As filed with the Securities and Exchange Commission on June 21, 2006
Registration No. 333-134070
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 1
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
GeoMet, Inc.
(Exact name of registrant as specified in its charter)
Delaware | 1311 | 76-0662382 | ||
(State or other jurisdiction of incorporation or organization) |
(Primary Standard Industrial Classification Code Number) |
(I.R.S. Employer Identification Number) |
909 Fannin, Suite 3208
Houston, TX 77010
(713) 659-3855
(Address, including zip code, and telephone number, including area code, of registrants principal executive offices)
J. Darby Seré
Chairman, President and Chief Executive Officer
GeoMet Inc.
909 Fannin, Suite 3208
Houston, TX 77010
(713) 659-3855
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
Dallas Parker William T. Heller IV Thompson & Knight LLP 333 Clay Street, Suite 3300 Houston, TX 77002 (713) 654-8111 |
T. Mark Kelly Alan P. Baden Vinson & Elkins LLP 1001 Fannin Street, Suite 3300 Houston, TX 77002 (713) 758-2222 |
Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement is declared effective.
If any securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the Securities Act), check the following box. ¨
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
The information in the prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.
Subject to Completion, Dated June 21, 2006
Prospectus
8,200,000 Shares
Common Stock
GeoMet, Inc. and the selling stockholders are offering 5,066,408 shares and 3,133,592 shares, respectively, of common stock. This is our initial public offering, and no public market currently exists for our shares. We anticipate that the initial public offering price will be between $ and $ per share. After the offering, the market price for our shares may be outside this range.
We have applied to have our common stock quoted on the Nasdaq National Market under the symbol GMET.
Investing in our common stock involves a high degree of risk. See Risk Factors beginning on page 10.
Per Share | Total | |||||
Offering price |
$ | $ | ||||
Discounts and commissions to underwriters |
$ | $ | ||||
Offering proceeds to GeoMet, Inc., before expenses |
$ | $ | ||||
Offering proceeds to the selling stockholders |
$ | $ |
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus is accurate or complete. Any representation to the contrary is a criminal offense.
We have granted the underwriters the right to purchase up to 1,230,000 additional shares of common stock on the same terms and conditions as set forth above if the underwriters sell more than 8,200,000 shares of common stock in this offering. The underwriters can exercise this right at any time and from time to time, in whole or in part, within 30 days after the offering. The underwriters expect to deliver the shares of common stock to investors on or about , 2006.
Banc of America Securities LLC |
A.G. Edwards |
Raymond James |
, 2006
Page | ||
1 | ||
10 | ||
21 | ||
22 | ||
22 | ||
23 | ||
24 | ||
Selected Historical Consolidated Financial and Operating Data |
25 | |
Managements Discussion and Analysis of Results of Operations and Financial Condition |
28 | |
48 | ||
59 | ||
Security Ownership of Certain Beneficial Owners and Management |
70 | |
72 | ||
73 | ||
74 | ||
77 | ||
Material United States Federal Income Tax Considerations for Non-United States Holders |
79 | |
83 | ||
89 | ||
89 | ||
89 | ||
90 | ||
F-1 | ||
A-1 |
i
This summary highlights selected information from this prospectus but does not contain all information that you should consider before investing in our common stock. You should read this entire prospectus carefully, including Risk Factors beginning on page 10, and the financial statements included elsewhere in this prospectus. In this prospectus, we refer to GeoMet, Inc., its subsidiaries and predecessors as GeoMet, we, our, or our company. References to the number of shares of our common stock outstanding have been revised to reflect a four-for-one stock split effected in January 2006. Unless otherwise indicated, share numbers in the prospectus assume that the underwriters do not exercise their option to purchase additional shares of common stock. The estimates of our proved reserves as of December 31, 2005, 2004 and 2003 included in this prospectus are based on reserve reports prepared by DeGolyer and MacNaughton, independent petroleum engineers. A summary of their report with respect to our estimated proved reserves as of December 31, 2005 is attached to this prospectus as Appendix A. We discuss sales volumes, per Mcf revenue, per Mcf cost and other data in this prospectus net of any royalty owners interest. We have provided definitions for some of the industry terms used in this prospectus in the Glossary of Natural Gas and Coalbed Methane Terms.
About GeoMet
We are engaged in the exploration, development, and production of natural gas from coal seams (coalbed methane or CBM). Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the Appalachian Basin in West Virginia and Virginia. We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator and developer of coalbed methane properties since 1993. At December 31, 2005, we controlled a total of approximately 255,000 net acres of coalbed methane development rights, primarily in Alabama, West Virginia, Virginia, Louisiana, Colorado, and British Columbia. We are developing a total of approximately 77,000 net acres of coalbed methane development rights in the Gurnee field in the Cahaba Basin and in the Pond Creek field in the Appalachian Basin. We also control the balance of approximately 178,000 net acres of coalbed methane exploration and development rights primarily in north central Louisiana, British Columbia, West Virginia, and Colorado. We have conducted substantial gas desorption testing and drilling of core holes throughout our property base. We believe our extensive undeveloped acreage position in the Gurnee field in the Cahaba Basin and in the Pond Creek field in the Appalachian Basin contains a total of 586 additional drilling locations.
At December 31, 2005, we had 262.5 Bcf of estimated proved reserves with a PV-10 of approximately $880 million using gas prices in effect at such date. See Selected Historical Consolidated Financial and Operating DataReconciliation of Non-GAAP Financial Measures for additional information regarding PV-10. Our estimated proved reserves at December 31, 2005 were 100% coalbed methane and 74% proved developed. For the month of May 2006, our net gas sales averaged approximately 16,500 Mcf per day. For 2005, our total capital expenditures were approximately $60 million, and our development expenditures for the development of the Gurnee and Pond Creek fields were approximately $46.4 million. We intend to increase our development expenditures by approximately 57% in 2006 to approximately $72 million to accelerate the drilling of the Gurnee and Pond Creek fields, of which we had spent $10.3 million on development expenditures as of March 31, 2006. For 2006, we estimate that our total capital expenditures will be approximately $90 million and had spent $13.4 million as of March 31, 2006.
Areas of Operation
Cahaba Basin
We have the development rights to approximately 41,800 net CBM acres throughout the Cahaba Basin of central Alabama, which is adjacent to the Black Warrior Basin. At December 31, 2005, approximately 55% of our estimated proved reserves, or 145.1 Bcf, were located in the Gurnee field within the Cahaba Basin, of which approximately 78% were classified as proved developed. At December 31, 2005, we had developed 24% of our
1
Cahaba Basin CBM acreage. We own a 100% working interest in the area and are the operator. Net daily sales of gas averaged approximately 5,200 Mcf for the month of May 2006. In 2006, we intend to spend approximately $45 million of our capital expenditure budget to develop and drill approximately 75 wells and expand our facilities in the Cahaba Basin. As of March 31, 2006, we had spent $6.6 million of this budget and drilled 17 wells.
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. 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 these facilities will meet all of our future water disposal requirements for the Gurnee field.
We control and operate a 9.2-mile, 12-inch high-pressure steel pipeline and a gas treatment and compression facility through which we gather, dehydrate, and compress our gas for delivery into the Southern Natural Gas pipeline system.
Appalachian Basin
In the Appalachian Basin of southern West Virginia and southwestern Virginia, we have the rights to develop approximately 56,000 net CBM acres, approximately 35,000 of which are in our Pond Creek field. At December 31, 2005, approximately 44% of our estimated proved reserves, or 114.5 Bcf, were located within the Pond Creek field, of which approximately 70% were classified as proved developed. We own a 100% working interest in the area and are the operator. Net daily sales of gas averaged approximately 10,000 Mcf for the month of May 2006. In 2006, we intend to spend approximately $20 million of our capital expenditure budget to develop and drill approximately 40 wells in the Pond Creek field. As of March 31, 2006, we had spent $3.7 million of this budget and drilled nine wells.
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. We believe this disposal well will meet our future water disposal requirements in the Pond Creek field.
Our gas is gathered into our central dehydration and compression facility and delivered into the Cardinal States Gathering System for redelivery into the Columbia Gas Transmission Corporation gas pipeline system.
British Columbia
Our Peace River Project is comprised of approximately 36,573 gross acres (18,287 net acres), including 3,573 gross acres (1,787 net acres) acquired in May 2006, along the Peace River near Hudsons Hope, British Columbia. We are conducting operations on this project through an exploration and development agreement with a third party. We will earn a 50% working interest in this leasehold by spending $7.2 million on an evaluation program. We have spent approximately $7.0 million of this amount from project inception through March 31, 2006. We expect to complete our earning obligations in the second quarter of 2006 and to operate this project going forward. We have drilled three core holes targeting the Lower Cretaceous Gething Coal Formation. We believe that the gas content and coal thickness under our acreage are favorable for CBM development. We have drilled and completed two production test wells, recompleted a third production test well and a water disposal well. We are in the process of testing operations on these wells.
North Central Louisiana
In Winn, LaSalle, and Caldwell Parishes of Louisiana, we are conducting an evaluation of the coals within the Wilcox formation. We operate the project with a 100% working interest. As of December 31, 2005, we had a total of approximately 119,000 net acres under lease. We have drilled 17 exploration or production test wells and
2
two water disposal wells. We have also conducted 60 gas desorption tests from a sample of nine of these wells to determine the gas content of the coal and to define the potential gas resources. We believe that the gas content and coal thickness under our acreage position are favorable for CBM development. We are currently evaluating producibility issues related to zonal isolation of adjacent water sands and related water encroachment in this area.
Piceance Basin of Colorado
We hold a total of approximately 16,900 net CBM acres of leasehold in the Piceance Basin in Mesa County, Colorado, of which approximately 14,600 net CBM acres are located in our Cameo prospect in the southwestern portion of the Piceance Basin. We have drilled one core hole and have conducted desorption tests on the core. We believe that the gas content and coal thickness under our acreage position are favorable for CBM development. We are actively pursuing opportunities to increase our acreage position in this area.
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 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 proppant 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.
3
Summary of Our Properties as of December 31, 2005
Estimated Proved Reserves(1) |
PV-10(2) | ||||||
Field |
Proved |
Proved Developed |
|||||
(MMcf) | (MMcf) | (In millions) | |||||
Appalachia: |
|||||||
Pond Creek field |
114,458 | 79,864 | $ | 366.3 | |||
Alabama: |
|||||||
Gurnee field |
145,062 | 112,517 | 496.6 | ||||
White Oak Creek field |
2,991 | 2,758 | 17.3 | ||||
Total |
262,511 | 195,139 | $ | 880.2 | |||
Area |
Net Productive Wells(3) |
Additional Drilling Locations(4) |
Net CBM Acres Owned or Controlled | |||||||
Total |
Developed |
Undeveloped | ||||||||
Appalachian Basin |
163 | 220 | 55,616 | 11,599 | 44,017 | |||||
Cahaba Basin |
132 | 366 | 41,766 | 10,120 | 31,646 | |||||
North Central Louisiana |
17 | | 119,244 | | 119,244 | |||||
British Columbia |
1 | | 16,500 | | 16,500 | |||||
Piceance Basin |
| | 16,949 | | 16,949 | |||||
Other (United States) |
| | 4,790 | | 4,790 | |||||
Total |
313 | 586 | 254,865 | 21,719 | 233,146 | |||||
(1) | Based on the reserve report prepared by DeGolyer and MacNaughton, independent petroleum engineers, a summary of which is attached to this prospectus as Appendix A. |
(2) | PV-10 was calculated using a natural gas price at December 31, 2005 of $9.66 per Mcf. See Selected Historical Consolidated Financial and Operating DataReconciliation of Non-GAAP Financial Measures for additional information. |
(3) | Excludes nine net wells pending completion at December 31, 2005. Productive wells are wells in which we have a working interest and that are producing or are capable of producing natural gas. |
(4) | Additional known drilling locations in proved projects. |
Recent Drilling Activity (net productive wells)
Year Ended December 31, | |||||||||||||
2005(1) |
2004 |
2003 |
2002 | ||||||||||
Development |
93.0 | 81.8 | 47.7 | 9.6 | |||||||||
Exploratory |
5.0 | 10.0 | 15.0 | 2.5 | |||||||||
Total |
98.0 | 91.8 | 62.7 | 12.1 | |||||||||
Total Capital Expenditures (in thousands) |
$ | 59,202 | $ | 86,189 | (2) | $ | 36,069 | $ | 12,770 | ||||
(1) | Excludes nine net wells pending completion. |
(2) | Includes $27 million for the acquisition of producing properties. |
Strategy
Our objective is to increase stockholder value by investing capital to increase our reserves, production, cash flow, and earnings. We intend to focus on the following strategies:
| Focus exclusively on coalbed methane operations where we have substantial experience and expertise. |
4
| Exploit our existing resource base by accelerating drilling in our projects and expanding into adjacent areas, thereby leveraging our knowledge of the area and our existing infrastructure and operating base. |
| Explore for large-scale CBM development opportunities both in our existing core areas and in other areas that we enter, where we intend to have operating control and the ability to reduce costs through economies of scale. We seek to be among the first companies in an area so that our costs of entry are less, large acreage positions can be established, and smaller incremental investments can be made to reduce our risk before larger expenditures are required. |
| Seek out opportunistic CBM producing property acquisitions. |
| Optimize financial flexibility by maintaining unused capacity under our bank revolving credit facility. We have a five-year, $180 million revolving credit facility with a $150 million borrowing base, of which $78.5 million was available for borrowing at June 20, 2006. |
Competitive Strengths
CBM Is Our Only Business. We explore for, develop, and produce CBM exclusively. We believe that substantial expertise and experience is required to develop, produce, and operate coalbed methane fields in an efficient manner. We believe that the inherent geologic and production characteristics of coalbed methane offer significant operational advantages compared to conventional gas production, including:
| Production Rates. Unlike conventional natural gas production, which typically declines after initial production is established, production from CBM wells typically increases for the first few years of their productive lives although eventual peak rates are often lower than those of typical conventional gas wells. CBM wells also generally decline at a shallow rate relative to typical conventional gas wells. |
| Low Geologic Risks. Most CBM areas are located in known coal basins where the coal resource has been evaluated for coal mining. These areas have extensive existing geologic information databases. The drilling of new coreholes and a limited number of production test wells reduces the geologic risk prior to committing large development expenditures. |
| Low Finding and Development Costs. Our finding and development costs have averaged $0.95 per Mcf for the three-year period ended December 31, 2005. These costs include estimated future development costs associated with proved undeveloped reserves. |
| Low Production Costs. In the early stage of CBM project development per unit operating costs are high because production is initially low and many of our costs are fixed. As production from a project increases and economies of scale are realized, the per unit operating costs typically decrease. Over the life of a project, we believe our average per unit operating costs will be lower than those of many conventional gas industry projects. |
| Long-lived Reserves. Because CBM wells have initial inclining production rates and low decline rates thereafter, CBM projects typically result in a reserve life that is significantly longer than many types of conventional gas production. |
Highly Experienced Team of CBM Professionals. Our 24-person CBM management, professional, and project management team has an average of more than 16 years of CBM experience and has participated in the drilling and operation of more than 2,600 CBM wells worldwide since 1977.
Large Inventory of Organic Growth Opportunities. We have a total of over 255,000 net acres of CBM exploration and development rights, including almost 77,000 net undeveloped acres in our two development areas. We believe our extensive undeveloped acreage position in the Gurnee field in the Cahaba Basin and in the Pond Creek field in the Appalachian Basin provides us with a total of 586 additional drilling locations.
5
Track Record of Success in Identifying and Exploiting Large Underdeveloped Resource Plays. We pursue those projects that leverage our CBM expertise to exploit underdeveloped resource potential where we believe we can improve on the prior performance of other operators. We have a history of developing large scale projects in multiple basins with low finding and development costs and low project life operating costs.
Minimal Water Disposal Issues. Unlike many CBM projects, water disposal is not a significant issue for us in the Gurnee field, where we have a pipeline in place to transport produced water for disposal into the Black Warrior River, or in the Pond Creek field, which produces comparatively low amounts of water and where we have an existing water disposal well that we believe is adequate for our needs.
Risks Affecting Our Business
Our ability to successfully leverage our competitive strengths and execute our strategy depends upon many factors and is subject to a variety of risks. For example, our ability to accelerate drilling on our properties and fund our 2006 capital budget depends, to a large extent, upon our ability to generate cash flow from operations at or above current levels, maintain borrowing capacity at or near current levels under our revolving credit facility, and the availability of future debt and equity financing at attractive prices. Our ability to fund CBM property acquisitions and compete for and retain the qualified personnel necessary to conduct our business is also dependent upon our financial resources. Changes in natural gas prices, which may affect both our cash flows and the value of our gas reserves, our ability to replace production through drilling activities, material adverse changes in our gas reserves due to factors other than gas pricing changes, our ability to transport our gas to markets, drilling costs and other factors, many of which are beyond our control, may adversely affect our ability to fund our anticipated capital expenditures, pursue property acquisitions, and compete for qualified personnel, among other things. You are urged to read the section entitled Risk Factors for more information regarding these and other risks that may affect our business and our common stock.
6
CORPORATE INFORMATION
During the first quarter of 2006, we completed a private equity offering of 10,250,000 shares of our common stock, consisting of 2,317,023 shares issued by us and 7,932,977 shares sold by certain of our existing stockholders, to qualified institutional buyers. We received aggregate consideration (before offering expenses of $850,000 but after the initial purchasers discount) of approximately $28.0 million, or $12.09 per share. We did not receive any proceeds from the shares sold by the selling stockholders. In addition, we received approximately $17.5 million from certain of the selling stockholders for repayment of loans from us, including accrued and unpaid interest thereon. We used the net proceeds from the offering, together with the proceeds from the repayment of the selling stockholders loans, to repay a portion of the borrowings under our credit facility and for general corporate purposes.
On April 14, 2005, GeoMet, Inc., an Alabama corporation (Old GeoMet), was merged with and into GeoMet Resources, Inc., a Delaware corporation (GeoMet), and we subsequently changed our name to GeoMet, Inc. We initially acquired 80% of the common stock of Old GeoMet on December 9, 2000 and subsequently acquired an additional 0.95% of Old GeoMets common stock on November 17, 2004. Accordingly, the equity of the minority interests in Old GeoMet was shown in the consolidated financial statements as a minority interest prior to April 14, 2005. The merger and related acquisition of the minority interest in Old GeoMet improved our financial flexibility, simplified our capital structure, and by aligning the interests of all equity holders, created a corporate structure more suited to a sale, public offering or other liquidity alternative for equity holders. Prior to our acquisition of the remaining minority interest in Old GeoMet, Old GeoMet held all of our gas assets and was, therefore, the borrower under bank credit facilities secured by such assets. We provided financing, management and other services to Old GeoMet, and Old GeoMet owed us $40 million in senior subordinated debt that had been advanced to fund exploration and development projects. Our acquisition of Old GeoMet eliminated the senior subordinated debt owned to us, combined our management and other personnel with the assets held by Old GeoMet that we managed, aligned the interests of our respective equity holders, and simplified our overall corporate structure. As a consequence of the elimination of the senior subordinated debt, borrowing capacity increased and financial flexibility was improved. The alignment of the interests of equity holders simplified our planning with respect to various liquidity alternatives and, generally, made it easier for investors and others to understand our company.
Our corporate headquarters are located at 909 Fannin, Suite 3208, Houston, Texas 77010 and our telephone number is (713) 659-3855. Our corporate website address is www.geometinc.com. Our technical and operational headquarters are located at 5336 Stadium Trace Parkway, Suite 206, Birmingham, Alabama 35244.
7
THE OFFERING
Common stock offered by us(1) |
5,066,408 shares. |
Common stock offered by the selling stockholders |
3,133,592 shares. |
Common stock to be outstanding after this offering(1)(2)(3) |
37,720,887 shares. |
Use of proceeds |
We will receive net proceeds from the sale of the shares offered by us, after deducting estimated offering expenses and underwriting discounts and commissions, of approximately $ million, based on an assumed offering price of $ per share. We expect to use our net proceeds from this offering to repay $ million of outstanding indebtedness under our credit facility and to use the remainder for general corporate purposes. We will not receive any proceeds from the sale of shares of our common stock by the selling stockholders. |
Dividend policy |
We do not anticipate that we will pay cash dividends in the foreseeable future. Our credit facility prohibits the payment of cash dividends. |
Risk factors |
For a discussion of factors you should consider in making an investment, see Risk Factors. |
Proposed Nasdaq symbol |
GMET |
(1) | We have granted the underwriters an option to purchase up to 1,230,000 additional shares of our common stock if the underwriters sell more than 8,200,000 shares of common stock in this offering. Unless otherwise indicated, share numbers assume that the underwriters do not exercise their option to purchase additional shares of common stock. |
(2) | Excludes options to purchase 1,770,990 shares of our common stock outstanding as of March 31, 2006, of which 1,682,990 were exercisable within 60 days. |
(3) | Represents 32,614,021 shares outstanding on March 31, 2006, 40,458 shares to be issued upon the exercise of options outstanding at March 31, 2006 that have been or will be exercised and sold by certain of the selling stockholders in this offering, and the shares to be issued by us in this offering. |
8
SUMMARY OF FINANCIAL, RESERVE AND OPERATING DATA
The following table shows our historical financial, reserve and operating data for, and as of the end of, each of the periods indicated. Our historical results are not necessarily indicative of the results that may be expected for any future period. The following data should be read in conjunction with Managements Discussion and Analysis of Results of Operations and Financial Condition and our consolidated financial statements and related notes included elsewhere in this prospectus.
