natural gas properties |
| 333,109,974 |
| 539,077,119 |
| ||
| Other property and equipment |
| 3,158,701 |
| 3,749,621 |
| ||
| Total property and equipment |
| 336,268,675 |
| 542,826,740 |
| ||
| Less accumulated depreciation, depletion, amortization and impairment of gas properties |
| (293,939,624 | ) | (467,702,053 | ) | ||
| Property and equipment—net |
| 42,329,051 |
| 75,124,687 |
| ||
| Other noncurrent assets: |
|
|
|
|
| ||
| Deferred income taxes |
| — |
| 1,125,804 |
| ||
| Other |
| 769,384 |
| 962,451 |
| ||
| Total other noncurrent assets |
| 769,384 |
| 2,088,255 |
| ||
| TOTAL ASSETS |
| $ | 54,800,254 |
| $ | 96,326,457 |
|
| LIABILITIES, MEZZANINE AND STOCKHOLDERS’ DEFICIT |
|
|
|
|
| ||
| Current Liabilities: |
|
|
|
|
| ||
| Accounts payable |
| $ | 3,541,770 |
| $ | 5,728,879 |
|
| Royalties payable |
| 3,656,272 |
| 3,830,904 |
| ||
| Accrued liabilities |
| 1,073,653 |
| 1,793,946 |
| ||
| Deferred income taxes |
| — |
| 1,125,804 |
| ||
| Derivative liability—natural gas contracts |
| 834,151 |
| 919,572 |
| ||
| Asset retirement obligations |
| 265,470 |
| 73,706 |
| ||
| Current portion of long-term debt |
| 71,550,000 |
| 10,300,000 |
| ||
| Total current liabilities |
| 80,921,316 |
| 23,772,811 |
| ||
| Long-term debt |
| — |
| 129,000,000 |
| ||
| Asset retirement obligations |
| 8,915,407 |
| 13,235,318 |
| ||
| Derivative liability—natural gas contracts |
| 709,571 |
| 1,636,348 |
| ||
| Other long-term accrued liabilities |
| 113,434 |
| 143,682 |
| ||
| TOTAL LIABILITIES |
| 90,659,728 |
| 167,788,159 |
| ||
| Commitments and contingencies (Notes 10 and 19) |
|
|
|
|
| ||
| Mezzanine equity: |
|
|
|
|
| ||
| Series A Convertible Redeemable Preferred Stock—net of offering costs of $1,660,435; redemption amount $60,005,710; $.001 par value; 7,401,832 shares authorized, 6,000,571 and 5,305,865 shares were issued and outstanding at December 31, 2013 and 2012, respectively |
| 43,404,993 |
| 35,851,887 |
| ||
| Stockholders’ (Deficit) Equity: |
|
|
|
|
| ||
| Preferred stock, $0.001 par value—2,598,168 shares authorized, none issued |
| — |
| — |
| ||
| Common stock, $0.001 par value—authorized 125,000,000 shares; 40,662,749 and 40,690,077 issued and 40,652,317 and 40,679,645 outstanding at December 31, 2013 and 2012, respectively |
| 40,663 |
| 40,690 |
| ||
| Treasury stock, at cost—10,432 shares at December 31, 2013 and 2012 |
| (94,424 | ) | (94,424 | ) | ||
| Paid-in capital |
| 187,527,716 |
| 195,033,585 |
| ||
| Accumulated other comprehensive loss |
| — |
| (53,020 | ) | ||
| Retained deficit |
| (266,738,422 | ) | (302,057,496 | ) | ||
| Less notes receivable |
| — |
| (182,924 | ) | ||
| Total stockholders’ deficit |
| (79,264,467 | ) | (107,313,589 | ) | ||
| TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ DEFICIT |
| $ | 54,800,254 |
| $ | 96,326,457 |
|
See accompanying Notes to Audited Consolidated Financial Statements.
GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31,
|
|
| 2013 |
| 2012 |
| ||
| Revenues: |
|
|
|
|
| ||
| Gas sales |
| $ | 38,086,539 |
| $ | 39,146,723 |
|
| Other |
| 122,844 |
| 236,364 |
| ||
| Total revenues |
| 38,209,383 |
| 39,383,087 |
| ||
| Expenses: |
|
|
|
|
| ||
| Lease operating expense |
| 13,131,855 |
| 17,482,709 |
| ||
| Compression and transportation expense |
| 7,716,864 |
| 8,349,799 |
| ||
| Production taxes |
| 2,096,598 |
| 1,961,804 |
| ||
| Depreciation, depletion and amortization |
| 4,594,093 |
| 11,531,565 |
| ||
| Impairment of intangible asset |
| — |
| 782,462 |
| ||
| Impairment of natural gas properties |
| — |
| 95,728,981 |
| ||
| General and administrative |
| 5,009,645 |
| 4,851,193 |
| ||
| Restructuring costs |
| 95,584 |
| 1,083,018 |
| ||
| Gains (losses) on natural gas derivatives |
| 1,811,191 |
| (4,415,617 | ) | ||
| Total operating expenses |
| 34,455,830 |
| 137,355,914 |
| ||
| Gain on the sale of properties in Alabama |
| 36,948,313 |
| — |
| ||
| Operating income (loss) |
| 40,701,866 |
| (97,972,827 | ) | ||
| Other income (expense): |
|
|
|
|
| ||
| Interest income |
| 1,714 |
| 5,527 |
| ||
| Interest expense |
| (5,132,424 | ) | (5,827,659 | ) | ||
| Write off of debt issuance costs |
| — |
| (1,377,520 | ) | ||
| Other |
| (227,082 | ) | (1,463 | ) | ||
| Total other income (expense) |
| (5,357,792 | ) | (7,201,115 | ) | ||
| Income (loss) before income taxes from continuing operations |
| 35,344,074 |
| (105,173,942 | ) | ||
| Income tax expense |
| 25,000 |
| 44,043,200 |
| ||
| Income (loss) from continuing operations |
| 35,319,074 |
| (149,217,142 | ) | ||
| Discontinued operations |
| — |
| (736,025 | ) | ||
| Net income (loss) |
| $ | 35,319,074 |
| $ | (149,953,167 | ) |
| Accretion of discount on Series A Convertible Redeemable Preferred Stock |
| (2,257,968 | ) | (1,913,134 | ) | ||
| Paid-in-kind dividends on Series A Convertible Redeemable Preferred Stock |
| (5,295,138 | ) | (3,934,094 | ) | ||
| Cash dividends paid on Series A Convertible Redeemable Preferred Stock |
| (2,572 | ) | (2,757 | ) | ||
| Net income (loss) available to Common Stockholders |
| $ | 27,763,396 |
| $ | (155,803,152 | ) |
| Net income (loss) per common share—basic: |
|
|
|
|
| ||
| Net income (loss) per common share from continuing operations |
| $ | 0.69 |
| $ | (3.86 | ) |
| Net loss per common share from discontinued operations |
| $ | — |
| $ | (0.02 | ) |
| Net income (loss) per common share—basic |
| $ | 0.69 |
| $ | (3.88 | ) |
| Net income (loss) per common share—diluted: |
|
|
|
|
| ||
| Net income (loss) per common share from continuing operations |
| $ | 0.42 |
| $ | (3.86 | ) |
| Net loss per common share from discontinued operations |
| $ | — |
| $ | (0.02 | ) |
| Net income (loss) per common share—diluted |
| $ | 0.42 |
| $ | (3.88 | ) |
| Weighted average number of common shares: |
|
|
|
|
| ||
| Basic |
| 40,481,330 |
| 40,123,608 |
| ||
| Diluted |
| 83,384,951 |
| 40,123,608 |
| ||
See accompanying Notes to Audited Consolidated Financial Statements