Three Months Ended March 31, |
Year Ended December 31, |
|||||||||||||||||||
2006 |
2005 |
2005 |
2004 |
2003 |
||||||||||||||||
(Unaudited) | ||||||||||||||||||||
(In thousands, unless otherwise indicated) | ||||||||||||||||||||
STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME DATA: |
||||||||||||||||||||
Total revenues |
$ | 12,311 | $ | 6,507 | $ | 41,980 | $ | 20,924 | $ | 12,049 | ||||||||||
Lease operating expenses, compression and transportation expenses and production taxes |
4,186 | 2,930 | 12,933 | 7,517 | 3,047 | |||||||||||||||
Depreciation, depletion and amortization |
1,834 | 885 | 4,867 | 2,691 | 2,120 | |||||||||||||||
Research and development |
69 | 1 | 609 | 278 | 432 | |||||||||||||||
General and administrative |
1,020 | 751 | 3,208 | 2,513 | 1,370 | |||||||||||||||
Impairment of non-operating assets |
| | | | 8 | |||||||||||||||
Realized losses (gains) on derivative contracts |
596 | (165 | ) | 7,473 | 815 | 44 | ||||||||||||||
Unrealized losses (gains) from the change in market value of open derivative contracts |
(9,074 | ) | 4,839 | 12,059 | (542 | ) | 102 | |||||||||||||
Income from operations |
13,680 | (2,734 | ) | 831 | 7,652 | 4,926 | ||||||||||||||
Other expenses and interest, net |
866 | 592 | 3,839 | 920 | 144 | |||||||||||||||
Income tax expense (benefit) |
5,652 | (1,106 | ) | (993 | ) | 2,312 | 1,651 | |||||||||||||
Minority interest |
(442 | ) | 584 | 571 | ||||||||||||||||
Cumulative effect of change in accounting method |
| (507 | ) | | | 19 | ||||||||||||||
Net income (loss) |
$ | 7,163 | $ | (1,713 | ) | $ | (1,573 | ) | $ | 3,836 | $ | 2,541 | ||||||||
BALANCE SHEET DATA (at period end): |
||||||||||||||||||||
Working capital (deficit) |
$ | (8,384 | ) | $ | (6,388 | ) | $ | (7,368 | ) | $ | (1,251 | ) | $ | 5,133 | ||||||
Total assets |
$ | 260,951 | $ | 159,284 | $ | 247,909 | $ | 142,090 | $ | 81,505 | ||||||||||
Long-term debt |
$ | 58,377 | $ | 67,467 | $ | 99,926 | $ | 51,513 | $ | 10,102 | ||||||||||
Stockholders equity |
$ | 147,214 | $ | 60,975 | $ | 95,422 | $ | 65,692 | $ | 52,754 | ||||||||||
OTHER DATA: |
||||||||||||||||||||
Net cash provided by operating activities |
$ | 10,504 | $ | 2,696 | $ | 12,433 | $ | 10,580 | $ | 10,801 | ||||||||||
Net cash used in investing activities |
$ | (13,038 | ) | $ | (18,134 | ) | $ | (59,661 | ) | $ | (66,193 | ) | $ | (36,341 | ) | |||||
Net cash provided by financing activities |
$ | 3,270 | $ | 15,948 | $ | 44,906 | $ | 50,192 | $ | 30,534 | ||||||||||
Capital expenditures |
$ | 13,327 | $ | 18,130 | $ | 59,817 | $ | 86,189 | $ | 36,069 | ||||||||||
Net sales volume (Bcf) |
1.4 | 1.0 | 4.6 | 3.2 | 2.5 | |||||||||||||||
Average natural gas sales price ($ per Mcf) |
$ | 9.08 | $ | 6.38 | $ | 9.06 | $ | 6.12 | $ | 4.71 | ||||||||||
Average natural gas sales price ($ per Mcf) realized(1) |
$ | 8.64 | $ | 6.56 | $ | 7.43 | $ | 5.87 | $ | 4.69 | ||||||||||
Total production expenses ($ per Mcf) |
$ | 3.09 | $ | 2.94 | $ | 2.81 | $ | 2.36 | $ | 1.23 | ||||||||||
Expenses: ($ per Mcf) |
||||||||||||||||||||
Lease operating expenses |
$ | 2.09 | $ | 2.09 | $ | 1.89 | $ | 1.60 | $ | 0.66 | ||||||||||
Compression and transportation expenses |
$ | .79 | $ | .72 | $ | .72 | $ | 0.61 | $ | 0.40 | ||||||||||
Production taxes |
$ | .20 | $ | .13 | $ | .20 | $ | 0.15 | $ | 0.17 | ||||||||||
Research and development |
$ | .05 | $ | | $ | .13 | $ | 0.09 | $ | 0.17 | ||||||||||
General and administrative |
$ | .75 | $ | .75 | $ | .70 | $ | 0.79 | $ | 0.55 | ||||||||||
Depreciation, depletion & amortization |
$ | 1.35 | $ | .89 | $ | 1.06 | $ | 0.84 | $ | 0.85 | ||||||||||
Estimated proved reserves (Bcf)(2) |
| | 262.5 | 209.9 | 103.9 | |||||||||||||||
PV-10 ($ millions)(2)(3) |
| | $ | 880.2 | $ | 481.8 | $ | 236.9 | ||||||||||||
Standardized measure of discounted future net cash flows ($ millions) |
| | $ | 632.7 | $ | 349.8 | $ | 172.5 | ||||||||||||
Price used for PV-10 ($ per Mcf)(2) |
| | $ | 9.66 | $ | 6.21 | $ | 5.77 | ||||||||||||
EBITDA (in millions)(3) |
$ | 15.5 | $ | (1.3 | ) | $ | 6.1 | $ | 9.8 | $ | 6.5 |
(1) | Average realized price includes the effects of realized losses on derivative contracts. |
(2) | Based on the reserve reports prepared by DeGolyer and MacNaughton, independent petroleum engineers, at each period end. The natural gas price used to compute PV-10 is volatile and may fluctuate widely. Refer to Risk Factors for a more complete discussion. |
(3) | See Selected Historical Financial and Operating DataReconciliation of Non-GAAP Financial Measures for additional information. |
9
You should consider carefully each of the risks described below, together with all of the other information contained in this prospectus, before deciding to invest in our common stock.
Risks Related To Our Business
Natural gas prices are volatile, and a decline primarily in natural gas prices would significantly affect our financial results and impede our growth.
Our revenue, profitability, and cash flow depend upon the prices and demand for natural gas. The market for natural gas is very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
| the domestic and foreign supply of natural gas; |
| the price of foreign imports; |
| overall domestic and global economic conditions; |
| the consumption pattern of industrial consumers, electricity generators, and residential users; |
| weather conditions; |
| technological advances affecting energy consumption; |
| domestic and foreign governmental regulations; |
| proximity and capacity of gas pipelines and other transportation facilities; and |
| the price and availability of alternative fuels. |
Many of these factors may be beyond our control. Because all of our estimated proved reserves as of December 31, 2005 were natural gas reserves, our financial results are sensitive to movements in natural gas prices. Earlier in this decade, natural gas prices were much lower than they are today. Lower natural gas prices may not only decrease our revenues on a per Mcf basis, but also may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever managements plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.
We face uncertainties in estimating proved gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our reserves.
Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. In addition, in the early stages of a coalbed methane project, it is difficult to predict the production curve of a coalbed methane field. The estimated production profile of a field in the early stage of operations may vary significantly from the actual production profile as the field matures. As a result, quantities of estimated proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling,
10
testing, and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.
The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on current prices and costs. However, actual future net cash flows from our gas properties also will be affected by factors such as:
| geological conditions; |
| changes in governmental regulations and taxation; |
| assumptions governing future prices; |
| the amount and timing of actual production; |
| future gas prices and operating costs; and |
| capital costs of drilling new wells. |
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
Unless we replace our natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations, and cash flows.
Producing natural gas reservoirs are typically characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production generally declines at a shallow rate after initial increases in production which result as a consequence of the dewatering process. The rate of decline from our existing wells may change in a manner different than we have estimated. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find, or acquire additional reserves to replace our current and future production at acceptable costs.
Currently the vast majority of our producing properties are located in two counties in Alabama, one county in West Virginia, and one county in Virginia, making us vulnerable to risks associated with having our production concentrated in a few areas.
The vast majority of our producing properties are geographically concentrated in two counties in Alabama, one county in West Virginia, and one county in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, interruption of transportation of natural gas produced from the wells in these basins, or other events which impact these areas.
11
Our ability to market the gas we produce depends in substantial part on the availability and capacity of pipelines systems owned and operated by third parties. Operational impediments on these pipeline systems may hinder our access to natural gas markets or delay our production.
The availability of a ready market for our natural gas production depends on a number of factors, including the proximity of our reserves to pipelines, capacity constraints on pipelines, and disruption of transportation of natural gas through pipelines. We transport the natural gas we produce principally through pipelines owned by third parties. If we cannot access these third-party pipelines, or if transportation of gas through any of these pipelines is disrupted, we may be required to shut in or curtail production from some of our wells or seek alternate methods of transportation of our production. If any of these were to occur, our revenues would be would be reduced, which would in turn have a material adverse effect on our financial condition and results of operations.
The natural gas we produce from the Pond Creek field in the Appalachian Basin is gathered at our central dehydration and compression facility and is delivered into the Cardinal States Gathering Company (Cardinal States) gathering system for redelivery into the Columbia Gas Transmission Corporation gas pipeline system. Our gathering agreement with Cardinal States terminates on April 30, 2007. However, we are currently constructing a 12-mile pipeline to transport the natural gas we produce from the Pond Creek field into the Jewell Ridge Pipeline, which is currently being constructed by East Tennessee Natural Gas, LLC, a subsidiary of Duke Energy Corporation. Upon completion of our new pipeline, it will no longer be necessary for us to access the Cardinal States gathering system to transport our gas to market. Pocahontas Mining LLC (PMC) owns a portion of the land through which our new pipeline will be constructed and has granted us an easement to construct the pipeline on this land under a right-of-way agreement. CNX Gas Company LLC (CNX), the parent company of Cardinal States, has recently notified us that it believes that the pipeline right-of-way granted to us by PMC is invalid and that it has the exclusive right to transport natural gas across PMCs property. Thereafter, CNX gated certain access roads to PMCs property, impeding the construction of our pipeline; however, we have continued constructing the pipeline on acreage to which we have access. We have applied for a temporary and permanent injunction to prevent CNX from impeding our access to the property and are also seeking a declaration of our rights under the right-of-way agreement. The court held an evidentiary hearing on our claims on June 15, 2006. That hearing was continued until July 6, 2006 for the taking of additional evidence. In the interim period, the court has ordered CNX to allow us access to the property over and across the existing roads. In the event we are unsuccessful in obtaining a permanent injunction or declaratory judgment against CNX, we may be required to construct an alternate pipeline, change the planned route of our pipeline, seek alternative methods to transport our production to market, or extend our existing gathering agreement with Cardinal States on terms that will likely be unfavorable to us. Each of these alternatives will be costly and may result in our inability to deliver the gas we produce from the Pond Creek field to market for some period of time. If we are unable to deliver our gas to market for a prolonged period of time, our financial position, results of operations and cash flow will be materially adversely affected.
We may be unable to obtain adequate acreage to develop additional large-scale projects.
To achieve economies of scale and produce gas economically, we need to acquire large acreage positions to reduce our per unit costs. There are a limited number of coalbed formations in North America that we believe are favorable for CBM development. We face competition when acquiring additional acreage, and we may be unable to find or acquire additional acreage at prices that are acceptable to us.
Our exploration and development activities may not be commercially successful.
The exploration for and production of natural gas involves numerous risks. The cost of drilling, completing, and operating wells for coalbed methane or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:
| unexpected drilling conditions; |
| title problems; |
12
| pressure or irregularities in geologic formations; |
| equipment failures or repairs; |
| fires or other accidents; |
| adverse weather conditions; |
| reductions in natural gas prices; |
| pipeline ruptures; and |
| unavailability or high cost of drilling rigs, other field services, and equipment. |
Our future drilling activities may not be successful, and our drilling success rates could decline. Unsuccessful drilling activities could result in higher costs without any corresponding revenues.
We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves.
We depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flow, bank borrowings, and issuances of common stock. Our future contractual commitments from January 1, 2006 through December 31, 2011 total $150 million and include debt service, operating lease obligations, firm transportation obligations and other obligations, collectively aggregating approximately $18 million during 2006, $25 million during 2007 to 2010, and $107 million during 2011 to 2012, when our existing credit facility matures. We also require capital to fund our drilling budget, which is expected to be $90 million for 2006. We will be required to meet our needs from our internally generated cash flow, debt financings, and equity financings.
If our revenues decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. Our revolving credit facility contains covenants restricting our ability to incur additional indebtedness without the consent of the lender. There can be no assurance that our lender will provide this consent or as to the availability or terms of any additional financing. If we incur additional debt, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our level of debt affects our operations in several important ways, including the following:
| a portion of our cash flow from operations is used to pay interest on borrowings; |
| a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; |
| a leveraged financial position would make us more vulnerable to economic downturns and could limit our ability to withstand competitive pressures; and |
| any debt that we incur under our revolving credit facility will be at variable rates which makes us vulnerable to increases in interest rates. For example, a 1% increase in interest rates based upon our debt outstanding as of December 31, 2005 would result in an additional $990,000 of interest expense. |
Even if additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our projects, which in turn could lead to a possible loss of properties and a decline in our natural gas reserves.
13
Our credit facility contains a number of financial and other covenants, and our obligations under the credit facility are secured by substantially all of our assets. If we are unable to comply with these covenants, our lenders could accelerate the repayment of our indebtedness.
Our credit facility subjects us to a number of covenants that impose restrictions on us, including our ability to incur indebtedness and liens, make loans and investments, sell assets, engage in mergers, consolidations and acquisitions, enter into transactions with affiliates, or pay dividends on our common stock. We are also required by the terms of our credit facility to comply with certain financial ratios. Our credit facility also provides for periodic redeterminations of our borrowing base, which may affect our borrowing capacity. Our credit facility is secured by a lien on substantially all of our assets, including equity interests in our subsidiaries. A more detailed description of our credit facility is included in Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources and the footnotes to our consolidated financial statements included elsewhere in this prospectus.
A breach of any of the covenants imposed on us by the terms of our credit facility, including the financial covenants, could result in a default under such indebtedness. In the event of a default, the lenders could terminate their commitments to us, and they could accelerate the repayment of all of our indebtedness. In such case, we may not have sufficient funds to pay the total amount of accelerated obligations, and our lenders could proceed against the collateral securing the facility. Any acceleration in the repayment of our indebtedness or related foreclosure could adversely affect our business.
In addition, the borrowing base under our credit facility is redetermined semi-annually and may be redetermined at other times upon request by the lenders under certain circumstances. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. The next scheduled redetermination is to occur as of June 30, 2006. Upon a redetermination, we could be required to repay a portion of our bank debt. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the credit facility and an acceleration of our indebtedness.
We operate in a highly competitive environment and many of our competitors have greater resources than we do.
The gas industry is intensely competitive and we compete with companies from various regions of the United States and Canada and may compete with foreign suppliers for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our operating results and financial position may be adversely affected. For example, one of our competitive strengths is as a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive advantage in that area.
In addition, larger companies may be able to pay more to acquire new properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new reserves also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.
The coalbeds from which we produce gas frequently contain water that may hamper our ability to produce gas in commercial quantities or affect our profitability.
Unlike conventional natural gas production, coalbeds frequently contain water that must be removed in order for the gas to desorb from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities. The cost of water disposal may affect our profitability.
14
We may face unanticipated water disposal costs.
Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies or our wells produce water in excess of the applicable volumetric permit limit, we may have to shut in wells, reduce drilling activities, or upgrade facilities. The costs to dispose of this produced water may increase if any of the following occur:
| we cannot obtain future permits from applicable regulatory agencies; |
| water of lesser quality is produced; |
| our wells produce excess water; or |
| new laws and regulations require water to be disposed of in a different manner. |
Our operations in British Columbia present unique risks and uncertainties, different from or in addition to those we face in our domestic operations.
We conduct our operations in British Columbia through our wholly owned subsidiary, Hudsons Hope Gas Ltd. Our operations in British Columbia may be adversely affected by currency fluctuations. The expenses of such operations are payable in Canadian dollars. As a result, our Canadian operations are subject to risk of fluctuations in the relative value of the Canadian and United States dollars. Other risks of operations in Canada include, among other things, increases in taxes and governmental royalties and changes in laws and policies governing operations of foreign-based companies. Laws and policies of the United States affecting foreign trade and taxation may also adversely affect our operations in British Columbia.
We may be unable to retain our existing senior management team and/or our key personnel that has expertise in coalbed methane extraction and our failure to continue to attract qualified new personnel could adversely affect our business.
Our business requires disciplined execution at all levels of our organization to ensure that we continually develop our reserves and produce gas at profitable levels. This execution requires an experienced and talented management and production team. If we were to lose the benefit of the experience, efforts and abilities of any of our key executives or the members of our team that have developed substantial expertise in coalbed methane extraction, our business could be adversely affected. We have not entered into, and do not expect to enter into employment agreements or non-competition agreements with any of our key employees, other than J. Darby Seré, our Chief Executive Officer and President, and William C. Rankin, our Executive Vice President and Chief Financial Officer. We do not maintain key person life insurance on any of our personnel. Our ability to manage our growth, if any, will require us to continue to train, motivate, and manage our employees and to attract, motivate, and retain additional qualified managerial and production personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating, and retaining the personnel required to grow and operate our business profitably.
Government laws, regulations, and other legal requirements relating to protection of the environment, health and safety matters and others that govern our business increase our costs and may restrict our operations.
We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state, local, and foreign authorities, relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, control of surface subsidence from underground mining, and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will
15
continue to have, a significant effect on our respective costs of operations and competitive position. In addition, we could incur substantial costs, including clean-up costs, fines and civil or criminal sanctions, and third party damage claims for personal injury, property damage, wrongful death, or exposure to hazardous substances, as a result of violations of or liabilities under environmental and health and safety laws.
Additionally, the gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the pricing or marketing of gas production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing, and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.
We must obtain governmental permits and approvals for drilling operations, which can be a costly and time consuming process and result in restrictions on our operations.
Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of gas may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.
We have limited protection for our technology and depend on technology owned by others.
We use operating practices that management believes are of significant value in developing CBM resources. In most cases, patent or other intellectual property protection is unavailable for this technology. Our use of independent contractors in most aspects of our drilling and some completion operations makes the protection of such technology more difficult. Moreover, we rely on the technological expertise of the independent contractors that we retain for our operations. We have no long-term agreements with these contractors, and thus we cannot be sure that we will continue to have access to this expertise.
We may incur additional costs to produce gas because our confirmation of title for gas rights for some of our properties may be inadequate or incomplete.
We generally obtain title opinions on significant properties that we drill or acquire. However, we cannot be sure that we will not suffer a monetary loss from title defects or failure. In addition, the steps needed to perfect our ownership varies from state to state and some states permit us to produce the gas without perfected ownership under forced pooling arrangements while other states do not permit this. As a result, we may have to incur title costs and pay royalties to produce gas on acreage that we control and these costs may be material and vary depending upon the state in which we operate.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel, and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical, and from time to time there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment, and supplies are substantially greater. As a result of historically strong prices of gas, the demand for oilfield services has risen,
16
and the costs of these services are increasing. If the unavailability or high cost of drilling rigs, equipment, supplies, or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected.
Hedging transactions may limit our potential gains.
In order to manage our exposure to price risks in the marketing of our natural gas production, we have entered into natural gas price hedging arrangements with respect to a portion of our expected production. We will most likely enter into additional hedging transactions in the future. While intended to reduce the effects of volatile natural gas prices, such transactions may limit our potential gains and increase our potential losses if natural gas prices were to rise substantially over the price established by the hedge. For example, as a consequence of increases in natural gas prices during the year ended December 31, 2005, we recognized total losses on our outstanding hedges of approximately $19.5 million (consisting of a $7.5 million realized loss and a $12 million unrealized loss). Based upon the hedges we had in place at December 31, 2005, hypothetical 10% and 25% increases in natural gas prices would have increased our pre-tax loss by approximately $4.9 million and $12.9 million, respectively. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:
| our production is less than expected; or |
| the counterparties to our hedging agreements fail to perform under the contracts. |
We do not insure against all potential operating risks. We may incur substantial losses and be subject to substantial liability claims as a result of our natural gas operations.
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.
Risks Relating to Our Common Stock
One existing stockholder holds a substantial interest in our company, and insiders own a significant amount of our common stock, which could limit your ability to influence the outcome of stockholder votes, and the interests of this stockholder and these insiders could differ from those of our other stockholders.
A representative of Yorktown Energy Partners IV, L.P. (Yorktown) serves on our board of directors, and, following the closing of this offering, Yorktown will own approximately 37.2% of our outstanding common stock. In addition, our executive officers and their affiliates will beneficially own or control approximately 10.2% of our outstanding common stock following the closing of this offering. Yorktown and our executive officers and directors have, and can be expected to continue to have, a significant voice in our affairs and in the outcome of stockholder voting. Under Delaware law and our certificate of incorporation, matters requiring a stockholder to vote, including the election of directors, the adoption of an amendment to our certificate of incorporation, and the approval of mergers and other significant corporate transactions require the affirmative vote of the holders of a majority of the outstanding shares or, in the case of the election of directors, a plurality of the votes cast. As a consequence, the effect of this level of share ownership by Yorktown and our officers and directors may permit
17
them to approve certain matters by written consent and may delay or prevent a change of control of us or otherwise protect your investment.
There has been no public market for our common stock, and our stock price may fluctuate significantly.
There is currently no public market for our common stock, and an active trading market may not develop or be sustained after the sale of all of the shares covered by this prospectus. The market price of our common stock could fluctuate significantly as a result of:
| our operating and financial performance and prospects; |
| quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues; |
| changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry; |
| liquidity and registering our common stock for public resale; |
| actual or unanticipated variations in our reserve estimates and quarterly operating results; |
| changes in oil and gas prices; |
| speculation in the press or investment community; |
| sales of our common stock by our stockholders; |
| increases in our cost of capital; |
| changes in applicable laws or regulations, court rulings and enforcement and legal actions; |
| changes in market valuations of similar companies; |
| adverse market reaction to any increased indebtedness we incur in the future; |
| additions or departures of key management personnel; |
| actions by our stockholders; |
| general market and economic conditions, including the occurrence of events or trends affecting the price of natural gas; and |
| domestic and international economic, legal, and regulatory factors unrelated to our performance. |
If a trading market develops for our common stock, stock markets in general experience volatility that often is unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.
The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public markets.
We have recently filed a registration statement registering for resale the 10,250,000 shares of common stock that we sold in our private placement during the first quarter of 2006. The sale of a large number of shares of our common stock pursuant to the resale registration statement, the perception that any such sale might occur, or the issuance of a large number of shares of our common stock in connection with future acquisitions, equity financings or otherwise, could cause the market price of our common stock to decline significantly. After the completion of this offering, we will have 37,720,887 shares of common stock issued and outstanding, including approximately 18,000,000 shares of our common stock held by our executive officers and directors which are or will be eligible for sale under Rule 144 after the expiration of the 180-day lock-up period that is applicable to our executive officers, directors, and certain of our stockholders following the completion of this offering. All of the
18
shares of common stock sold in this offering will be freely tradable without restriction or further registration under the Securities Act by persons other than our affiliates (within the meaning of Rule 144 under the Securities Act) immediately upon completion of this offering, subject to the 180-day lock-up period. Additionally, we may file one or more registration statements with the Securities and Exchange Commission providing for the registration of up to approximately 4,400,000 additional shares of our common stock issued or reserved for issuance under our employee plans, all of which will be eligible for sale without further registration under the Securities Act.
We may not be accepted for listing or inclusion on a national securities exchange.
In connection with our filing of this registration statement, we have agreed to use commercially reasonable efforts to satisfy the criteria for inclusion of (if we meet the criteria for listing on such market) our common stock on the Nasdaq National Market as soon as practicable (including seeking to cure in our listing and inclusion application any deficiencies cited by such market), and thereafter maintain the listing on the Nasdaq National Market. We have applied to have our common stock approved for quotation on the Nasdaq National Market. The Nasdaq National Market has initial listing criteria, including criteria related to minimum bid price, public float, market makers, minimum number of round lot holders, and board independence requirements, which we expect to meet upon completion of this offering; however, we can give no assurance that we will meet these requirements. We currently do not satisfy the minimum round lot holder requirements of the Nasdaq National Market. Our inability to list or include our common stock on the Nasdaq National Market could affect the ability of stockholders to sell their shares of common stock and consequently adversely affect the value of such shares. In addition, we would have more difficulty attracting the attention of market analysts to cover us in their research.
If our common stock is approved for inclusion on the Nasdaq National Market, we will have no prior trading history, and thus there is no way to determine the prices or volumes at which our common stock will trade. We can give no assurances as to the development of liquidity or any trading market for our common stock. Holders of shares of our common stock may not be able to resell their shares at or near their original acquisition price, or at any price.
We do not intend to pay, and are prohibited from paying, any dividends on our common stock.
We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs and plans for expansion. In addition, the declaration and payment of any dividends on our common stock is prohibited by the terms of our credit facility so long as it is in effect. The credit facility terminates in January 2011; however, prior to that time we may enter into a new credit facility or other contractual arrangement that further restricts our ability to pay dividends.
You may experience dilution of your ownership interests due to the future issuance of shares of our common stock, which could have an adverse effect on our stock price.
We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. Our authorized capital stock consists of 125,000,000 shares of common stock and 10,000,000 shares of preferred stock with such designations, preferences, and rights as may determined by our board of directors. As of March 31, 2006, 32,614,021 shares of common stock and no shares of preferred stock were outstanding. As of March 31, 2006, we have reserved 4,400,000 shares for future issuance to employees as restricted stock or stock option awards pursuant to our stock option plans, of which options to purchase 2,172,552 shares have already been granted, 1,770,990 of which remain outstanding and 2,227,448 shares remain available for future grants. The potential
19
issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes, or for other business purposes. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.
Purchasers of common stock in this offering will experience immediate and substantial dilution of $ per share.
Based on an assumed initial public offering price of $ per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of March 31, 2006 after giving effect to this offering would be $ per share. See Dilution for a complete description of the calculation of net tangible book value.
We will incur increased costs as a result of being a public company.
As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. The U.S. Sarbanes-Oxley Act of 2002 and related rules of the U.S. Securities and Exchange Commission, or SEC, and the Nasdaq National Market regulate corporate governance practices of public companies. We expect that compliance with these public company requirements will increase our costs and make some activities more time consuming. For example, we have created new board committees, and we will adopt new internal controls and disclosure controls and procedures. In addition, we will incur additional expenses associated with our SEC reporting requirements. A number of those requirements will require us to carry out activities we have not conducted previously. For example, under Section 404 of the Sarbanes-Oxley Act, for our annual report on Form 10-K for 2007, we will need to document and test our internal control procedures, our management will need to assess and report on our internal control over financial reporting and our independent accountants will need to issue an opinion on that assessment and the effectiveness of those controls. Furthermore, if we identify any issues in complying with those requirements (for example, if we or our independent auditors identified a material weakness or significant deficiency in our internal control over financial reporting), we could incur additional costs rectifying those issues, and the existence of those issues could adversely affect us, our reputation or investor perceptions of us. We also expect that it could be difficult and will be significantly more expensive to obtain directors and officers liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified persons to serve on our board of directors or as executive officers. Advocacy efforts by shareholders and third parties may also prompt even more changes in governance and reporting requirements. We cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.
20
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Various statements in this prospectus, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future reserves, production, revenues, income, and capital spending. When we use the words believe, intend, expect, may, should, anticipate, could, estimate, plan, predict, project, or their negatives, other similar expressions, or the statements that include those words are usually forward-looking statements.
The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, managements assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the Risk Factors section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:
| our business strategy; |
| our financial position; |
| our cash flow and liquidity; |
| declines in the prices we receive for our gas affecting our operating results and cash flows; |
| uncertainties in estimating our gas reserves; |
| replacing our gas reserves; |
| uncertainties in exploring for and producing gas; |
| our inability to obtain additional financing necessary in order to fund our operations, capital expenditures, and to meet our other obligations; |
| availability of drilling and production equipment and field service providers; |
| disruptions, capacity constraints in, or other limitations on the pipeline systems which deliver our gas; |
| competition in the gas industry; |
| our inability to retain and attract key personnel; |
| our joint venture arrangements; |
| the effects of government regulation and permitting and other legal requirements; |
| costs associated with perfecting title for gas rights in some of our properties; |
| our need to use unproven technologies to extract coalbed methane in some properties; and |
| other factors discussed under Risk Factors. |
21
We expect to receive net proceeds from this offering of approximately $ million ($ million if the underwriters option to purchase additional shares is exercised in full), based on an assumed public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting underwriting discounts and commissions and estimated offering expenses of $ incurred by us. We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders.
We expect to use our net proceeds from this offering to repay $ million of outstanding indebtedness under our credit facility and to use the remainder for general corporate purposes.
We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to reinvest cash flow generated by operations in our business. Our credit facility currently prohibits us from paying cash dividends on our common stock. Our credit facility terminates in January 2011; however, prior to that time we may enter into other credit agreements or borrowing arrangements that restrict our ability to declare or pay cash dividends on our common stock. Our board of directors has the authority to issue preferred stock and to fix dividend rights that may have preference to our common stock.
22
The following table presents our capitalization as of March 31, 2006, on:
| a historical basis; and |
| as adjusted to give effect to the sale of shares in this offering and the application of the net proceeds we receive as set forth under Use of Proceeds. |
You should read this table in conjunction with our consolidated financial statements included in this prospectus.
March 31, 2006 | |||||||
Historical |
As Adjusted | ||||||
(In thousands) | |||||||
Cash and cash equivalents(1) |
$ | 1,340 | $ | ||||
Long-term debt(1) |
$ | 58,377 | $ | ||||
Stockholders equity: |
|||||||
Common stock, $0.001 par value, 125,000,000 shares authorized; and 32,614,021 shares issued and outstanding, and 37,720,887 shares issued and outstanding, as adjusted |
$ | 33 | $ | ||||
Preferred stock, $0.001 par value, 10,000,000 shares authorized, none issued |
| ||||||
Additional paid-in capital(2) |
133,956 | ||||||
Accumulated other comprehensive income |
31 | ||||||
Retained earnings |
13,607 | ||||||
Notes receivable(1) |
(413 | ) | |||||
Total stockholders equity |
147,214 | ||||||
Total capitalization |
$ | 206,931 | $ | ||||
(1) | Long-term debt decreased by $ from the sale of shares of common stock in this offering. |
(2) | Our additional paid-in capital increased by approximately $ from the sale of 5,066,408 shares of common stock in this offering. |
23
If you invest in our common stock, your interest will be diluted to the extent of the difference between the public offering price per share and the pro forma net tangible book value per share of the common stock after this offering. Our net tangible book value as of March 31, 2006, was $ per share of common stock. Net tangible book value per share represents the amount of the total tangible assets less our total liabilities, divided by the number of shares of common stock that are outstanding. After giving effect to the sale of shares of common stock in this offering at an assumed offering price of $ per share and after the deduction of underwriting discounts and commissions and estimated offering expenses, the as adjusted net tangible book value at March 31, 2006 would have been $ million, or $ per share. This represents an immediate increase in such net tangible book value of $ per share to existing stockholders and an immediate and substantial dilution of $ per share to new investors purchasing common stock in this offering. The following table illustrates this per share dilution:
Assumed offering price per share |
$ | |||||
Net tangible book value per share as of March 31, 2006 |
$ | |||||
Increase attributable to new public investors |
$ | |||||
As adjusted net tangible book value per share after this offering |
$ | |||||
Dilution in as adjusted net tangible book value per share to new investors |
$ | |||||
Assuming the exercise in full of the underwriters option to purchase additional shares, our as adjusted net tangible book value at March 31, 2006 would have been approximately $ per share, representing an immediate increase in the net tangible book value of $ per share to our existing stockholders and an immediate decrease in net tangible book value of $ per share to new investors.
The following table summarizes, on an as adjusted basis, as of March 31, 2006, the difference between the number of shares of common stock purchased from us, the total consideration paid to us and the average price per share paid by existing stockholders and by new investors at an assumed initial public offering price of $ per share, before deducting estimated underwriting discounts and commissions and estimated offering expenses.
Shares Purchased |
Total Consideration |
Average Price Per Share | ||||||||||||
Number |
Percent |
Amount |
Percent |
|||||||||||
Existing stockholders |
% | $ | % | $ | ||||||||||
New investors |
||||||||||||||
Total |
100.0 | % | $ | 100.0 | % | |||||||||
24
SELECTED HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA
The following table shows our selected historical consolidated financial and operating data as of and for the three months ended March 31, 2006 and 2005 and each of the five years ended December 31, 2005. The selected historical consolidated financial and operating data for the three months ended March 31, 2006 and 2005 was derived from our unaudited financial statements included herein. The selected historical consolidated financial and operating data for the three years ended December 31, 2005 are derived from our audited financial statements included herein. The selected historical consolidated financial and operating data for the two years ended December 31, 2002 was derived from our audited financial statements which are not included herein. You should read the following data in conjunction with Managements Discussion and Analysis of Results of Operations and Financial Condition and our consolidated financial statements and related notes included elsewhere in this prospectus where there is additional disclosure regarding the information in the following table. Our historical results are not necessarily indicative of the results that may be expected in future periods.
Three Months Ended March 31, |
Year Ended December 31, |
|||||||||||||||||||||||||||
2006 |
2005 |
2005 |
2004 |
2003 |
2002 |
2001 |
||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||||||||
(In thousands, unless otherwise indicated) | ||||||||||||||||||||||||||||
STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME DATA: |
||||||||||||||||||||||||||||
REVENUES |
||||||||||||||||||||||||||||
Gas sales |
$ | 12,311 | $ | 6,369 | $ | 41,604 | $ | 19,522 | $ | 11,700 | $ | 6,731 | $ | 11,850 | ||||||||||||||
Operating fees and other |
| 138 | 376 | 1,402 | 349 | 277 | 205 | |||||||||||||||||||||
Total revenues |
12,311 | 6,507 | 41,980 | 20,924 | 12,049 | 7,008 | 12,055 | |||||||||||||||||||||
EXPENSES |
||||||||||||||||||||||||||||
Lease operating expenses |
2,841 | 2,083 | 8,687 | 5,092 | 1,640 | 590 | 542 | |||||||||||||||||||||
Compression and transportation expenses |
1,076 | 721 | 3,332 | 1,951 | 993 | 654 | 681 | |||||||||||||||||||||
Production taxes |
269 | 126 | 914 | 473 | 414 | 285 | 560 | |||||||||||||||||||||
Depreciation, depletion and amortization |
1,834 | 885 | 4,867 | 2,691 | 2,120 | 2,151 | 3,167 | |||||||||||||||||||||
Research and development |
69 | 1 | 609 | 279 | 432 | 168 | | |||||||||||||||||||||
General and administrative |
1,020 | 751 | 3,208 | 2,513 | 1,370 | 1,598 | 1,206 | |||||||||||||||||||||
Impairment of other equipment and other non-current assets |
| | | | 8 | 108 | | |||||||||||||||||||||
Realized losses (gains) on derivative contracts |
596 | (165 | ) | 7,473 | 815 | 44 | | | ||||||||||||||||||||
Unrealized losses (gains) from the change in market value of open derivative contracts |
(9,074 | ) | 4,839 | 12,059 | (542 | ) | 102 | | | |||||||||||||||||||
Total operating expenses |
(1,369 | ) | 9,241 | 41,149 | 13,272 | 7,123 | 5,554 | 6,156 | ||||||||||||||||||||
Income (loss) from operations |
13,680 | (2,734 | ) | 831 | 7,652 | 4,926 | 1,454 | 5,899 | ||||||||||||||||||||
Interest income |
11 | 18 | 77 | 70 | 95 | 119 | 291 | |||||||||||||||||||||
Interest expense (net of amounts capitalized) |
(863 | ) | (609 | ) | (3,895 | ) | (986 | ) | (232 | ) | (186 | ) | (151 | ) | ||||||||||||||
Other expenses |
(13 | ) | | (21 | ) | (4 | ) | (7 | ) | (7 | ) | (3 | ) | |||||||||||||||
Total other income (expense) |
(866 | ) | (592 | ) | (3,839 | ) | (920 | ) | (144 | ) | (74 | ) | 137 | |||||||||||||||
Income (loss) before income taxes, minority interest, and cumulative effect of change in accounting principle, net of income tax |
12,815 | (3,226 | ) | (3,008 | ) | 6,732 | 4,782 | 1,380 | 6,036 | |||||||||||||||||||
Income tax expense (benefit) |
5,652 | (1,106 | ) | (993 | ) | 2,312 | 1,651 | 639 | 1,152 | |||||||||||||||||||
Net income (loss) before minority interest and cumulative effect of |
7,163 | (2,220 | ) | (2,015 | ) | 4,420 | 3,131 | 741 | 4,884 | |||||||||||||||||||
Minority interest |
| (507 | ) | (442 | ) | 584 | 571 | 138 | 958 | |||||||||||||||||||
Net income (loss) before cumulative effect of change in accounting principle, net of income tax |
7,163 | (1,713 | ) | (1,573 | ) | 3,836 | 2,560 | 603 | 3,926 | |||||||||||||||||||
Cumulative effect of change in accounting principle, net of income tax |
| | | | 19 | | | |||||||||||||||||||||
Net income (loss) |
$ | 7,163 | $ | (1,713 | ) | $ | (1,573 | ) | $ | 3,836 | $ | 2,541 | $ | 603 | $ | 3,926 | ||||||||||||
Other comprehensive income |
||||||||||||||||||||||||||||
Foreign currency translation adjustment, net of income taxes of $0 |
25 | (4 | ) | 54 | 2 | | | | ||||||||||||||||||||
Comprehensive income (loss) |
$ | 7,138 | $ | (1,717 | ) | $ | (1,519 | ) | $ | 3,838 | $ | 2,541 | $ | 603 | $ | 3,926 | ||||||||||||
25
SELECTED HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA (continued):
Three Months Ended March 31, |
Year Ended December 31, |
|||||||||||||||||||||||||||
2006 |
2005 |
2005 |
2004 |
2003 |
2002 |
2001 |
||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||||||||
(In thousands unless otherwise indicated) | ||||||||||||||||||||||||||||
Net income (loss) per common share: |
||||||||||||||||||||||||||||
Basic |
$ | 0.23 | $ | (0.07 | ) | $ | (0.06 | ) | $ | 0.17 | $ | 0.20 | $ | 0.08 | $ | 0.49 | ||||||||||||
Diluted |
$ | 0.22 | $ | (0.07 | ) | $ | (0.06 | ) | $ | 0.17 | $ | 0.20 | $ | 0.08 | $ | 0.49 | ||||||||||||
BALANCE SHEET DATA (at period end): |
||||||||||||||||||||||||||||
Working capital (deficit) |
$ | (8,384 | ) | $ | (6,388 | ) | $ | (7,368 | ) | $ | (1,251 | ) | $ | 5,133 | $ | 3,940 | $ | 6,268 | ||||||||||
Total assets |
$ | 260,951 | $ | 159,284 | $ | 247,909 | $ | 142,090 | $ | 81,505 | $ | 42,261 | $ | 33,240 | ||||||||||||||
Long-term debt |
$ | 58,377 | $ | 67,467 | $ | 99,926 | $ | 51,513 | $ | 10,102 | $ | 6,665 | $ | 1,242 | ||||||||||||||
Stockholders equity |
$ | 147,214 | $ | 60,975 | $ | 95,422 | $ | 65,692 | $ | 52,754 | $ | 22,912 | $ | 22,310 | ||||||||||||||
OTHER DATA: |
||||||||||||||||||||||||||||
Net cash provided by operating activities |
$ | 10,504 | $ | 2,696 | $ | 12,433 | $ | 10,580 | $ | 10,801 | $ | 4,603 | $ | 8,669 | ||||||||||||||
Net cash used in investing activities |
$ | (13,038 | ) | $ | (18,134 | ) | $ | (59,661 | ) | $ | (66,193 | ) | $ | (36,341 | ) | $ | (12,773 | ) | $ | (5,232 | ) | |||||||
Net cash provided by (used in) financing activities |
$ | 3,270 | $ | 15,948 | $ | 44,906 | $ | 50,192 | $ | 30,534 | $ | 5,372 | $ | (2,127 | ) | |||||||||||||
Capital expenditures |
$ | 13,327 | $ | 18,130 | $ | 59,817 | $ | 86,189 | $ | 36,069 | $ | 12,770 | $ | 5,117 | ||||||||||||||
Net sales volume (Bcf) |
1.4 | 1.0 | 4.6 | 3.2 | 2.5 | 2.1 | 2.5 | |||||||||||||||||||||
Average natural gas sales price ($ per Mcf) |
$ | 9.08 | $ | 6.38 | $ | 9.06 | $ | 6.12 | $ | 4.71 | $ | 3.16 | $ | 4.73 | ||||||||||||||
Average natural gas sales price ($ per Mcf) realized(1) |
$ | 8.64 | $ | 6.56 | $ | 7.43 | $ | 5.87 | $ | 4.69 | $ | 3.16 | $ | 4.73 | ||||||||||||||
Total production expenses ($ per Mcf) |
$ | 3.09 | $ | 2.94 | $ | 2.81 | $ | 2.36 | $ | 1.23 | $ | 0.72 | $ | 0.71 | ||||||||||||||
Estimated proved reserves (Bcf)(2) |
| | 262.5 | 209.9 | 103.9 | 35.5 | 16.7 | |||||||||||||||||||||
PV-10 ($ millions)(2)(3) |
| | $ | 880.2 | $ | 481.8 | $ | 236.9 | $ | 64.4 | $ | 19.2 | ||||||||||||||||
Standardized measure of discounted future net cash flows ($ millions) |
| | $ | 632.7 | $ | 349.8 | $ | 172.5 | $ | 45.4 | $ | 14.0 | ||||||||||||||||
EBITDA ($ millions)(3) |
$ | 15.5 | $ | (1.3 | ) | $ | 6.1 | $ | 9.8 | $ | 6.5 | $ | 3.5 | $ | 8.1 |
(1) | Average realized price includes the effects of realized losses on derivative contracts. |
(2) | Based on the reserve reports prepared by DeGolyer and MacNaughton, independent petroleum engineers, at each period end. Natural gas prices are volatile and may fluctuate widely affecting significantly the calculation of estimated net cash flows. Refer to Risk Factors for a more complete discussion. |
(3) | See Reconciliation of Non-GAAP Financial Measures below for additional information. |
26
Reconciliation of Non-GAAP Financial Measures
The following table shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their present value. We believe PV-10 to be an important measure for evaluating the relative significance of our CBM gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
As of December 31, |
||||||||||||||||||||
2005 |
2004 |
2003 |
2002 |
2001 |
||||||||||||||||
(In thousands) | ||||||||||||||||||||
Future cash inflows |
$ | 2,536,279 | $ | 1,302,830 | $ | 599,501 | $ | 163,986 | $ | 45,679 | ||||||||||
Less: Future production costs |
463,416 | 290,425 | 125,765 | 48,771 | 14,030 | |||||||||||||||
Less: Future development costs |
76,297 | 38,242 | 23,832 | 4,676 | 1,140 | |||||||||||||||
Future net cash flows |
1,996,566 | 974,163 | 449,904 | 110,539 | 30,509 | |||||||||||||||
Less: 10% discount factor |
1,116,413 | (492,339 | ) | (213,018 | ) | (46,095 | ) | (11,310 | ) | |||||||||||
PV-10 |
$ | 880,153 | 481,824 | 236,886 | 64,444 | 19,199 | ||||||||||||||
Less: Undiscounted income taxes |
(579,689 | ) | (274,975 | ) | (125,858 | ) | (32,101 | ) | (8,196 | ) | ||||||||||
Plus: 10% discount factor |
332,201 | 142,906 | 61,520 | 13,084 | 2,969 | |||||||||||||||
Discounted income taxes |
(247,488 | ) | (132,069 | ) | (64,338 | ) | (19,017 | ) | (5,227 | ) | ||||||||||
Standardized measure of discounted future net cash flows |
$ | 632,665 | $ | 349,755 | $ | 172,548 | $ | 45,427 | $ | 13,972 | ||||||||||
The following table reconciles our net income (loss) to EBITDA. EBITDA is defined as earnings (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization. Although EBITDA is not a measure of performance calculated in accordance with generally accepted accounting principles (GAAP), management believes that it is useful to an investor in evaluating our company because it is a widely used measure to evaluate a companys operating performance.
Three Months Ended March 31, |
Year Ended December 31, |
|||||||||||||||||||||||||||
2006 |
2005 |
2005 |
2004 |
2003 |
2002 |
2001 |
||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Net income (loss) |
$ | 7,163 | $ | (1,713 | ) | $ | (1,573 | ) | $ | 3,836 | $ | 2,541 | $ | 603 | $ | 3,926 | ||||||||||||
Add: Interest expense (net of amounts capitalized) |
863 | 609 | 3,895 | 986 | 232 | 186 | 151 | |||||||||||||||||||||
Less: Interest income |
(11 | ) | (18 | ) | (77 | ) | (70 | ) | (94 | ) | (119 | ) | (291 | ) | ||||||||||||||
Add (Deduct): Income tax expense (benefit) |
5,652 | (1,106 | ) | (993 | ) | 2,312 | 1,651 | 639 | 1,152 | |||||||||||||||||||
Add: Depreciation, depletion and amortization |
1,834 | 886 | 4,867 | 2,691 | 2,120 | 2,151 | 3,167 | |||||||||||||||||||||
EBITDA |
$ | 15,500 | $ | (1,342 | ) | $ | 6,119 | $ | 9,755 | $ | 6,450 | $ | 3,460 | $ | 8,105 | |||||||||||||
27
MANAGEMENTS DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
The following is a discussion and analysis of our financial condition and results of operations and should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this prospectus.
Overview
We are an independent natural gas producer involved in the exploration, development, and production of natural gas from coal seams (coalbed methane or CBM). Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the Appalachian Basin in West Virginia and Virginia. We control a total of approximately 255,000 net acres of coalbed methane development rights, primarily in Alabama, West Virginia, Virginia, Louisiana, Colorado, and British Columbia.
We have been very active in North America for over twenty years as an operator of CBM fields owned by us, as a contract operator for CBM fields in which we owned an interest, and as a consultant or contract operator for CBM fields owned by other companies. Over the last five years, we have focused on expanding the number of projects that we own and operate. This focus resulted in the initial development of our two primary producing properties, the Gurnee field in the Cahaba Basin and the Pond Creek field in the Appalachian Basin. Additionally, we own and operate several active exploration projects. This change in focus of our operations has also resulted in a significant increase in our business, ranging from capital expenditures to headcount.
Effective April 30, 2004, we acquired the working interests of our 50% partner in the Appalachian Basin, including a 50% working interest in the Pond Creek field, for cash consideration of $27 million and a contingent payment of up to $3 million, which we expect to pay in full in 2008 (the Pond Creek Acquisition). In the acquisition we acquired approximately 31.8 Bcf of estimated proved reserves at a price of $0.84 per Mcf.
Effective June 7, 2004, we sold our 10% working interest in the White Oak Creek field in the Black Warrior Basin for $21 million (the White Oak Creek Sale). We sold approximately 8.4 Bcf of our estimated proved reserves at a price of $2.50 per Mcf while retaining an approximate 3% overriding royalty interest in the field. This overriding royalty interest is presently subject to a dispute. The trial court has ruled in our favor; however, the case is currently under appeal. See BusinessLegal Proceedings for a further discussion of this lawsuit. Prior to 2003 and the start-up of the Pond Creek field, our working and overriding interests in the White Oak Creek field were our primary sources of production, revenue, and cash flow.
On January 30, 2006, we sold 2,067,023 shares of common stock in a private placement to qualified institutional buyers pursuant to Rule 144A under the Securities Act. In connection with this offering, on February 7, 2006, we sold an additional 250,000 shares of our common stock to qualified institutional buyers under Rule 144A under the Securities Act pursuant to the initial purchasers option to purchase additional shares.
The net proceeds from our private placement of common stock during the first quarter of 2006 of approximately $27 million and the receipt of approximately $17.5 million from the repayment of certain stockholder loans and from the exercise of stock options by certain of the selling stockholders were used to reduce outstanding borrowings under our bank credit facility and for general corporate purposes.
Unlike conventional natural gas production operations, in the early stages of a CBM project, production of water is generally comparatively higher and production of gas lower. Typically, gas production from CBM projects gradually increases over time as pressure is lowered due to extraction of water and as additional wells are drilled. As water extraction continues and the maximum number of wells drilled on the project acreage is reached, production peaks and stabilizes for a period and ultimately begins to decline. The length of time that it takes to dewater a particular reservoir before it produces gas and the method to dispose of the water varies.
28
Generally, gas and water are produced simultaneously and the dewatering occurs over time. In other situations, the well will produce only water for a period of time before meaningful gas production begins. At Pond Creek the wells usually produce gas and water simultaneously, while at Gurnee some wells produce only water for 1 to 6 months before meaningful gas production begins. At both projects, certain wells produce only water which helps to dewater the entire reservoir.
The methods used to dispose of the produced water are different for Pond Creek and Gurnee. The produced water at Pond Creek flows from gathering lines into holding tanks where it is trucked and injected into a water disposal well. At Gurnee the produced water flows from gathering lines, is treated and transported by pipeline to a location where it is treated a second time and discharged. The construction of water disposal facilities usually requires significant capital investment in the early phase of the project. As a consequence of these unique CBM characteristics, we may be required to expend substantial capital to develop a CBM field many months before meaningful production and resulting cash flows are realized.
A significant portion of our operating expenses are fixed, generally driven by the number of producing wells, the disposal of produced water, and the cost and maintenance of infrastructure. Over time, as gas production increases and produced water declines, lease operating expenses per unit of production are generally lower. As an example, the per Mcf lease operating expense at the White Oak Creek field, a mature CBM project that reached peak gas production in 2001, was $0.60 for the first five months of 2004 (through the date of the White Oak Creek sale). Conversely, our primary producing properties, Pond Creek and Gurnee, are at much earlier stages in their lifecycles with development operations beginning on June 30, 2002 and December 31, 2003, respectively, and gas sales commencing in February 2003 and January 2004, respectively. The lease operating expense per Mcf for these fields for the year ended December 31, 2005 was $1.43 and $3.55, respectively. The per unit operating expenses for these properties are high relative to White Oak Creek due to their earlier stages of development, but are expected to decline as gas production increases. For the year ended December 31, 2005, sales volumes from the Gurnee and Pond Creek projects accounted for approximately 90% of our total sales volumes. As a result of the concentration of sales volumes in these two projects, our gas revenues, profitability, and cash flows will be primarily dependent on the performance of these projects.
For the three months ended March 31, 2006, gas production increased by 360.3 MMcf from the comparable period in the prior year to 1.4 Bcf. The increase in production was principally related to the continued development of our Cahaba and Pond Creek fields. In addition, average gas sales prices were $9.08 per Mcf, an increase of $2.70 per Mcf from the comparable period in the prior year.
To reduce our exposure to fluctuations in natural gas prices, which have exhibited a high degree of volatility over the past several years, we periodically enter into derivative commodity instruments. Our policy is to enter into hedging transactions which increase our probability of achieving our targeted level of cash flows. As a result of these hedging positions, we had unrealized gains in the amount of $9.1 million for the three months ended March 31, 2006 compared to unrealized losses of $4.8 million in the comparable prior year period.
Our financial results are impacted by many factors such as the price of natural gas, our levels of production, and our ability to market our production. Commodity prices and production volumes are affected by changes in market demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes, future revenues and reserves. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas reserves at economical costs are critical to our long-term success.
We believe that our cash flow from operations and other financial resources such as our credit facility and equity offerings will provide us with the ability to fully develop our existing properties and finance our current exploration on unevaluated properties.
29
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements that have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experiences and various other assumptions that we believe are reasonable; however, actual results may differ. Our significant accounting policies are described in Note 2 to our consolidated financial statements included elsewhere in this prospectus. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements:
Reserves. Our most significant financial estimates are based on estimates of proved gas reserves. Proved gas reserves represent estimated quantities of gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production, and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering, and production data and, the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geologic interpretation, and judgment. In addition, as a result of changing market conditions, commodity prices and future development costs will change from year to year, causing estimates of proved reserves to also change. Estimates of proved reserves are key components of our most significant financial estimates involving our unevaluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. Our reserves are fully engineered on an annual basis by DeGolyer & MacNaughton, our independent petroleum engineers.
Gas Properties. The method of accounting for gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for gas properties. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated into U.S. and Canadian cost centers.
Gas properties are depleted using the unit-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved gas reserves. Estimation of proved gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Holding all other factors constant, if proved gas reserves were revised upward or downward, earnings would increase or decrease, respectively. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of gas properties unless the sale or disposition represents a significant quantity of gas reserves, which would have a significant impact on the depreciation, depletion and amortization rate.
Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the ceiling limitation). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. The ceiling test is imposed separately for our U.S. and Canadian cost centers. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not
30
reversible at a later date. The risk that we will be required to write down the carrying value of our gas properties increases when gas prices are depressed, even if low prices are temporary. In addition, a write-down may occur if estimates of proved gas reserves are substantially reduced or estimates of future development costs increase significantly.
The ceiling test is calculated using natural gas prices in effect as of the balance sheet date and adjusted for basis or location differential, held constant over the life of the reserves. In addition, subsequent to the adoption of SFAS 143, Accounting for Asset Retirement Obligations, the future cash outflows associated with settling asset retirement obligations were not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.
Unevaluated Properties. The costs directly associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairments to unevaluated properties are transferred to the amortization base.
Future Abandonment Costs. We have significant legal obligations to plug, abandon and dismantle existing wells and facilities that we have acquired, constructed, or developed. Liabilities for asset retirement obligations are recorded at fair value in the period incurred. Upon initial recognition of the asset retirement liability, the asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. Asset retirement costs included in the carrying amount of the related asset are subsequently allocated to expense as part of our depletion calculation. Additionally, increases in the discounted asset retirement liability resulting from the passage of time are recorded as lease operating expense.
Estimating the future asset retirement liability requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value. Present value calculations inherently incorporate numerous assumptions and judgments. These include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement liability, a corresponding adjustment will be made to the carrying cost of the related asset.
Price Risk Management Activities. We account for our price risk management activities under the provisions of SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, as amended. We record the fair value of our derivative instruments on our balance sheet as either an asset or liability. The statement requires that changes in the derivatives fair value be recognized currently in the income statement unless specific hedge accounting criteria are met. We have elected not to designate any of our current price risk management activities as accounting hedges, and accordingly, accounted for them using the mark-to-market accounting method. Under this accounting method, the changes in the market value of outstanding financial instruments are recognized as gains or losses which are included in operating expenses in the period of change. Our estimates of fair value are determined by the use of an option-pricing model that is based on various assumptions and factors including the time value of options, volatility and closing NYMEX market indices.
Revenue Recognition. We derive revenue primarily from the sale of produced natural gas. We use the sales method of accounting for the recognition of gas revenue. Because there is a ready market for natural gas, we sell
31
our natural gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title is transferred based on our net revenue interests. Gas sold in production operations is not significantly different from our share of production based on our interest in the properties.
Settlements of gas sales occur after the month in which the gas was produced. We estimate and accrue for the value of these sales using information available at the time financial statements are generated. Differences are reflected in the accounting period that payments are received from the purchaser.
Income Taxes. We record our income taxes using an asset and liability approach in accordance with the provisions of the Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under SFAS No. 109, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Estimating the amount of valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in stockholder ownership that could trigger limits on use of net operating losses under Internal Revenue Code Section 382. We have a significant deferred tax asset associated with net operating loss carryforwards (NOLs). It is more likely than not that we will use these NOLs to offset current tax liabilities in future years.
Future Charges
Public Company Expenses
We believe that our general and administrative expenses will increase in connection with the filing of this registration statement. This increase will consist of legal and accounting fees and additional expenses associated with compliance with the Sarbanes-Oxley Act of 2002 and other regulations. We anticipate that our ongoing general and administrative expenses will also increase as a result of being a publicly traded company. This increase will be due primarily to the cost of accounting support services, filing annual and quarterly reports with the SEC, investor relations, directors fees, directors and officers insurance, and registrar and transfer agent fees. As a result, we believe that our general and administrative expenses for 2006 will increase significantly. Our consolidated financial statements following the completion of this offering will reflect the impact of these increased expenses and affect the comparability of our financial statements with periods prior to the completion of this offering.
Stock Compensation
Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123R, Share-Based Payment (SFAS 123R), using the prospective transition method. Due to the adoption of SFAS 123R, we expect our compensation expense related to the granting of share-based awards subsequent to adoption to be higher than in prior periods. For awards outstanding as of January 1, 2006, we will continue using the accounting principles originally applied to those awards before adoption. Therefore, no equity compensation cost will be recognized on these awards in the future unless such awards are modified, repurchased or cancelled.
Stock-based employee compensation is accounted for under the intrinsic value method of Accounting Principles Bulletin No. 25 Accounting for Stock Issued to Employees. For the years ended December 31, 2005, 2004, and 2003, the exercise price of the options granted was equal to the estimated fair value of our common
32
stock at grant date, and therefore, no compensation costs have been recognized under stock option plans. We used the income method on a semi-annual basis to estimate the market value of our common stock at grant date. As allowed by SFAS No. 123, Accounting for Stock-Based Compensation issued in 1995, we have continued to apply APB Opinion No. 25 for the purpose of determining net income and to present pro forma disclosures required by SFAS No. 123. The table below shows pro forma amounts for what net income would have been if compensation cost had been determined under fair value methods at grant date for stock options granted for the years ended December 31, 2005, 2004 and 2003.
Years Ended December 31, | ||||||||||
2005 |
2004 |
2003 | ||||||||
Net income (loss) as reported |
$ | (1,573,281 | ) | $ | 3,835,781 | $ | 2,541,418 | |||
Less: Total stock-based employee compensation expense determined under fair value based methods for all grants, net of related tax effects |
61,178 | 63,196 | 87,809 | |||||||
Pro forma |
$ | (1,634,459 | ) | $ | 3,772,585 | $ | 2,453,609 | |||
The effects of applying SFAS 123 in this pro forma disclosure may not be representative of future amounts. See Note 9 to our consolidated financial statements included elsewhere in this prospectus for additional detail on stock options. The fair value of each option grant was based on the minimum value method with the following assumptions used for grants for the years ended December 31, 2005, 2004 and 2003: (a) dividend yield of 0%, (b) expected volatility of 0%, (c) risk-free interest rate of 3.4% in 2005, 2.6% in 2004, and 2.5% in 2003, and (d) an expected life of three years for 2005 and 2004, and four years for 2003.
Given the lack of an active public market for our common stock, our compensation committee established the fair value of our common stock for incentive stock option awards based on the recommendation of senior management using the best information available on the date of grant. We used the income method except when there was other, more conclusive evidence of fair value, such as a recent arms-length event or transaction involving the acquisition or exchange of our common stock. Determining the fair value of our common stock required making complex and subjective judgments regarding a number of variables and data points. We used the income method in lieu of other acceptable methods because the income method applies cash flow modeling and assumptions similar to those used in determining the PV-10 of our proved gas reserves. We did not obtain a contemporaneous valuation by an unrelated valuation specialist for the options granted during 2005 because we believed that both our senior management and the management of our majority stockholder had adequate expertise and experience in valuing gas properties and entities with gas exploration, production, and development activities. We believe our methodology and valuations represented the estimated fair value of our common stock at that time.
Information on stock option grants during the year ended December 31, 2005 is summarized as follows:
Date of Issuance |
Type of equity issuance |
Number of options granted |
Exercise price |
Fair market |
Intrinsic value per share | |||||
January 24, 2005 |
Employee Options | 65,244 | $6.98 | $6.98 | $ | |||||
June 1, 2005 |
Employee Options | 88,000 | 7.64 | 7.64 | |
Significant Factors, Assumptions, and Methodologies Used in Determining Fair Value.
Factors considered by our compensation committee in establishing the fair value of our common stock at the various grant dates included the following:
| the most recent valuation of our estimated proved natural gas reserves prepared by independent reservoir engineers; |
| the future price of natural gas; |
33
| the relative risks associated with estimating production and costs from different categories of reserves; |
| the discount factor used to approximate the time value of money; |
| the significant uncertainty surrounding the determination of estimated quantities of natural gas reserves; |
| the valuation of other assets and liabilities; |
| arms-length transactions involving our common stock; and |
| general industry and economic trends. |
Significant Factors Contributing to the Difference between Fair Value as of the Date of Each Grant and the Price that Selling Stockholders Will Obtain From the Sale of Their Shares.
As set forth in the table above, we granted stock options with exercise prices ranging from $6.98 to $7.64 during the year ended December 31, 2005. The reasons for the difference between the exercise price range of $6.98 and $7.64 and the estimated selling range included in this offering are as follows:
| Increases in the spot and futures price of natural gas used to determine the value of our natural gas reserves. Average well head gas prices increased $0.14 per Mcf, or 2.3%, from $6.01 per Mcf at December 31, 2004 to $6.15 per Mcf at June 30, 2005. Gas prices further increased $3.87 per Mcf, or 62.9%, from June 30, 2005 to $10.02 per Mcf at December 31, 2005; |
| Increases in the quantities of proved reserves owned by us and increases in the level of daily production volume resulting from our ongoing successful drilling program at Gurnee and Pond Creek. Quantities of proved reserves increased 13 Bcf, or 6.2%, from 210 Bcf at December 31, 2004 to 213 Bcf at June 30, 2005. Quantities of proved reserves further increased 50 Bcf, or 23.5%, from June 30, 2005 to 263 Bcf at December 31, 2005; and |
| Increases in the market values of successful publicly traded exploration and production companies. Indices for oil and gas stock prices increased 87.14 points, or 29.3%, from 297.42 at December 2004 to 384.56 at June 2005. Indices for oil and gas stock prices further increased 66.22 points, or 17.2 %, from June 2005 to 450.78 at December 2005. |
Derivative Instruments
Due to the historical volatility of natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of prices we receive for our production. Currently, we use collars and fixed-price swaps as our mechanism for hedging commodity prices. We have elected not to designate any of our current derivative instruments as hedges for accounting purposes in accordance with SFAS No. 133Derivative Instruments and Hedging Activities. As a result, we account for our derivative instruments on a mark-to-market basis, and changes in the fair value of derivative instruments are recognized as gains and losses which are included in operating expense in the period of change. While we believe that the stabilization of prices and protection afforded us by providing a revenue floor for our production is beneficial, this strategy may result in lower revenues than we would have if we were not a party to derivative instruments in times of rising natural gas prices. As a result of rising commodity prices, we recognized total losses on derivative contracts for the year ended December 31, 2005 of approximately $19.5 million. If commodity prices increase, we may recognize additional charges in future periods; however, for the three months ended March 31, 2006 prices decreased, and we recognized a total gain on derivative contracts in the amount of $8.5 million, consisting of a $0.6 million realized loss and a $9.1 million unrealized gain.
34
Producing Field Operations Summary
The table below presents information on gas revenues, sales volumes, production expenses and per Mcf data for the three months ended March 31, 2006 and 2005 and for the years ended December 31, 2005, 2004 and 2003. This table should be read with the discussion of the results of operations for the periods presented below.
Three Months Ended March 31, |
Year Ended December 31, | ||||||||||||||
2006 |
2005 |
2005 |
2004 |
2003 | |||||||||||
(In thousands except per Mcf) | |||||||||||||||
Gas sales |
$ | 12,311 | $ | 6,369 | $ | 41,604 | $ | 19,522 | $ | 11,700 | |||||
Lease operating expenses |
$ | 2,841 | $ | 2,083 | $ | 8,687 | $ | 5,092 | $ | 1,640 | |||||
Compression and transportation expenses |
1,076 | 721 | 3,332 | 1,951 | 993 | ||||||||||
Production taxes |
269 | 126 | 914 | 473 | 414 | ||||||||||
Total production expenses |
$ | 4,186 | $ | 2,930 | $ | 12,933 | $ | 7,516 | $ | 3,047 | |||||
Net sales volumes (MMcf) |
1,356 | 996 | 4,594 | 3,187 | 2,484 | ||||||||||
Per Mcf data ($/Mcf): |
|||||||||||||||
Average natural gas sales price |
$ | 9.08 | $ | 6.38 | $ | 9.06 | $ | 6.12 | $ | 4.71 | |||||
Average natural gas sales price realized(1) |
$ | 8.64 | $ | 6.56 | $ | 7.43 | $ | 5.87 | $ | 4.69 | |||||
Lease operating expenses |
$ | 2.09 | $ | 2.09 | $ | 1.89 | $ | 1.60 | $ | 0.66 | |||||
Compression and transportation expenses |
$ | 0.79 | $ | 0.72 | $ | 0.72 | $ | 0.61 | $ | 0.40 | |||||
Production taxes |
$ | 0.21 | $ | 0.13 | $ | 0.20 | $ | 0.15 | $ | 0.17 | |||||
Total production expenses |
$ | 3.09 | $ | 2.94 | $ | 2.81 | $ | 2.36 | $ | 1.23 |
(1) | Average realized price includes the effects of realized losses on derivative contracts. |
35
Results of Operations
Three Months Ended March 31, 2006 compared with Three Months Ended March 31, 2005
The following is a discussion of significant matters affecting the operating and financial results for the three months ended March 31, 2006 compared to the three months ended March 31, 2005.
Selected items presented in our Consolidated Statement of Operations and Comprehensive Income on page F-29 and their percentage changes from the comparable period are presented below.
Three Months Ended March 31, |
|||||||||||
2006 |
2005 |
Change |
|||||||||
(In thousands) | |||||||||||
Gas sales |
$ | 12,311 | $ | 6,369 | 93 | % | |||||
Operating fees and other |
| 138 | (100 | )% | |||||||
Total revenues |
$ | 12,311 | $ | 6,507 | 89 | % | |||||
Lease operating expenses |
$ | 2,841 | $ | 2,083 | 36 | % | |||||
Compression and transportation expenses |
1,076 | 721 | 49 | % | |||||||
Production taxes |
269 | 126 | 113 | % | |||||||
Depreciation, depletion and amortization |
1,834 | 885 | 107 | % | |||||||
Research and development |
69 | 1 | 680 | % | |||||||
General and administrative |
1,020 | 751 | 36 | % | |||||||
Realized losses (gains) on derivative contracts |
596 | (165 | ) | 461 | % | ||||||
Unrealized losses (gains) from the change in market value of open derivative contracts |
(9,074 | ) | 4,839 | (288 | )% | ||||||
Total operating expenses |
$ | (1,369 | ) | $ | 9,241 | (115 | )% | ||||
Interest expense (net of amounts capitalized) |
$ | (863 | ) | $ | (609 | ) | 42 | % | |||
Income (loss) before income taxes and minority interest, net of income tax |
$ | 12,815 | $ | (3,326 | ) | 485 | % | ||||
Income tax expense (benefit) |
5,652 | (1,106 | ) | 611 | % | ||||||
Net income (loss) before minority interest, net of income tax |
$ | 7,163 | $ | (2,220 | ) | 423 | % | ||||
Gas sales. Gas sales increased by $5.9 million, or 93%, to $12.3 million compared to the prior year quarter. The increase in gas sales was a result of increased production and average gas prices. Production increased 36% while average gas prices excluding hedging transactions increased 42%. The $5.9 million increase in gas sales consisted of a $3.6 million increase in prices and a $2.3 million increase in production. The increase in production was principally attributable to our Cahaba and Pond Creek development activities.
Lease operating expenses. Lease operating expenses increased by $0.758 million, or 36% to $2.8 million. The increase in lease operating expenses was primarily a result of increased production as the unit costs per Mcf remained fairly flat.
Compression and transportation expenses. Compression and transportation expenses increased by $0.355 million, or 49% to $1.1 million. The $0.355 million increase in compression and transportation expenses consisted of a $0.261 million increase in production and a $0.094 million increase in costs. The increase in cost per Mcf was a result of additional compressors and increases in transportation fees to support the increase in production levels.
Production taxes. Production taxes increased by $0.143 million, or 114%, to $0.269 million. The production taxes increase of $0.143 million consisted of a $0.097 million increase in costs and a $0.046 million increase in production. The increase in production taxes was a result of increased production and the increase in costs was a result of reduced tax exemptions at certain fields.
36
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $0.949 million, or 107%, to $1.8 million. The depreciation, depletion and amortization increase of $0.949 million consisted of a $0.629 million increase in depletion rate and a $0.320 million increase in production. The increase in the depletion rate was primarily due to $48.0 million added to the net book value of gas properties due to a purchase accounting adjustment related to the acquisition of the minority interest stock in a subsidiary and, to a lesser extent, a downward reserve revisions at Cahaba and increased drilling and completion costs.
General and administrative. General and administrative expenses increased by $0.269 million or, 36%, to $1.0 million. The increase in general and administrative expenses was a result of increases in employee expenses (13%), professional services (58%), director expenses (12%), office expenses and business taxes (34%). This increase was partially offset by increased capitalized general and administrative expenses (46%) and field and operating overhead recoveries (54%). The largest increase was in professional services that resulted from the increased audit, tax and legal services. The increase in general and administrative expenses was a result of expanding the overhead structure to support our growth and the increased costs of preparing to be a public company.
Realized losses on derivative contracts. Realized losses on derivative contracts increased by $0.761 million to $0.596 million compared to a gain of $0.165 million in the prior corresponding period. Realized losses represent net cash flow settlements paid to the counterparty while realized gains represent net cash flow settlement paid to us from the counterparty. Realized losses occur when commodity gas prices or the derivative index price exceeds the derivative ceiling price. Conversely, realized gains occur when commodity gas prices go below the derivative floor price.
Unrealized losses (gains) from the change in market value of open derivative contracts. Unrealized losses (gains) from the change in market value of open derivative contracts generated a $9.1 million gain as compared to a $5.0 million loss in the comparable period in 2005. Unrealized losses and gains are non-cash transactions that occur when the corresponding asset or liability derivative contracts are marked to market at the end of each reporting period. Unrealized gains are recognized when the fair values of derivative assets increase or the fair value of derivative liabilities decrease. Unrealized losses are recognized when the fair values of derivative assets decrease or the fair value of derivative liabilities increase. The $9.1 million gain is a result of decreased commodity gas prices.
Interest expense (net of amounts capitalized). Interest expense (net of amounts capitalized) increased by $0.254 million, or 42%, to $0.863 million. The increase was primarily due to higher outstanding bank balances and higher interest rates. The increase in interest expense was partially offset by capitalizing the interest expense to our gas properties.
Income tax expense (benefit). Income tax expense (benefit) resulted in expense of $5.7 million in the first quarter of 2006 compared to a benefit of $1.1 million in the comparable prior period in 2005. The increase in income tax expense in the current quarter was due to (1) the pretax income position versus a pretax loss position in the comparable prior period and (2) an increase in the effective tax rate for the current quarter to 44% from 33.2% in the comparable prior period as a result of certain state taxes not previously included in prior periods and the related cumulative non-cash adjustment of $0.406 million. Excluding the state tax revision, the revised estimated effective tax rate for the year is expected to be approximately 40.1%.
37
Year Ended December 31, 2005 compared with Year Ended December 31, 2004
The following is a discussion of significant matters affecting the operating and financial results for the year ended December 31, 2005 compared to the year ended December 31, 2004. Significant changes in sales volumes at our major properties and the White Oak Creek Sale and the Pond Creek Acquisition, which occurred in 2004 and were discussed in detail in the Overview, result in the periods not being comparable.
Selected items presented in our Consolidated Statement of Operations and Comprehensive Income on page F-4 and their percentage changes from the comparable period are presented in the table below:
Years Ended December 31, |
Percentage Change |
||||||||||
2005 |
2004 |
||||||||||
(In thousands) | |||||||||||
Gas sales |
$ | 41,604 | $ | 19,522 | 113 | % | |||||
Operating fees and other |
376 | 1,402 | (73 | )% | |||||||
Total revenues |
$ | 41,980 | $ | 20,924 | 101 | % | |||||
Lease operating expenses |
$ | 8,687 | $ | 5,092 | 71 | % | |||||
Compression and transportation expenses |
3,332 | 1,951 | 71 | % | |||||||
Production taxes |
914 | 473 | 93 | % | |||||||
Depreciation, depletion and amortization |
4,867 | 2,691 | 81 | % | |||||||
Research and development |
609 | 279 | 119 | % | |||||||
General and administrative |
3,208 | 2,513 | 28 | % | |||||||
Realized losses on derivative contracts |
7,473 | 815 | 817 | % | |||||||
Unrealized losses (gains) from the change in market value of open derivative contracts |
12,059 | (542 | ) | 2,325 | % | ||||||
Total operating expenses |
$ | 41,149 | $ | 13,272 | 210 | % | |||||
Interest expense (net of amounts capitalized) |
$ | (3,895 | ) | $ | (986 | ) | 295 | % | |||
Income (loss) before income taxes, minority interest, and cumulative effect of change in accounting principle, net of income tax |
$ | (3,008 | ) | $ | 6,732 | (145 | )% | ||||
Income tax provision |
(993 | ) | 2,312 | (143 | )% | ||||||
Net income (loss) before minority interest and cumulative effect of change in accounting principle, net of income tax |
$ | (2,015 | ) | $ | 4,420 | (146 | )% | ||||
Sales volumes. Increases in wells coming on line from the ongoing drilling program and the Pond Creek Acquisition, offset partially by the White Oak Creek Sale and normal production declines, resulted in a 44% increase in sales volumes to 4.6 Bcf from 3.2 Bcf. Total net productive wells increased 42% to 313 from 220.
Gas sales. Increases in gas prices and sales volumes resulted in an 113% increase in gas sales to $41.6 million from $19.5 million. Gas prices increased 48% to $9.06 per Mcf from $6.12 per Mcf before the effects of hedges.
Operating fees and other. A $0.8 million cash settlement from a previous joint venture partner in the prior period and a $0.29 million decrease in operating fees from the termination of contract operations resulted in a 73% decrease in operating fees and other.
Lease operating expenses. An increase in unit costs and higher sales volumes resulted in a 71% increase in lease operating expenses to $8.7 million from $5.1 million. Lease operating expenses per Mcf increased 18% to $1.89 from $1.60. The increase in per unit lease operating expenses was primarily due to a change in the sales
38
volume mix, which is weighted more to early stage projects with higher per unit lease operating expenses in 2005 as compared to mature projects with lower per unit lease operating expenses in 2004. The White Oak Creek Sale was the sale of a mature project with significantly lower per unit lease operating expenses than the overall per unit lease operating expenses.
Compression and transportation expenses. An increase in unit expenses and higher sales volumes at Pond Creek resulted in a 71% increase in compression and transportation expenses to $3.3 million from $2.0 million. Compression and transportation expenses per Mcf increased 18% to $0.72 from $0.61. The increase in per unit compression and transportation expenses was primarily due to the additions of compressors to handle the increase in sales volumes and increases in firm transportation fees at Pond Creek. There are no transportation expenses at Cahaba.
Production taxes. Increases in gas sales resulted in a 93% increase in production taxes to $0.9 million from $0.5 million. A significant portion of Pond Creek sales volumes is exempt from production taxes for five years from date of first production because of a West Virginia tax exemption.
Depreciation, depletion and amortization. A 31% increase in the depletion rate for gas reserves to $1.02 from $0.78 combined with a 44% increase in sales volumes caused depreciation, depletion and amortization to increase 81% to $4.9 million from $2.7 million. The increase in the depletion rate was primarily due to a $48 million increase in the net book value of gas properties due to a purchase accounting adjustment related to the acquisition of the minority interest stock in a subsidiary, and to a lesser extent downward reserve revisions at Cahaba and increased drilling and completion costs. The depletion rate is generally calculated by dividing the net book value of gas properties by total proved reserves.
General and administrative. Increases in employee expenses, office expenses, and business taxes, resulted in a 28% increase in general and administrative to $3.2 million from $2.5 million. An increase in the number of employees due to increased activity levels, increases in salaries and bonuses of employees, and a $0.15 million one-time payment to certain executives associated with the subsidiary merger increased employee expenses. Office expenses increased due to increased rent expense and office supplies expense. Business taxes increased due to increased franchise taxes caused by increased capital subject to tax. General and administrative recoveries, reclassification and capitalized items was $5.4 million for 2005 and 2004. General and administrative recoveries, reclassifications and capitalized items primarily consist of capitalized general and administrative costs related to exploration and development activities and the reclassification of costs related to field employees involved in production activities.
Realized losses on derivative contracts. Increases in gas prices during the year ended December 31, 2005, combined with increases in the nominal volume of derivative contracts that settled during the year, caused the realized losses on derivative contracts to increase 817% to $7.5 million from $0.8 million. We enter into various gas swap and three-way collar transactions from time to time that are not designated as accounting hedges. Realized losses represent the net cash settlements paid to the derivative counterparty during the year. The realized losses are recorded in total operating expenses in the Consolidated Statement of Operations and Comprehensive Income.
Unrealized losses (gains) from the change in market value of open derivative contracts. The change in the market value of open derivative contracts during the year ending December 31, 2005 resulted in a 2,325% change to an unrealized loss of $12.1 million from an unrealized gain of $0.5 million. Increases in gas prices during the year and in the nominal volume of outstanding derivative contracts contributed to the unrealized losses. We enter into various gas swap and three-way collar transactions from time to time that are not designated as accounting hedges. Under this accounting treatment, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the income statement in the period of change. The gains and losses are recorded in total operating expenses in the Consolidated Statement of Operations and Comprehensive Income.
39
Interest expense (net of amounts capitalized). Higher average levels of debt outstanding and higher borrowing rates on the credit facility caused interest expense (net of amounts capitalized ) to increase 295% to $3.9 million from $1.0 million. Capitalized interest in 2005 and 2004 was $0.7 million and $0.1 million, respectively.
Income tax provision. Our income tax provision includes both state and federal taxes. Our state taxes are an insignificant portion of our income tax provision. The 143% decrease in our income tax provision to a benefit of $1.0 million from an expense of $2.3 million corresponds to the net loss in 2005 from net income for the comparable year. The effective rate in 2005 was 33% compared to 34% for 2004.
Year Ended December 31, 2004 compared with Year Ended December 31, 2003
The following is a discussion of significant matters affecting the operating and financial results for the year ended December 31, 2004 compared to the year ended December 31, 2003. Significant changes in sales volumes at our major properties and the White Oak Creek Sale and the Pond Creek Acquisition, which occurred in 2004 and were discussed in detail in the Overview, result in the periods not being comparable.
Selected items presented in the Consolidated Statement of Operations and Comprehensive Income on page F-4 and their percentage changes from the comparable period are presented in the table below:
Year Ended December 31, |
Percentage Change |
||||||||||
2004 |
2003 |
||||||||||
(In thousands) | |||||||||||
Gas sales |
$ | 19,522 | $ | 11,700 | 67 | % | |||||
Operating fees and other |
1,402 | 349 | 302 | % | |||||||
Total revenues |
$ | 20,924 | $ | 12,049 | 74 | % | |||||
Lease operating expenses |
$ | 5,092 | $ | 1,640 | 210 | % | |||||
Compression and transportation expenses |
1,951 | 993 | 96 | % | |||||||
Production taxes |
473 | 414 | 14 | % | |||||||
Depreciation, depletion and amortization |
2,691 | 2,120 | 27 | % | |||||||
Research and development |
279 | 432 | (35 | )% | |||||||
General and administrative |
2,513 | 1,370 | 83 | % | |||||||
Impairment |
| 8 | 100 | % | |||||||
Realized losses on derivative contracts |
815 | 44 | 1,752 | % | |||||||
Unrealized losses (gains) from the change in market value of open derivative contracts |
(542 | ) | 102 | 631 | % | ||||||
Total operating expenses |
$ | 13,272 | $ | 7,123 | 86 | % | |||||
Interest expense (net of amounts capitalized) |
$ | (986 | ) | $ | (232 | ) | 325 | % | |||
Income before income taxes, minority interest, and cumulative effect of change in accounting principle, net of income tax |
$ | 6,732 | $ | 4,782 | 41 | % | |||||
Income tax provision |
2,312 | 1,651 | 40 | % | |||||||
Net income before minority interest, and cumulative effect of change in accounting principle, net of income tax |
$ | 4,420 | $ | 3,131 | 41 | % | |||||
Sales volumes. Increases in wells coming on line from the ongoing drilling program at Pond Creek, the beginning of development at Cahaba and the Pond Creek Acquisition, offset partially by the White Oak Creek Sale and normal production declines, resulted in a 28% increase in sales volumes to 3.2 Bcf from 2.5 Bcf. Total net productive wells increased 96% to 220 from 112.
40
Gas sales. Increases in gas prices and sales volumes resulted in a 67% increase in gas sales to $19.5 million from $11.7 million. Gas prices increased 30% to $6.12 per Mcf from $4.71 per Mcf before the effects of hedges. The sales price per Mcf in 2003 was reduced by the forward sale of 3,000 MMBtu/day of gas produced from White Oak Creek at a set price of $4.00/MMBtu for the period January 1, 2003 to December 31, 2003.
Operating fees and other. A $0.8 million White Oak Creek joint interest audit settlement and a $0.2 million increase in contract operating fees, primarily increased operating fees and other by $1.1 million to $1.4 million in 2004 from $0.3 million in 2003.
Lease operating expenses. An increase in unit expenses and higher sales volumes resulted in a 210% increase in lease operating expenses to $5.1 million from $1.6 million. Lease operating expenses per Mcf increased 142% to $1.60 from $0.66. The increase in per unit lease operating expenses was primarily due to a change in the sales volume mix which is weighted more to early stage projects with higher per unit operating costs in the 2004 period as compared to mature projects with lower per unit operating expenses in the comparable period. The White Oak Creek Sale was the sale of a mature project with significantly lower per unit lease operating expenses than the overall per unit lease operating expenses.
Compression and transportation expenses. An increase in unit expenses and higher sales volumes at Pond Creek resulted in a 96% increase in compression and transportation expenses to $2.0 million from $1.0 million. Compression and transportation expenses per Mcf increased 53% to $0.61 from $0.40. The increase in per unit compression and transportation expenses was primarily due to the addition of compressors to handle the increase in sales volumes. There are no transportation expenses at Cahaba. The White Oak Creek Sale was the sale of a mature project with significantly lower per unit compression and transportation expenses than the overall per unit compression and transportation expenses.
Production taxes. Increases in gas sales resulted in a 14% increase in production taxes to $0.5 million from $0.4 million. All of Pond Creeks production in 2004 and 2003 was exempt from production taxes because the producing wells are located in West Virginia which has a production tax exemption for five years from the date of first production.
Depreciation, depletion and amortization. Increases in sales volumes and a 2.5% increase in the depletion rate to $0.80 per Mcf from $0.78 per Mcf caused depreciation, depletion and amortization to increase 27% to $2.7 million from $2.1 million. The Pond Creek Acquisition added 31.8 Bcf of proved reserves at a cost of $27 million or $0.85 per Mcf of proved reserves. The White Oak Creek Sale reduced the net book value of properties by $21 million and reduced proved reserves by 8.4 Bcf. The depletion rate is generally calculated by dividing the net book value of gas properties by total proved reserves.
General and administrative. Increases in employee expenses, professional fees and business taxes, partially offset by an increase in recoveries, reclassifications and capitalized items, resulted in an 83% increase in general and administrative to $2.5 million from $1.4 million. The hiring of additional employees due to the increase in activity levels and higher salary levels increased gross employee expenses approximately $0.9 million and a title dispute increased legal fees approximately $0.3 million. General and administrative recoveries, reclassifications and capitalized items in 2004 and 2003 were $5.4 million and $5.1 million, respectively. General and administrative recoveries, reclassifications and capitalized items primarily consist of capitalized general and administrative costs related to exploration and development activities and the reclassification of costs related to field employees involved in production activities.
Realized losses on commodity derivative contracts. Increases in gas prices during the year, combined with increases in the nominal volume of derivative contracts that settled during the year, caused the realized losses on derivative contracts to increase 1,752% to $0.8 million from $0.04 million. We enter into various gas swap and three-way collar transactions from time to time that are not designated as accounting hedges. Realized losses
41
represent the net cash settlements paid to the derivative counterparty during the year. The realized losses are recorded in total operating expenses in the Consolidated Statement of Operations and Comprehensive Income.
Unrealized losses (gains) from the change in market value of open derivative contracts. The change in the market value of open derivative contracts for the year resulted in an unrealized gain of $0.5 million from a loss of $0.1 million in the comparable period. Decreases in gas prices during the period and an increase in the nominal volume of outstanding derivative contracts contributed to the decrease in unrealized losses. We enter into various gas swap and three-way collar transactions from time to time that are not designated as accounting hedges. Under this accounting treatment, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the income statement in the period of change. The gains and losses are recorded in total operating expenses in the Consolidated Statement of Operations and Comprehensive Income.
Interest expense (net of amounts capitalized). Increased average debt levels and higher borrowing rates on the credit facility caused interest expense (net of amounts capitalized) to increase 325% to $1.0 million from $0.2 million during the period. Capitalized interest in 2004 and 2003 was $0.1 million and $0.1 million, respectively.
Income tax provision. Our income tax provision includes both state and federal taxes. Our state taxes are an insignificant portion of our income tax provision. The 40% increase in our income tax provision to $2.3 million from $1.7 million corresponds to the increase in net income before tax in 2004. The effective rate in 2004 and comparable period remained at approximately 34%.
Liquidity and Capital Resources
Cash Flows and Liquidity
Cash flow from operations for the three months ending March 31, 2006 and 2005 were $10.5 million and $2.3 million, respectively. Cash flow from operations for the three months ended March 31, 2006 of $10.5 combined together with net proceeds of the private offering of $27.6 million and proceeds from the collection of notes receivable of $17.2 were sufficient to fund our capital expenditures of $13.4 million and the repayment of our revolving credit facility and other debt of $41.5 million.
As of March 31, 2006 and December 31, 2005, we had a working capital deficit of approximately $8.4 million and $7.1 million, respectively. The increase in the working capital deficit was primarily a result of decreased accounts receivable and increased accounts payable. This increase in the deficit was partially offset by increased cash and cash equivalents and decreased net derivative liabilities. At March 31, 2006, we had adequate cash flows from operating activities and adequate credit availability to fund our working capital deficits.
The development of CBM fields requires substantial initial investment before meaningful production and resulting cash flows are realized. Among the factors that can be expected to affect our cash flows and liquidity are the characteristics of the field, the amount of water produced, the methods utilized to dispose of produced water, and the timing and volume of initial and subsequent natural gas production. We estimate total capital expenditures in 2006 will be approximately $90 million with approximately 80% allocated to development projects, 12% to exploration projects, 4% to leasehold acquisitions and the remaining 4% for other items (primarily capitalized overhead and interest and administrative capital expenditures), representing an increase of approximately $30 million over our actual 2005 capital expenditures. The increase is primarily attributable to increased development expenditures at Pond Creek and Cahaba. As of March 31, 2006 we have approximately $62 million of available borrowing capacity under our revolving credit facility.
Based upon current expectations, we believe that we will have adequate resources from cash flows from operations, and from proceeds from credit facility borrowing and this offering to fund our 2006 capital expenditures and other working capital needs.
If natural gas commodity prices decrease from their current levels for an extended period, our ability to finance our planned capital expenditures could be affected negatively. Furthermore, amounts available for
42
borrowing under our revolving credit facility are largely dependent on our level of estimated proved reserves and current natural gas prices. If either our estimated proved reserves or natural gas prices decrease, amounts available to us to borrow under our revolving credit facility could be negatively affected. If our cash flows are less than anticipated, amounts available for borrowing under our revolving credit facility are reduced or we are unable to sell equity at acceptable prices, we may be forced to defer planned capital expenditures.
Price Risk Management Activities
The energy markets have historically been very volatile, and there can be no assurance that gas prices will not be subject to wide fluctuations in the future. In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has adopted a policy of hedging natural gas prices from time to time primarily through the use of commodity price swap agreements and costless collar arrangements. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.
We enter into hedging transactions that increase our statistical probability of achieving our targeted level of cash flows. We have at times hedged forward for periods up to two years. We generally limit the amount of these hedges to no more than 50% to 60% of the then expected gas production for such future period. We have historically used swaps, costless collars and three-way costless collars in our hedging activities. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling and a minimum floor future price. Three-way costless collars are similar to regular costless collars except that, in order to increase the ceiling price, we agree to limit the amount of the floor price protection to a predetermined amount, generally between $1.00 and $1.50 per MMBtu. Currently, our hedge strategy favors the use of three-way collars that allow us to retain more price upside. We have not designated any of our price risk management activities as accounting hedges and, therefore, have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses during periods where prices rise above the level of our hedges and gains during periods where prices drop below the level of our hedges. Until 2005, the impact of this method of accounting was not significant; however, the significant increase in gas prices in 2005, particularly in the third quarter in response to Hurricanes Katrina and Rita, resulted in approximately $19.5 million in hedging losses for the year ended December 31, 2005. A total of $12.1 million of such losses were unrealized at December 31, 2005 and had no impact on cash flows.
We believe that the use of derivative instruments does not expose us to material risk. However, the use of derivative instruments could materially affect our results of operations depending on the future prices of natural gas. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity. For a summary of accounting policies related to derivative instruments, see Note 2 to our consolidated financial statements included elsewhere in this prospectus.
As indicated above, we have elected not to designate any of our current derivative contracts as accounting hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and accordingly, accounted for our derivative contracts using mark-to-market accounting. During the three months ended March 31, 2006, we recognized gains on derivative contracts of $8.478 million, which included realized losses of $0.596 million. During the three months ended March 31, 2005, we recognized losses on derivative contracts of $4.674 million, which included realized gains of $0.165 million.
As of March 31, 2006, the following natural gas derivative contracts were outstanding with prices expressed in dollars per million British thermal units ($/MMBtu) and notional volumes in million British thermal units.
Instrument Type |
Production Period |
Volumes (MMBtu) |
Weighted Average Floor ($/MMBtu) |
Cap ($/MMBtu) | ||||||
Collars (3 way) |
April 1December 31, 2006 | 3,178,000 | $ | 6.037.23 | $ | 8.98 | ||||
Collars (3 way) |
January 1October 31, 2007 | 1,756,000 | $ | 6.607.98 | $ | 10.28 |
43
At March 31, 2006 and at December 31, 2005, the fair values of open derivative contracts were liabilities of approximately $2.5 million and $11.5 million, respectively.
Sensitivity analyses of the incremental effects on pre-tax gain for the three months ended March 31, 2006 of a hypothetical 10% and 25% change in natural gas prices for outstanding hedge contracts as of March 31, 2006 are provided in the following table:
Incremental (Increase)/ Decrease in pre-tax gain assuming a hypothetical price increase and decrease of(1): |
||||||||
10% |
25% |
|||||||
(In thousands) | ||||||||
Price increase |
$ | (2,315 | ) | $ | (6,707 | ) | ||
Price decrease |
$ | 1,910 | $ | 4,409 |
(1) | We remain at risk for possible changes in the market value of these derivative contracts; however, any unfavorable increases would be partly offset by higher revenues due to higher sales prices for our gas. The favorable effect of this offset is not reflected in the sensitivity analyses. |
We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our credit agreement and the collateral for the outstanding borrowings under our credit agreement is used as collateral for our hedges.
Capital Expenditures and Capital Resources
Year Ended December 31, | |||||||||
2005 |
2004 |
2003 | |||||||
(In thousands) | |||||||||
Capital expenditures: |
|||||||||
Leasehold acquisition |
$ | 2,012 | $ | 1,571 | $ | 2,109 | |||
Exploration |
8,620 | 6,759 | 17,374 | ||||||
Development |
46,397 | 49,023 | 14,623 | ||||||
Acquisitions |
| 27,046 | | ||||||
Other items (primarily capitalized overhead and interest) |
2,173 | 1,790 | 1,963 | ||||||
Total capital expenditures |
$ | 59,202 | $ | 86,189 | $ | 36,069 | |||
Our capital expenditures for the year ending December 31, 2005 were approximately equal to the comparable 2004 period, exclusive of the Pond Creek Acquisition. Development expenditures declined slightly due to a decrease in Gurnee field spending partially offset by increased spending at Pond Creek. Exploration spending increased due primarily to Peace River project expenditures. Our capital expenditures for 2004, exclusive of the Pond Creek Acquisition and the White Oak Creek Sale, increased approximately 62% compared to 2003 as a result of increased development expenditures at the Gurnee field.
Credit Facility
In June 2006, we entered into a $180 million amended and restated credit agreement with Bank of America, N.A., as agent, and other lenders. Availability under the amended credit agreement is subject to a borrowing base, which is currently set at $150 million. The borrowing base is subject to semi-annual redeterminations. The lenders also have the right to require one additional redetermination in any fiscal year. The amended credit agreement provides for interest to accrue at a rate calculated, at our option, at either the adjusted base rate (which is the greater of the agents base rate or the federal funds rate plus one half of one percent) or the London Interbank Offered Rate (LIBOR) plus a margin of 1.00% to 2.00% based on borrowing base usage. Borrowings under the amended credit agreement are secured by first priority liens on substantially all of our assets including
44
equity interests in our subsidiaries. All outstanding borrowings under the amended credit agreement become due and payable on January 6, 2011.
We are subject to financial covenants requiring maintenance of a minimum current ratio and a minimum interest coverage ratio. Our ratio of consolidated current assets (defined to include amounts available under our borrowing base) to our consolidated current liabilities is not permitted to be less than 1 to 1 as of the end of any fiscal quarter, and our ratio of consolidated EBITDA for the four preceding quarters at the end of each fiscal quarter to the sum of our consolidated net interest expense for the preceding four quarters period plus letter of credit fees accruing during such quarter is not permitted to be less than 2.75 to 1. Consolidated EBITDA as defined in the amended credit agreement excludes other non-cash charges deducted in determining net income (loss), which would include unrealized losses from the change in the market value of open derivative contracts. In addition, we are subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. A breach of any of the covenants imposed on us by the terms of our credit facility, including the financial covenants, could result in a default under such indebtedness. In the event of a default, the lenders could terminate their commitments to us, and they could accelerate the repayment of all of our indebtedness. In such case, we may not have sufficient funds to pay the total amount of accelerated obligations, and our lenders could proceed against the collateral securing the facility. Any acceleration in the repayment of our indebtedness or related foreclosure could adversely affect our business.
In addition, the borrowing base under our credit facility is redetermined semi-annually and may also be redetermined once each fiscal year for any reason upon request by lenders representing 66.66% of the total commitment under our credit facility. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. The next scheduled redetermination is to occur as of June 30, 2006. Upon a redetermination, we could be required to repay a portion of our bank debt. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the credit facility and an acceleration of our indebtedness.
At March 31, 2006, $57.5 million was outstanding under our credit facility. Interest on the borrowings averaged 6.59% per annum. All of the debt outstanding under our credit facility accrues interest at floating or market rates. Fluctuations in market interest rates will cause our interest costs to fluctuate. Based upon the balance outstanding under our credit facility at March 31, 2006, a 1% change in market interest rates would have increased interest expense and negatively impacted our annual cash flows by approximately $575,000.
At March 31, 2006, we did not have any hedges in place to reduce our risk to increases in interest rates.
Contractual Commitments
We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. The following table summarizes these commitments at December 31, 2005:
Beginning January 1, 2006(1) | |||||||||||||||
One Year |
2-4 Years |
5-6 Years |
More than 6 Years |
Total | |||||||||||
(In thousands) | |||||||||||||||
Long-term debt and other obligations(2) |
$ | 86 | $ | 309 | $ | 99,618 | $ | | $ | 100,013 | |||||
Interest expense on bank credit facility(3) |
5,762 | 17,287 | 5,841 | | 28,890 | ||||||||||
Operating lease obligations |
1,185 | 3,059 | 1,283 | 210 | 5,737 | ||||||||||
Asset retirement obligations |
52 | | | 1,838 | 1,890 | ||||||||||
Derivative liability |
8,932 | 2,612 | | | 11,544 | ||||||||||
Firm transportation contracts |
1,100 | 1,506 | 418 | | 3,024 | ||||||||||
Other operating commitments |
1,067 | 530 | | | 1,597 | ||||||||||
Total commitments |
$ | 18,184 | $ | 25,303 | $ | 107,160 | $ | 2,048 | $ | 152,695 | |||||
45
(1) | Does not include a contingent payment related to the Pond Creek Acquisition because the amount is not contractually determinable until December 31, 2007. The contingent payment, if any, will be paid on March 31, 2008 and cannot exceed $3 million. |
(2) | Maturities based on the January 2006 amended bank credit agreement terms, which extended the maturity date to January 6, 2011. |
(3) | Assumes an annual rate on a 30-day LIBOR of 4.57% plus the current 1.25% margin for a total interest rate of 5.82%. |
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements.
Recent Accounting Pronouncements
In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. EITF Issue No. 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. We do not expect the adoption of this EITF Issue to have a material impact on our consolidated financial position, results of operations or cash flows.
In June 2005, the Financial Accounting Standard Board (FASB) issued FASB Statement No. 154, Accounting Changes and Error Corrections- a replacement of APB Opinion No. 20 and FASB Statement No. 3. This statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. The correction of an error in previously issued financial statements is not an accounting change. However, the reporting of an error correction involves adjustments to previously issued financial statements similar to those generally applicable to reporting an accounting change retrospectively. Therefore, the reporting of a correction of an error by restating previously issued financial statements is also addressed by this statement. This statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of this statement had no effect on our financial statements.
In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an Amendment of Accounting Principles Board (APB) Opinion No. 29, which provides all nonmonetary asset exchanges that have commercial substance must be measured based on fair value of the assets exchanged and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion No. 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. SFAS No. 153 became effective for fiscal periods beginning on or after June 15, 2005. We adopted SFAS No. 153 effective July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on our financial statements.
In March 2005, the FASB issued Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations. FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS 143). A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside our control. FIN 47 states that we must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This interpretation is intended to provide more information about long-lived assets, future cash outflows for these obligations, and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The release of FIN 47 did not affect the method we were applying to accrue asset retirement obligations, therefore, the adoption of FIN 47 had no effect on our financial statements.
46
In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change prior guidance for share-based payments for transactions with non-employees. SFAS No. 123(R) eliminates the intrinsic value measurement objective in APB Opinion 25 and, except in certain circumstances, requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The standard requires grant date fair value to be estimated using either an option-pricing model which is consistent with the terms of the award or a market observed price, if such a price exists. If such fair value cannot be reasonably estimated because it is not practicable to estimate the expected volatility of our share price, we are required to estimate a value calculated by substituting the historical volatility of an appropriate industry sector index for the expected volatility of our share price. Such cost must be recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The standard also requires us to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur.
We adopted SFAS No. 123(R) on January 1, 2006 using the prospective transition method. Under the prospective transition method equity compensation cost will be recognized in the consolidated statement of operations based on fair value for all new awards and existing awards that are modified, repurchased or cancelled after the required effective date of January 1, 2006. For awards outstanding as of January 1, 2006, we will continue using the accounting principles originally applied to those awards before adoption. We are in the process of implementing SFAS No. 123(R). The adoption of SFAS No. 123(R) on January 1, 2006 did not have an impact on our financial position or statement of operations. Subsequent to adoption, the effect of SFAS No. 123(R) cannot be predicted at this time because it will depend on the level of share-based awards granted in the future.
In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instrumentsan amendment of FASB Statements No. 133 and 140. SFAS No. 155 addresses the following: a) permits fair value re-measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation; b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of Statement 133; c) establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation; d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and e) amends Statement 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entitys first fiscal year that begins after September 15, 2006. The Company is currently evaluating the requirements of SFAS No. 155, but does not expect that the adoption of this pronouncement will have a material effect on its financial statements.
Quantitative and Qualitative Disclosures about Market Risk
For a discussion of our commodity and interest rate risks, see the discussions set forth above under Liquidity and Capital ResourcesPrice Risk Management Activities and Liquidity and Capital ResourcesCredit Facility above.
Foreign Currency Exchange Rate Risk
We began exploratory operations in Canada in the fourth quarter of 2004 and do not have operations in any other foreign countries. We do not hedge our foreign currency risk and are exposed to foreign currency exchange rate risk in the Canadian dollar. Because our Canadian project is exploratory, the effect of changes in the exchange rate does not impact our revenues or expenses but primarily affects the costs of unevaluated properties. We continue to monitor the foreign currency exchange rate in Canada and may implement measures to protect against the foreign currency exchange rate risk in the future.
47
About GeoMet
We are engaged in the exploration, development, and production of natural gas from coal seams (coalbed methane or CBM). Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the Appalachian Basin in West Virginia and Virginia. GeoMet was originally founded as a consulting company to the coalbed methane industry in 1985 and has been active as an operator and developer of coalbed methane properties since 1993. At December 31, 2005, we controlled a total of approximately 255,000 net acres of coalbed methane development rights, primarily in Alabama, West Virginia, Virginia, Louisiana, Colorado, and British Columbia. We control a total of approximately 77,000 net acres of coalbed methane development rights in the Gurnee field in the Cahaba Basin and in the Pond Creek field in the Appalachian Basin, and we also control the balance of 178,000 net acres of coalbed methane development rights primarily in north central Louisiana, British Columbia, West Virginia, and Colorado. We have conducted substantial gas desorption testing and drilling of core holes throughout our property base. We believe our extensive undeveloped acreage position in the Gurnee field in the Cahaba Basin and in the Pond Creek field in the Appalachian Basin contains a total of 586 additional drilling locations.
At December 31, 2005, we had 262.5 Bcf of estimated proved reserves with a PV-10 of approximately $880 million using gas prices in effect at such date. See Selected Historical Consolidated Financial and Operating DataReconciliation of Non-GAAP Financial Measures on page 24 for additional information regarding PV-10. Our estimated proved reserves were 100% coalbed methane and 74% proved developed. For the month of May 2006, our net gas sales averaged approximately 16,500 Mcf per day. For 2005, our total capital expenditures were approximately $60 million, and our development expenditures for the development of the Gurnee and Pond Creek fields were approximately $46.4 million. We intend to increase our development expenditures by approximately 57% in 2006 to approximately $72 million to accelerate the drilling of the Gurnee and Pond Creek fields, of which we had spent $10.3 million on development expenditures as of March 31, 2006. For 2006, we estimate that our total capital expenditures will be approximately $90 million and had spent $13.4 million as of March 31, 2006.
Areas of Operation
Cahaba Basin
We have the development rights to approximately 41,800 net CBM acres throughout the Cahaba Basin of central Alabama, which is adjacent to the Black Warrior Basin. At December 31, 2005, approximately 55% of our estimated proved reserves, or 145.1 Bcf, were located in the Gurnee field within the Cahaba Basin, of which approximately 78% were classified as proved developed. At December 31, 2005, we had developed 24% of our Cahaba Basin CBM acreage. We own a 100% working interest in the area and are the operator. As of December 31, 2005, we had drilled 132 wells in the Gurnee field. Net daily sales of gas averaged approximately 5,200 Mcf for the month of May 2006. At December 31, 2005, our undeveloped CBM acreage in the Cahaba Basin contained 366 additional drilling locations, based on 80-acre spacing. In 2006, we intend to spend approximately $45 million of our capital expenditure budget to develop and drill approximately 75 wells and expand our facilities in the Cahaba Basin. As of March 31, 2006, we had spent $6.6 million of this budget and drilled 17 wells.
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 30 core holes have been drilled and over 540 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.
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 design capacity of approximately 45,000 barrels of water per day. We also operate a water treatment facility in the Gurnee field to condition the produced water prior to
48
injection into the pipeline and a discharge pond at the river to aerate the water prior to disposal. We believe that these facilities will meet all of our future water disposal requirements for the Gurnee field.
We control and operate a 9.2-mile, 12-inch high pressure steel pipeline and a gas treatment and compression facility through which we gather, dehydrate, and compress our gas for delivery into the Southern Natural Gas pipeline system. We are re-activating an additional 5.6 miles of existing 12-inch steel pipeline and adding an additional 2.5 miles of newly constructed 12-inch steel pipeline in 2006.
Appalachian Basin
In the Appalachian Basin of southern West Virginia and southwestern Virginia, we have the rights to develop approximately 56,000 net CBM acres, approximately 35,000 of which are in our Pond Creek field. At December 31, 2005, approximately 44% of our estimated proved reserves, or 114.5 Bcf, were located within the Pond Creek field, of which approximately 70% were classified as proved developed. We own a 100% working interest in the area and are the operator. As of December 31, 2005, we had drilled 163 net wells in the Pond Creek field. Net daily sales of gas averaged approximately 10,000 Mcf for the month of May 2006. As of December 31, 2005, our undeveloped CBM acreage in the Pond Creek field contains 220 additional drilling locations based on 80-acre spacing. In 2006, we intend to spend approximately $20 million of our capital expenditure budget to develop and drill approximately 40 wells in the Pond Creek field. As of March 31, 2006, we had spent $3.7 million of this budget and drilled nine wells.
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 high quality, low-medium volatile bituminous rank Pennsylvanian Age coal. Due to mining activity, it has been long known that these coal groups are gas rich. A total of 39 core holes have been drilled in the area 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. We believe this disposal well will meet our future water disposal requirements in the Pond Creek field.
Our gas is gathered into our central dehydration and compression facility and delivered into the Cardinal States Gathering System for redelivery into the Columbia Gas Transmission Corporation gas pipeline system. Our gathering agreement with Cardinal States terminates on April 30, 2007. We have initiated right-of-way acquisitions, permitting, and construction of our own 12-mile pipeline to be constructed at an estimated cost of $5 to $6 million, which we plan to interconnect with Jewell Ridge, a new interstate pipeline. The construction of our new 12-mile pipeline is presently subject to a dispute regarding the right to use the surface of certain acreage. Additional information regarding this dispute can be found below under Legal ProceedingsCNX Surface Use Dispute. East Tennessee Natural Gas, LLC (ETNG), a subsidiary of Duke Energy Corporation, will construct the Jewell Ridge pipeline. The Jewell Ridge Pipeline is expected to be in service before the end of 2006. On March 28, 2006 we executed a precedent agreement with ETNG which, subject to satisfaction of certain conditions, obligate the parties to enter into two long-term firm transportation agreements. The agreements will have maximum daily quantities of 15,000 decatherms and 10,000 decatherms per day, respectively, with primary terms of 15 years and 10 years, respectively.
British Columbia
Our Peace River Project is comprised of approximately 36,573 gross acres (18,287 net acres) including 3,573 gross acres (1,787 net acres) acquired in May 2006 along the Peace River near Hudsons Hope, British Columbia. We are conducting operations on this project through an exploration and development agreement with a third party. We will earn a 50% working interest in this leasehold by spending $7.2 million on an evaluation program. We have spent approximately $7.0 million of this amount from project inception through March 31, 2006. We expect to complete our earning obligations in the second quarter of 2006 and to operate this project
49
going forward. We have drilled three core holes targeting the Lower Cretaceous Gething coal formation. Multiple, mostly thin, coal seams exist at depths from 1,000 to 3,000 feet. At these depths, coals are medium volatile bituminous rank. We believe that the gas content and coal thickness under our acreage position are favorable for CBM development. We have drilled and completed two production test wells, recompleted a third production test well and a water disposal well. We are currently conducting testing operations on these wells.
North Central Louisiana
In Winn, LaSalle, and Caldwell Parishes of Louisiana, we are conducting an evaluation of the coals within the Wilcox Formation. We operate the project with a 100% working interest. As of December 31, 2005, we had a total of approximately 119,000 net acres under lease. The Wilcox is a thick deltaic deposit of Eocene age, composed primarily of sandstone, siltstone, shale, and coal. The coals are low rank, being classified as sub-bituminous and lignitic. Multiple, mostly thin, coal seams exist at depths from 2,000 to 3,500 feet. We have drilled 17 exploration or production test wells and two water disposal wells. We have also conducted 60 gas desorption tests from a sample of nine of these wells to determine the gas content of the coal and to define the potential gas resources. We believe that the gas content and coal thickness under our acreage position are favorable for CBM development. We are currently evaluating producibility issues related to zonal isolation of adjacent water sands and related water encroachment in this area.
Piceance Basin of Colorado
We also hold a total of approximately 16,900 net CBM acres of leasehold in the Piceance Basin in Mesa County, Colorado, of which approximately 14,600 net CBM acres are located in our Cameo prospect in the southwestern portion of the Piceance Basin. We are targeting the Cameo coals within a 200-foot interval of the Williams Fork formation at a depth of about 2,000 feet. We have drilled one core hole and have conducted gas desorption tests on the core. We believe that the gas content and coal thickness under our acreage position are favorable for CBM development. We are actively pursuing opportunities to increase our acreage position in this area.
History of GeoMet
Our predecessor, GeoMet, Inc., an Alabama corporation (Old GeoMet), was founded in 1985 by three geologists (the Founders) with backgrounds in the coal mining and related coal degasification industry. The Founders became directly involved with coalbed methane in 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 and with many of the companies involved in the early development of coalbed methane, including Taurus (now Energen), Amoco, Chevron, and River Gas Corporation (River Gas). In addition to work done in the United States, we have 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 Founders acquired a 25% equity interest in River Gas and we 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. In 1993, following the sale of the Founders equity interest in River Gas, we ceased consulting services and began to participate 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.
50
Shareholders of Old GeoMet sold 80% of their ownership in Old GeoMet in December 2000 to GeoMet Resources, Inc., a Delaware corporation (Resources), a special purpose entity formed by J. Darby Seré, William C. Rankin, and Yorktown Energy Partners IV, L.P. In connection with this purchase, Resources committed an additional $40 million to Old GeoMet to fund future coalbed methane development and Messrs. Seré and Rankin assumed the positions of President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, respectively. Old GeoMet and Resources merged in April 2005 and Resources changed its name to GeoMet, Inc.
Estimated Proved Reserves
The following tables set forth certain information with respect to our estimated proved reserves by field as of December 31, 2005. Reserve volumes and values were determined under the method prescribed by the SEC which requires the application of period-end prices and costs held constant throughout the projected reserve life. The reserve information as of December 31, 2005 is based on estimates made in a reserve report prepared by DeGolyer and MacNaughton, independent petroleum engineers. A summary of DeGolyer and MacNaughtons report on our estimated proved reserves as of December 31, 2005 is attached to this memorandum as Appendix A.
Estimated Proved Reserves | |||||||||||
Field |
Proved Developed Producing |
Proved Developed Non- Producing |
Proved Undeveloped |
Total Proved |
PV-10 | ||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (In million) | |||||||
Appalachia: |
|||||||||||
Pond Creek field |
78,256 | 1,608 | 34,594 | 114,458 | $ | 366,265 | |||||
Alabama: |
|||||||||||
Gurnee field |
88,787 | 23,730 | 32,545 | 145,062 | 496,624 | ||||||
White Oak Creek field |
2,721 | 37 | 233 | 2,991 | 17,266 | ||||||
Total |
169,764 | 25,375 | 67,372 | 262,511 | $ | 880,155 | |||||
PV-10, a non-GAAP measure, is our estimated present value of future net revenues from estimated proved reserves before income taxes. We believe PV-10 to be an important measure for evaluating the relative significance of our CBM gas properties and that PV-10 is widely used by professional analysts and investors in evaluating gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. Management also uses PV-10 in evaluating acquisition candidates. PV-10 only differs from the standardized measure of discounted future net cash flows (SMOG), as calculated and presented in accordance with SFAS No. 69, in that SMOG takes into account the present value of income taxes related to our net cash flows. See Selected Historical Consolidated Financial and Operating DataReconciliation of Non-GAAP Financial Measures.
CBM-producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Therefore, without reserve additions in excess of production through successful exploration and development activities or acquisitions, our reserves and production, after an initial period of incline, are expected to decline slower than non-CBM wells. See Risk Factors and the notes to our consolidated financial statements included elsewhere in this prospectus for a discussion of the risks inherent in CBM gas estimates and for certain additional information concerning the estimated proved reserves.
The weighted average price of gas at December 31, 2005 used to estimate proved reserves and future net revenue was $9.66 per Mcf and was calculated using the Henry Hub cash price at December 31, 2005, of $9.52 per MMBtu of gas, adjusted for our price differentials but excluding the effects of hedging.
51
Historical Finding and Development Costs
For the three years ended December 31, 2005, our finding and development costs have averaged $0.95 per Mcf. The cost of finding and developing reserves is expressed in dollars per Mcf and is calculated for the three year time period by taking the sum of the cost incurred for exploration, development and acquisition, including future development costs attributable to proved undeveloped reserves, adjusted for the change for the period in the balance of unevaluated gas properties not subject to amortization and dividing such amount by the total proved reserve additions. Estimated future development costs at December 31, 2005 totaled $76.3 million. Management believes that this information is useful to an investor in evaluating GeoMet because it measures the efficiency of a company in adding proved reserves as compared to others in the industry. The cost and reserve information is derived directly from line items disclosed in the schedule of Capitalized Cost, Natural Gas Reserves and the Standardized Measure, which are all required to be disclosed by SFAS 69.
The proved reserve additions, approximately 67% of which are proved developed, are primarily attributable to the development of the Pond Creek and Gurnee fields and the Pond Creek Acquisition. Changes in commodity prices, operating costs and other factors also have an effect on the proved reserve additions. We have not quantified the proved reserve additions that are attributable to factors that did not require the expenditure of additional costs. We have a large property position, consisting of over 255,000 net acres of CBM exploration and development rights, including almost 77,000 net undeveloped acres in our two development areas, with 586 additional drilling locations. We expect that exploration and development activities on these properties, not acquisitions of proved reserves from third parties, will be the principal source of our future proved reserve additions. Nonetheless, our historical finding and development costs may not be indicative of those costs in the future, as exploring for and developing CBM involves a variety of risks, and we are unable to predict the amount or timing of future proved reserve additions or the costs that we may incur in connection with any such reserve additions. There is no accepted standard of computing finding and development costs and as a result, finding and development costs are reported in many different ways by companies that compete with us and in certain cases not reported at all.
Production and Operating Statistics
The following table presents certain information with respect to our production and operating data for the periods presented.
Year Ended December 31, | |||||||||
2005 |
2004 |
2003 | |||||||
Gas: |
|||||||||
Net sales volume (Bcf) |
4.6 | 3.2 | 2.5 | ||||||
Average natural gas sales price ($ per Mcf) |
$ | 9.06 | $ | 6.12 | $ | 4.71 | |||
Average natural gas sales price ($ per Mcf) realized (1) |
$ | 7.43 | $ | 5.87 | $ | 4.69 | |||
Total production expenses ($ per Mcf) |
$ | 2.81 | $ | 2.36 | $ | 1.23 | |||
Expenses: ($ per Mcf) |
|||||||||
Lease operations expenses |
$ | 1.89 | $ | 1.60 | $ | 0.66 | |||
Compression and transportation expenses |
$ | 0.72 | $ | 0.61 | $ | 0.40 | |||
Production taxes |
$ | 0.20 | $ | 0.15 | $ | 0.17 | |||
Depreciation, depletion & amortization (excluding impairment) |
$ | 1.06 | $ | 0.84 | $ | 0.85 | |||
Research and development |
$ | 0.13 | $ | 0.09 | $ | 0.17 | |||
General and administrative |
$ | 0.70 | $ | 0.79 | $ | 0.55 |
(1) | Average realized price includes the effects of realized losses on derivative contracts. |
52
Productive Wells and Acreage
The following table sets forth our interest in undeveloped acreage, developed acreage and productive wells in which we own a working interest as of December 31, 2005. Gross represents the total number of acres or wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in the gross acres or wells. Productive wells are wells in which we have a working interest and that are producing and wells capable of producing natural gas.
Productive Wells(1) |
Developed Acres |
Undeveloped Acres | ||||||||||
Area |
Gross |
Net |
Gross |
Net |
Gross |
Net | ||||||
Appalachian Basin |
163 | 163 | 11,599 | 11,599 | 44,344 | 44,017 | ||||||
Cahaba Basin |
132 | 132 | 10,120 | 10,120 | 31,646 | 31,646 | ||||||
North Central Louisiana |
17 | 17 | | | 122,612 | 119,244 | ||||||
British Columbia |
2 | 1 | | | 33,000 | 16,500 | ||||||
Piceance Basin |
| | | | 17,000 | 16,949 | ||||||
Other (United States) |
| | | | 5,028 | 4,790 | ||||||
Total |
314 | 313 | 21,719 | 21,719 | 253,630 | 233,146 | ||||||
(1) | Excludes 9 gross/net wells pending completion at December 31, 2005. |
Drilling Activity
The following table sets forth the number of completed gross exploratory and gross development wells drilled in the United States and Canada that we participated in for each of the last three fiscal years. The number of wells drilled refers to the number of wells commenced at any time during the respective year. Productive wells are producing wells and wells capable of production. At December 31, 2005, we were in the process of completing 9 gross wells (9 net).
Exploratory |
Development | |||||||||||
Well Activity (Gross)United States |
Productive |
Dry |
Total |
Productive |
Dry |
Total | ||||||
Year ended December 31, 2005 |
4 | 3 | 7 | 93 | | 93 | ||||||
Year ended December 31, 2004 |
10 | 1 | 11 | 85 | | 85 | ||||||
Year ended December 31, 2003 |
16 | 1 | 17 | 133 | | 133 |
Exploratory |
Development | |||||||||||
Well Activity (Gross)Canada |
Productive |
Dry |
Total |
Productive |
Dry |
Total | ||||||
Year ended December 31, 2005 |
2 | | 2 | | | |
The following table sets forth, for each of the last three fiscal years, the number of completed net exploratory and net development wells drilled by us based on our proportionate working interest in such wells.
Exploratory |
Development | |||||||||||
Well Activity (Net)United States |
Productive |
Dry |
Total |
Productive |
Dry |
Total | ||||||
Year ended December 31, 2005 |
4.0 | 3.0 | 7.0 | 93.0 | | 93.0 | ||||||
Year ended December 31, 2004 |
10.0 | 1.0 | 11.0 | 81.8 | | 81.8 | ||||||
Year ended December 31, 2003 |
15.0 | 1.0 | 16.0 | 47.7 | | 47.7 |
Exploratory |
Development | |||||||||||
Well Activity (Net)Canada |
Productive |
Dry |
Total |
Productive |
Dry |
Total | ||||||
Year ended December 31, 2005 |
1.0 | | 1.0 | | | |
53
Title to Properties
Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.
We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business.
Marketing and Customers
We market all of our gas through Shamrock Energy LLC, a wholly owned subsidiary of Optigas, Inc., under a natural gas purchase contract that may be terminated by either party upon 90 days notice after February 2006. The contract calls for Shamrock to purchase and us to sell gas from properties covered by the contract, which includes all of our major properties. Shamrock provides several related services including nominations, gas control, gas balancing, transportation and exchange, market and transportation intelligence and other advisory and agency services. We receive the weighted average resale price for the gas less a fee for Shamrocks services ranging from $0.03 to $0.045 per MMBtu purchased. Proceeds from the sale of the gas are deposited into and disbursed from a trust account for our benefit and the obligations of Shamrock are guaranteed by Optigas. The parties have agreed to amend the contract to make certain technical changes including changes in the payment and reporting terms and to provide that the contract be cancelable by either party on 90 days notice. On June 13, 2006, we entered into an option agreement pursuant to which we have the right to acquire all of the outstanding equity interests of Shamrock, which option expires on January 31, 2007.
Competition
Our operations primarily compete regionally in the northeastern and southeastern United States. Competition throughout the United States is regionalized. We believe that the gas market is highly fragmented and not dominated by any single producer. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. We believe that competition within our market is based primarily on price and the proximity of gas fields to customers.
Regulation
Regulation by the FERC of Interstate Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or the FERC, does not directly regulate any of our operations. However, the FERCs regulation influences certain aspects of our business and the market for our products. In general, the FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:
| the certification and construction of new facilities; |
| the extension or abandonment of services and facilities; |
| the maintenance of accounts and records; |
| the acquisition and disposition of facilities; |
| the initiation and discontinuation of services; and |
| various other matters. |
In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.
54
Intrastate Regulation of Natural Gas Transportation Pipelines. We do not own any pipelines that provide intrastate natural gas transportation, so state regulation of pipeline transportation does not directly affect our operations. As with FERC regulation described above, however, state regulation of pipeline transportation may influence certain aspects of our business and the market for our products.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. We own an intrastate natural gas pipeline that we believe would meet the traditional tests the FERC has used to establish a pipelines status as a gatherer not subject to the FERC jurisdiction. However, the distinction between the FERC-regulated transmission services and federally unregulated gathering services is the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts.
In the states in which we operate, regulation of intrastate gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirement and complaint based rate regulation. For example, we are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In certain circumstances, such laws will apply even to gatherers like us that do not provide third party, fee-based gathering service and may require us to provide such third party service at a regulated rate. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Sales of Natural Gas. The price at which we sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms, and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERCs jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERCs more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other sellers of natural gas with whom we compete.
Environmental Regulations
Our coalbed methane exploration and production operations are subject to significant federal, state, and local environmental laws and regulations governing environmental protection as well as the discharge of substances into the environment. These laws and regulations may restrict the types, quantities, and concentrations
55
of various substances that can be released into the environment as a result of natural gas and oil drilling, production, and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells; and restrict injection of liquids into subsurface strata that may contaminate groundwater. Governmental authorities have the power to enforce compliance with their laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that are adopted in the future, could have a material adverse impact on our operations.
We believe that we are in substantial compliance with existing applicable environmental laws and regulations. However, it is possible that new environmental laws or regulations or the modification of existing laws or regulations could have a material adverse effect on our operations. As a general matter, the recent trend in environmental legislation and regulation is toward stricter standards, and this trend will likely continue. To date, we have not been required to expend extraordinary resources in order to satisfy existing applicable environmental laws and regulations. However, costs to comply with existing and any new environmental laws and regulations could become material. Moreover, a serious incident of pollution may result in the suspension or cessation of operations in the affected area or in substantial liabilities to third parties. Although we maintain insurance coverage against costs of clean-up operations, no assurance can be given that we are fully insured against all such potential risks. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.
The following is a summary of some of the existing environmental laws, rules and regulations to which our operations in the United States are subject. Our operations in Canada are subject to similar Canadian requirements.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes strict, joint and several liability without regard to fault or legality of conduct, on persons who are considered to have contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although CERCLA currently excludes petroleum and natural gas, natural gas liquids, liquefied natural gas or synthetic gas useable for fuel, from the definition of hazardous substance, our operations may generate materials that are subject to regulation as hazardous substances under CERCLA.
CERCLA may require payment for cleanup of certain abandoned waste disposal sites, even if such waste disposal activities were undertaken in compliance with regulations applicable at the time of disposal. Under CERCLA, one party may, under certain circumstances, be required to bear more than its proportional share of cleanup costs if payment cannot be obtained from other responsible parties. CERCLA authorizes the U.S. Environmental Protection Agency and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of financial liability under these laws involves inherent uncertainties.
Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, or RCRA, and comparable state programs regulate the management, treatment, storage, and disposal of hazardous and non-hazardous solid wastes. Our operations generate wastes, including hazardous wastes, that are subject to RCRA and comparable state laws. We believe that these operations are currently complying in all material respects with applicable RCRA requirements. Although RCRA currently exempts certain natural gas and oil
56
exploration and production wastes from the definition of hazardous waste, we cannot assure you that this exemption will be preserved in the future, which could have a significant impact on us as well as of the oil and gas industry, in general.
Water Discharges. Our operations are subject to the Clean Water Act, or CWA, as well as the Oil Pollution Act, or OPA, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, including wetlands. Under the CWA and OPA, any unpermitted release of pollutants from operations could cause us to become subject to: the costs of remediating a release; administrative, civil or criminal fines or penalties; or OPA specified damages, such as damages for loss of use and natural resource damages. In addition, in the event that spills or releases of produced water from CBM production operations were to occur, we would be subject to spill notification and response requirements under the CWA or the equivalent state regulatory program. Depending on the nature and location of these operations, spill response plans may also have to be prepared.
Our CBM exploration and production operations produce substantial volumes of water that must be disposed of in compliance with requirements of the CWA, Safe Drinking Water Act, or SDWA, or an equivalent state regulatory program. This produced water is disposed of by re-injection into the subsurface through disposal wells, discharge to surface streams, or in evaporation ponds. Discharge of produced water to surface streams and other bodies of water must be authorized in advance pursuant to permits issued under the CWA, and disposal of produced water in underground injection wells must be authorized in advance pursuant to permits issued under the SDWA. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been disposed in substantial compliance with such permits and applicable laws.
Air Emissions. The Clean Air Act, or CAA, and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Air emissions from some equipment used in our operations, such as gas compressors, are potentially subject to regulations under the CAA or equivalent state and local regulatory programs, although many small air emission sources are expressly exempt from such regulations. To the extent that these air emissions are regulated, they are generally regulated by permits issued by state regulatory agencies. To date, we believe that no unusual difficulties have been encountered in obtaining air permits, and we believe that our operations are in substantial compliance with the CAA and analogous state and local laws and regulations. However, in the future, we may be required to incur capital expenditures or increased operating costs to comply with air emission-related requirements.
Other Laws and Regulations. Our operations are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud.
In addition, our operations may in the future be subject to the regulation of greenhouse gas emissions. Numerous countries, including Canada but not the United States, are participants in the Kyoto Protocol to the United Nations Framework Convention on Climate Change. Participating countries are required to implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributed to global warming. Although the United States is not participating in the Protocol, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from certain greenhouse gas emission sources, primarily power plants. The oil and gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations in the United States currently are not adversely impacted by current state and local climate change initiatives. Our Canadian operations are subject to the Protocol, but implementation of the Protocols greenhouse gas emission reduction requirements in British
57
Columbia are not presently expected to have a significant adverse effect on our operations. However, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions may impact our business.
Employees
At December 31, 2005, we had 63 full-time employees. None of our employees are represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.
Legal Proceedings
From time to time we are a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial condition, results of operations or cash flows.
El Paso Overriding Royalty Interest Dispute
We filed a claim on June 9, 2004 against El Paso Production Company, CMV Joint Venture and CDX Minerals, LLC seeking a declaratory judgment of our rights under a joint operating agreement covering certain properties in White Oak Creek. We had previously entered into an agreement to sell our interest to CDX, subject to a preferential right to purchase held by El Paso, which El Paso subsequently exercised. A dispute arose as to whether the preferential right granted under the agreement applied to overriding royalty interests and other related interests. We have asserted that the preferential right to purchase does not include overriding royalty interests and that we are entitled to retain all overriding royalty interests we possess under the agreement. The trial court rendered judgment in our favor, and El Paso has appealed the decision of the trial court. While we believe that we are entitled to retain these interests, a judgment against us would result in our being required to sell the overriding royalty interest to El Paso for a price of approximately $10.5 million; however, this amount would be reduced by any proceeds we have received from production since the effective date of the sale.
CNX Surface Use Dispute
We and Pocahontas Mining Limited Liability Company (PMC) filed a claim on May 26, 2006 against CNX Gas Company LLC (CNX) seeking a temporary and permanent injunction as well as a declaration of our rights under a right-of-way agreement that we entered into with PMC, the surface owner. We are in the process of constructing a 12-mile pipeline, a portion of which traverses this right-of-way to connect with and transport our gas to the Jewell Ridge Pipeline. CNX has claimed that it has the exclusive right to transport gas across the acreage in question and that our right-of-way is invalid. CNX has gated certain access roads to the acreage and requested that we remove our contractors equipment from the property. The Circuit Court of Buchanan County, Virginia conducted an evidentiary hearing on June 15, 2006. That hearing was continued until July 6, 2006 for the taking of additional evidence. In the interim period, the court has ordered CNX to allow us access to the property over and across the existing roads. We believe that our right-of-way agreement is valid and enforceable and that we will prevail in our lawsuit; however, in the event we are not allowed access to this acreage, we may be required to construct an alternate pipeline, change the planned route of our pipeline, seek alternative methods to market our gas, or attempt to extend our current gathering agreement with Cardinal States Gathering Company, a subsidiary of CNX, on terms that may be unfavorable to us. Each of these alternatives will be costly and may result in our inability to deliver our gas to market for an extended period of time. Such inability could have a material adverse effect on our financial position, results of operations and cash flows.
Insurance Matters
As is common in the gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations and cash flows.
58
Executive Officers and Directors
The following discussion sets forth the names and ages of our executive officers and the names and ages of the individuals that serve on our board of directors. Our executive officers are appointed by our board of directors and shall serve until the expiration of their contracts, their death, resignation, or removal by our board of directors. Our directors serve one year terms or until their successors are elected and qualified or until their death, resignation or removal in the manner provided in our bylaws. The present term of each director will expire at the next annual meeting of our stockholders.
Name |
Age |
Position with Company | ||
J. Darby Seré |
58 | Chairman of the Board, President, and Chief Executive Officer | ||
William C. Rankin |
56 | Executive Vice President and Chief Financial Officer | ||
Philip G. Malone |
58 | Senior Vice PresidentExploration and Director | ||
Brett S. Camp |
47 | Senior Vice PresidentOperations | ||
J. Hord Armstrong, III |
65 | Director | ||
James C. Crain |
57 | Director | ||
Stanley L. Graves |
61 | Director | ||
Charles D. Haynes |
66 | Director | ||
W. Howard Keenan, Jr. |
55 | Director |
J. Darby Seré, Chairman of the Board, President, and Chief Executive Officer. Since 2000, Mr. Seré has served as a Director, President and Chief Executive Officer of GeoMet, Inc. Mr. Seré was elected Chairman of the Board in January 2006. Mr. Seré has over 34 years of experience in the oil and gas business, including 17 years as Chief Executive Officer of two publicly held exploration and production companies. Mr. Seré served as President, CEO and Director of Bellwether Exploration Company from 1988-1999, where he also served as Chairman of the Board from 1997-1999, and President, Chief Executive Officer and Director of Bayou Resources, Inc. from 1982-1987. Mr. Seré was Manager of Acquisitions, Vice PresidentAcquisitions and Engineering and Executive Vice President of Howell Corporation / Howell Petroleum Corporation from 1977-1981. Mr. Seré began his career as a staff reservoir engineer for Chevron Oil Co. in 1970. Mr. Seré currently serves as a director of Gateway Energy Corporation, a publicly held gas gathering, transportation and distribution company. Mr. Seré is a registered professional engineer and holds a Bachelors degree in Petroleum Engineering from Louisiana State University and a Masters of Business Administration from Harvard University.
William C. Rankin, Executive Vice President and Chief Financial Officer. Since 2000, Mr. Rankin has served as Executive Vice President and Chief Financial Officer of GeoMet, Inc. Mr. Rankin has 34 years experience as an accountant and financial manager, including 27 years as a financial officer with both publicly and privately owned energy companies. He began his career as an auditor with Deloitte & Touche from 1971-1975. He served as Director of Internal Audit of Kerr-McGee Corporation from 1975-1977, Controller of Cotton Petroleum Corporation from 1977-1980 and Executive Vice President and Chief Financial Officer for Cayman Resources Corporation from 1980-1985. Mr. Rankin joined Hadson Corporation in 1985 as Vice President and Controller, became Vice President and Treasurer in 1988 and last served as Sr. Vice President and Chief Financial Officer of Hadson Resources Corporation from 1989-1993. In 1994 he became Sr. Vice President and Chief Financial Officer of Contour Energy Company (and its predecessors) where he served until 1997. In 1997, he became Sr. Vice President of Bellwether Exploration Company. Mr. Rankin is a Certified Public Accountant and holds a Bachelors degree in Accounting from the University of Arkansas.
Philip G. Malone, Senior Vice PresidentExploration and Director. Since 2000, Mr. Malone has served as our Vice PresidentExploration. Mr. Malone has 31 years experience as a professional geologist; one year at the Geological Survey of Alabama, ten years at USX Corporation and 20 years at GeoMet, where he participated in founding the company in 1985. From 1976 to 1985, he was a geologist with USX Corporation and served as chief geologist for the last three years of his tenure with responsibility for supervising exploration and
59
development work related to coal and coalbed methane for USX Southern District. He has authored and co-authored numerous technical papers and is a recognized speaker worldwide on CBM topics. Mr. Malone holds a Bachelors degree in Geology from the University of Alabama.
Brett S. Camp, Senior Vice PresidentOperations. Since 2000, Mr. Camp has been our Vice President-Operations. Mr. Camp has 24 years experience as a professional geologist; four years at USX Corporation and 20 years at GeoMet, where he participated in founding the company in 1985. Mr. Camp holds a Bachelors degree in Geology from Eastern Illinois University.
J. Hord Armstrong, III, Director. Mr. Armstrong was appointed to our board of directors in January 2006. Mr. Armstrong has over 30 years of financial and operational experience in varied industries. Mr. Armstrong founded D&K Healthcare Resources, Inc. in 1987, and served as its Chairman and Chief Executive Officer until October 2005. From 1977 to 1987, Mr. Armstrong was with Arch Coal Inc. last serving as its Chief Financial Officer. Mr. Armstrong was First Vice President with White Weld & Company from 1968 to 1977. Mr. Armstrong served for ten years as a member of the Board of Trustees of the St. Louis College of Pharmacy and has served as a director of Jones Pharma Incorporated. Mr. Armstrong formerly served as Chairman of the Board of Trustees of the Pilot Fund, a registered investment company, and also formerly served as a Director of BHA, Inc., based in Kansas City, Missouri. Mr. Armstrong graduated from Williams College in 1963, and attended the New York University School of Business in 1965 and 1966.
James C. Crain, Director. Mr. Crain was appointed to our board of directors in January 2006. Mr. Crain has been involved in the energy industry for over 30 years, both as an attorney and as an executive officer. Since 1984, Mr. Crain has held officer positions with Marsh Operating Company, including Vice President of Land and Legal, Executive Vice President, and his current position, President, which he has held since 1989. In addition, since 1997, Mr. Crain has acted as the general partner of Valmora Partners, L.P., which invests in various oil and gas businesses. Prior to joining Marsh in 1984, Mr. Crain was a Partner in the law firm of Jenkens & Gilchrist, where he was the head of the Energy Section. Mr. Crain currently serves on the board of directors of Crosstex Energy, L.P., a Delaware limited partnership that is publicly traded on the Nasdaq National Market. Mr. Crain holds a Bachelors degree in Accounting, a Masters of Professional Accounting in Taxation and a Juris Doctorate degree, all from the University of Texas.
Stanley L. Graves, Director. Mr. Graves was appointed to our board of directors in January 2006. Mr. Graves has over 37 years of experience in the oil and gas business. He currently serves as Chairman of the Board of Graves Service Company, Inc., as well as President of Graco Resources, Inc. From 1997-2002, Mr. Graves was the President of U.S. Clay, L.P., which mined and processed bentonite. Prior to his time at U.S Clay, L.P., Mr. Graves served as Vice PresidentBusiness Development for Ultimate Abrasive Systems, Inc., as President of Eldridge Gathering System Inc., and as Vice President of Energen Corp., the largest CBM producer in Alabama. Mr. Graves currently serves on the board of directors of CapitalSouth Bancorp, a publicly traded bank holding corporation. Mr. Graves holds a Bachelors degree in Engineering from Auburn University.
Charles D. Haynes, Director. Dr. Haynes was appointed to our board of directors in January 2006. Dr. Haynes has over 43 years in the energy profession as an academic, researcher, and executive. He retired from The University of Alabama in May 2005, having held faculty and administrative positions since 1991. From 1977 to 1990, he was a senior executive officer and director of Belden & Blake Corporation. He is a licensed professional engineer in Alabama and currently serves as Chair of the Alabama Board of Licensure for Engineers and Land Surveyors. He holds Bachelors, Masters, and Doctorate degrees from The University of Alabama, Pennsylvania State University, and the University of Texas, respectively.
W. Howard Keenan, Jr., Director. Mr. Keenan has served on our board of directors since December 2000. Mr. Keenan has over 30 years of experience in the financial and energy businesses. Since 1997, he has been a Member of Yorktown Partners LLC, a private equity investment manager focused on the energy industry. From 1975 to 1997, he was in the Corporate Finance Department of Dillon, Read & Co. Inc. and active in the private
60
equity and energy areas including the founding of the first Yorktown Fund in 1991. He is or has served as a director of multiple Yorktown portfolio companies. Mr. Keenan holds a Bachelors degree from Harvard College and a Masters of Business Administration from Harvard University.
Board of Directors; Committees of the Board
Our board of directors is comprised of seven members, consisting of J. Darby Seré, Philip G. Malone, J. Hord Armstrong, III, James C. Crain, Stanley L. Graves, Charles D. Haynes, and W. Howard Keenan, Jr. We expect that Messrs. Armstrong, Crain, Graves, and Haynes, being a majority of our board, will qualify as independent directors as such term is defined by the SEC and the exchange on which our securities will be traded. We have a compensation committee, an audit committee, and a nominating, corporate governance and ethics committee, which are each composed of independent directors. We also have an executive committee that has three members, one of whom is an independent director.
Director Compensation
Each of our independent directors receives an annual retainer of $20,000 and an annual grant of 2,000 shares of non-qualified stock options. Our independent directors also receive $1,500 for each board meeting attended and $1,000 for each committee meeting attended. In lieu of the foregoing meeting fees, if attendance is by telephone, they receive a fee of $200 per hour. The Chairman of the Audit Committee receives an additional annual retainer of $10,000. The Chairs of other committees of our board of directors receive an additional annual retainer of $5,000. All directors are reimbursed for reasonable expenses incurred in their service on our board of directors.
Indemnification
Our certificate of incorporation and bylaws provide that we will indemnify our officers and directors to the fullest extent permitted by law. Additionally, we have entered into separate indemnification agreements with our officers and the members of our board of directors to provide additional indemnification benefits, including the right to receive in advance reimbursements for expenses incurred in connection with a defense for which the officer or director is entitled to indemnification.
61
Executive Compensation
The Summary Compensation Table below sets forth the cash and non-cash compensation information for the years ended December 31, 2005, 2004 and 2003 for the Chief Executive Officer and our other executive officers whose salary and bonus earned for services rendered to us exceeded $100,000 for the most recent fiscal year.
Summary Compensation Table
Annual Compensation |
Long-Term Compensation |
|||||||||||||||||||
Awards |
Payouts |
|||||||||||||||||||
Name And Principal Position |
Year |
Salary ($) |
Bonus ($)(1) |
Other Annual Compensation (2)($) |
Restricted Stock Award(s) ($) |
Securities Underlying Options (#)(3) |
LTIP Payouts |
All Other Compensation (4)($) | ||||||||||||
J. Darby Seré Chairman of the Board, President, and Chief Executive Officer |
2005 2004 2003 |
$ |
255,600 243,360 231,840 |
$ |
182,235 70,574 63,756 |
$ |
11,305 6,881 7,448 |
|
106,660 319,980 |
|
$ |
6,300 6,150 7,000 | ||||||||
William C. Rankin Executive Vice President and Chief Financial Officer |
2005 2004 2003 |
$ |
211,800 201,720 192,144 |
$ |
154,725 58,499 52,840 |
$ |
15,071 14,664 12,413 |
|
93,340 280,020 |
|
$ |
6,300 6,000 6,000 | ||||||||
Philip G. Malone Senior Vice PresidentExploration |
2005 2004 2003 |
$ |
119,160 109,163 121,800 |
$ |
36,940 22,924 33,495 |
|
|
|
|
|
$ |
4,263 4,280 4,598 | ||||||||
Brett S. Camp Senior Vice PresidentOperations |
2005 2004 2003 |
$ |
161,180 126,000 119,400 |
$ |
49,966 36,540 32,835 |
|
|
|
|
|
$ |
5,932 4,765 4,506 |
(1) | Bonuses represent the amount earned for the year indicated and are generally paid in the following year. Messrs. Seré and Rankin received $79,995 and $70,005, respectively, of bonuses for 2005 during 2005 prior to our merger with our majority-owned subsidiary. |
(2) | Other compensation includes paid vacation time not taken by the named executives. |
(3) | These options were granted pursuant to the GeoMet Resources, Inc. Stock Acquisition and Stockholders Agreement, which allowed Messrs. Seré and Rankin collectively to be granted options to purchase up to 1.2 million shares of our common stock. These options have an exercise price of $2.50 per share and fully vested on January 30, 2006. These options expire 10 years after the date of grant. |
(4) | Represents employer matching contributions to our 401(k) plan. |
Option/SAR Grants in Fiscal Year 2005
There were no options/SARs granted during this period.
Aggregated Option/SAR Exercises and December 31, 2005 Option/SAR Values
The following table sets forth for each of the named executive officers the number of shares subject to both exercisable and unexercisable stock options in respect of our common stock, as well as the value of unexercisable in-the-money options as of the end of December 31, 2005. We have not granted any SARS.
Name |
Shares Acquired on Exercise (#) |
Value Realized ($) |
Number of Securities Underlying Unexercised Options/SARs at December 31, 2005 (shares) |
Value of Unexercised In the Money Options/SARs at December 31, 2005 ($)(1) | ||||||||||
Exercisable |
Unexercisable(2) |
Exercisable |
Unexercisable | |||||||||||
J. Darby Seré |
| | 462,200 | 177,760 | $ | 4,853,100 | $ | 1,866,480 | ||||||
William C. Rankin |
| | 404,480 | 155,560 | $ | 4,247,040 | $ | 1,633,380 |
(1) | Calculated using the price of $13.00 received in the private offering on January 30, 2006 less the applicable exercise price multiplied by the number of option shares. |
(2) | All stock options became vested and immediately exercisable on January 30, 2006, the closing date of our private placement offering. Mr. Seré exercised and sold 160,000 shares in connection with the private placement offering. |
62
The stock options granted to these executive officers were granted pursuant to the GeoMet Resources, Inc. Stock Acquisition and Stockholders Agreement. These options have an exercise price of $2.50 per share and fully vested on January 30, 2006, the date on which Yorktown and its permitted transferees ceased to own at least 60% of our common stock. These options expire 10 years after the dates of grant.
Employment Agreements and Other Arrangements
Mr. Seré and Mr. Rankin executed employment agreements in December 2000, each agreement having initial terms that expired in December 2003. The agreements are substantially similar in form, with differences in titles, responsibilities and base salary. Following the expiration of the initial term, each agreement has been automatically extended for an additional one-year term, and will continue to be automatically extended for an additional year, unless we or the executive gives written notice to the contract party 90 days before the end of subsequent additional term.
Each agreement provides that, if the executives employment is terminated by us without cause, or by the executive for good reason, that we will pay him, within 30 days of the date of termination, a lump sum amount equal to 18-months base salary, plus the executives base salary, reimbursable expenses and vacation accrued but unpaid through the date of termination. In addition, we will continue to provide group medical and dental insurance to the executive and the executives family for a period of 18 months after the date of termination.
Officer Bonus Program
Our officer bonus compensation has been previously determined at the sole discretion of the compensation committee and was not subject to any formal plan. Beginning in 2006, certain of our officers bonus compensation will be based on the achievements of targets of four performance measures, including annual production, year-end proved reserve quantities, annual EBITDA, and three-year finding and development costs. Each of these performance measures carries a 25% weight in determining the total bonus amount. The bonus amount determined by achievements of the targets of these performance measures will range from a minimum of 25% of each such officers bonus target percentage of annual base salary compensation to a maximum of 175% of such target percentage. The bonus target percentages of annual base salary compensation for our chief executive officer, our chief financial officer and our two senior vice presidents are 60%, 50%, 40%, and 40%, respectively. Our chief executive officer may recommend that any or all of the individual bonuses (except his own), as so determined be adjusted by an absolute 25% of the bonus target percentage of annual base salary compensation based on subjective individual performance factors. The compensation committee may make further adjustments to increase or decrease individual bonuses based on subjective performance factors.
Incentive Bonus Pool Plan
We established an Incentive Bonus Pool Plan (the Bonus Plan) in 2001 to provide a performance incentive and a retention vehicle for certain of our key non-executive management, technical and professional employees. Our compensation committee administers the Bonus Plan. Awards consist of pool units that are fictional ownership units in the incentive bonus pool where the maximum number of pool units of the Bonus Plan cannot exceed 1,000 units. Amounts credited to the incentive bonus pool for a plan year equal 2% of our annual un-audited consolidated pre-tax income. Awards under the Bonus Plan are paid in installments over three years, 50% of the award in year one and installments of 25% each are paid in the succeeding two years, subject to the participants continuing employment with us. In the event of change of control as defined each participants unpaid incentive bonus becomes fully vested. Our board of directors may terminate the Bonus Plan at any time and pay outstanding awards.
Description of 2005 Stock Option Plan
We have adopted the GeoMet, Inc. 2005 Stock Option Plan (the 2005 Plan). Our board of directors believes that equity-based incentive compensation plans provide an important means of attracting, retaining and motivating employees, non-employee directors, and other service providers. The 2005 Plan is intended to promote and advance our interests by providing our employees, non-employee directors and other service
63
providers added incentive to continue in our service through a more direct interest in the future success of our operations. Our board of directors believes that employees, non-employee directors, and other service providers who have an investment in us are more likely to meet and exceed performance goals. In 2001, the Company established a stock option plan that authorizes the granting of options to key employees to acquire common stock of its majority-owned subsidiary at prices equivalent to the market value at the date of grant. The options have a term of seven years, vest evenly over four years and become exercisable on each of the first four anniversary dates of issuance. Effective with the merger of the majority-owned subsidiary into GeoMet, all of the outstanding options under this plan became fully vested and the options were exchanged for options to acquire common stock of GeoMet under the 2005 Plan. Our board of directors and stockholders recently approved the GeoMet, Inc. 2006 Long-Term Incentive Plan discussed below, under which an additional 2,000,000 shares of our common stock were reserved for awards to be granted. In conjunction with the approval of the 2006 Plan, we will not grant any additional awards under our 2005 Plan; however, we will continue to issue shares of our common stock upon exercise of awards that we have previously granted. The following is a summary of the 2005 Plan.
Administration. The 2005 Plan provides for administration by our compensation committee. Among the powers granted to the compensation committee are (1) the authority to interpret the 2005 Plan and the options granted thereunder, (2) determine eligibility for participation in the 2005 Plan, (3) prescribe the form of the option agreements embodying options granted under the 2005 Plan, (4) make administrative guidelines and other regulations for carrying out the 2005 Plan and make changes in such guidelines and regulations as the compensation committee deems proper and (5) take any and all other actions it deems necessary or advisable for the proper operation or administration of the 2005 Plan. The compensation committee also has authority with respect to all matters relating to the discharge of its responsibilities and the exercise of its authority under the 2005 Plan. The 2005 Plan provides for indemnification of compensation committee members for personal liability incurred related to any action, interpretation or determination made in good faith with respect to the 2005 Plan and awards made under the 2005 Plan.
Eligibility. Our employees, non-employee directors and other service providers who, in the opinion of the compensation committee, are in a position to make a significant contribution to our success are eligible to participate in the 2005 Plan. The compensation committee determines the type and size of award and sets the terms, conditions, restrictions and limitations applicable to the award within the confines of the terms of the 2005 Plan.
Available Shares. The maximum number of shares available for grant under the plan is 1,200,000 shares of our common stock plus any shares of common stock that become available under the 2005 Plan for any reason other than exercise. The number of shares available for award under the 2005 Plan is subject to adjustment for certain corporate changes in accordance with the provisions of the 2005 Plan. Shares of common stock issued pursuant to the 2005 Plan may be shares of original issuance or treasury shares or a combination of those shares.
Stock Options. The 2005 Plan provides for the grant of incentive stock options intended to meet the requirements of Section 422 of the Code and nonqualified stock options that are not intended to meet those requirements. Incentive stock options may be granted only to our employees. All options will be subject to terms, conditions, restrictions and limitations established by the compensation committee, as long as they are consistent with the terms of the 2005 Plan.
The compensation committee will determine when an option will vest and become exercisable. No option will be exercisable more than ten years after the date of grant (or, in the case of an incentive stock option granted to a 10% shareholder, five years after the date of grant). Unless otherwise provided in the option award agreement, options terminate within a certain period of time following a participants termination of employment or service for any reason other than cause (one year in the case of an incentive stock option and two years in the case of a non-qualified stock option) or for cause (three months).
The exercise price of a stock option granted under the 2005 Plan shall be determined by the compensation committee but may not, in any event, be less than the fair market value of the common stock on the date of grant.
64
Incentive stock options must be granted at 100% of fair market value (or, in the case of an incentive stock option granted to a 10% shareholder, 110% of fair market value).
The exercise price of a stock option may be paid (i) in cash, (ii) with the consent of the compensation committee, by the execution of a promissory note and/or a combination of cash and execution of a promissory note, or (iii) with the consent of the compensation committee and if and to the extent provided for under the option agreement for such option, in cash and/or by delivery of shares of common stock already owned by the optionee having an aggregate fair market value (determined as of the date of exercise) equal to the purchase price.
New Plan Benefits. The number of awards that will be received by or allocated to our executive officers, non-employee directors, employees, and other service providers under the 2005 Plan is undeterminable at this time.
Corporate Change. Unless an award agreement provides otherwise, in the event of a participants involuntary termination of employment or service other than for death, cause, or inability to perform or a voluntary termination for good reason, within one year after a corporate change (which may include, among others, the dissolution or liquidation of us, certain reorganizations, mergers or consolidations, the sale of all or substantially all our assets, or the closing of an underwritten public offering of our common stock), the board of directors serving prior to the date of the applicable event shall accelerate the exercise dates of all outstanding options, and may, in its discretion, without obtaining stockholder approval, pay cash to any or all optionees in exchange for the cancellation of their outstanding options.
Withholding Taxes. All applicable withholding taxes will be deducted from any payment made under the 2005 Plan, withheld from other compensation payable to the participant, or be required to be paid by the participant prior to the making of any payment of cash or common stock under the 2005 Plan. Payment of withholding taxes may be made by withholding shares of common stock from any payment of common stock due or by the delivery by the participant of previously acquired shares of common stock, in either case having an aggregate fair market value equal to the amount of the required withholding taxes. No payment will be made and no shares of common stock will be issued pursuant to any award made under the 2005 Plan until the applicable tax withholding obligations have been satisfied.
Transferability. No award may be sold, transferred, pledged, exchanged, or disposed of, except by will or by the laws of descent and distribution. All awards are exercisable during the lifetime of the optionee only by the optionee, or if the optionee is legally incompetent, by the optionees legal representative. If provided in the award agreement, nonqualified stock options may be transferred by a participant to a permitted transferee. In connection with a divorce, a participant may request that we agree to observe the terms of a domestic relations order with respect to all or part of an award granted to a participant. Our decision regarding such a request will be made by the compensation committee based upon our interests. The compensation committees decision need not be uniform between participants.
Amendment. Our board of directors may suspend, terminate, amend or modify the plan, but may not without the approval of the holders of a majority of the shares of our common stock make any alteration or amendment that operates (1) to increase the total number of shares of common stock as to which options may be granted under the 2005 Plan (other than adjustments in connection with certain corporate reorganizations and other events), (2) to extend the term of the 2005 Plan or the exercise period beyond the ten-year maximum provided in the 2005 Plan, (3) to decrease the minimum purchase price provided in the 2005 Plan, or (4) to make any other change requiring shareholder approval under any applicable rule, regulation, or procedure of any national securities exchange or securities association upon which any of our securities are listed. No suspension, termination, amendment or modification of the plan will adversely affect in any material way any award previously granted under the 2005 Plan, without the consent of the participant.
Effectiveness. The 2005 Plan became effective in April 2005. Unless terminated earlier, the 2005 Plan will terminate on the tenth anniversary of the effective date. However, we have suspended granting any additional awards in conjunction with the approval of our 2006 Plan, which is discussed below.
65
Description of 2006 Long-Term Incentive Plan
The GeoMet, Inc. 2006 Long-Term Incentive Plan (the 2006 Plan), under which 2,000,000 shares of our common stock have been reserved for awards to be granted, has been approved by our board of directors and stockholders. The purpose of the 2006 Plan is to promote and advance our interests by providing our officers, independent directors, and technical and professional employees added incentive to continue in our service through a more direct interest in the future success of our operations. We believe that officers, independent directors, and technical and professional employees who have an investment in us are more likely to meet and exceed performance goals. We believe that the various equity-based incentive compensation vehicles provided for under the 2006 Plan, which may include stock options, restricted and unrestricted stock, restricted stock units, stock appreciation rights, performance awards and other incentive awards, are needed to maintain and promote our competitive ability to attract, retain and motivate officers, independent directors, and technical and professional employees. The following is a summary of the 2006 Plan.
Purposes. The 2006 Plan allows for the grant of stock options, stock awards, restricted stock, restricted stock units, stock appreciation rights, performance awards, and other incentive awards to our employees and independent directors who are in a position to make a significant contribution to the success of us and our affiliates. The purposes of the 2006 Plan are to attract and retain employees and independent directors, further align their interests with shareholder interests, and closely link compensation with company performance. The 2006 Plan will provide an essential component of the total compensation package, reflecting the importance that we place on aligning the interests of employees and independent directors with those of our stockholders.
Administration. The 2006 Plan provides for administration by the Compensation Committee or another committee of our board of directors (the Committee). However, each member of the Committee must (1) meet independence requirements of the exchange on which our common stock is listed (if any), (2) be a non-employee director within the meaning of Rule 16b-3 under the Securities Exchange Act of 1934, and (3) be an outside director under Section 162(m) of the Internal Revenue Code of 1986, as amended (the Code). With respect to awards granted to non-employee directors, the Committee is the board of directors. Among the powers granted to the Committee are (1) the authority to operate, interpret and administer the 2006 Plan, (2) determine eligibility for and the amount and nature of awards, (3) establish rules and regulations for the operation of the 2006 Plan, accelerate the exercise, vesting or payment of an award if the acceleration is in our best interest, (4) require participants to hold a stated number or percentage of shares acquired pursuant to an award for a stated period of time, and (5) establish other terms and conditions of awards made under the 2006 Plan. The Committee also has authority with respect to all matters relating to the discharge of its responsibilities and the exercise of its authority under the 2006 Plan. The 2006 Plan provides for indemnification of Committee members for personal liability incurred related to any action, interpretation, or determination made in good faith with respect to the Plan and awards made under the 2006 Plan.
Eligibility. Our employees and independent directors who, in the opinion of the Committee, are in a position to make a significant contribution to our success and our affiliates are eligible to participate in the 2006 Plan. The Committee determines the type and size of award and sets the terms, conditions, restrictions and limitations applicable to the award within the confines of the terms of the 2006 Plan.
Available Shares. The maximum number of shares available for grant under the 2006 Plan is 2,000,000 shares of common stock plus any shares of common stock that become available under the 2006 Plan for any reason other than exercise. The number of shares available for award under the 2006 Plan is subject to adjustment for certain corporate changes in accordance with the provisions of the 2006 Plan. Shares of common stock issued pursuant to the 2006 Plan may be shares of original issuance or treasury shares or a combination of those shares.
The maximum number of shares of common stock available for grant of awards under the 2006 Plan to any one participant is (1) 200,000 shares during the fiscal year in which the participant begins work for us and (2) 100,000 shares during each fiscal year thereafter.
Stock Options. The 2006 Plan provides for the grant of incentive stock options intended to meet the requirements of Section 422 of the Code and nonqualified stock options that are not intended to meet those
66
requirements. Incentive stock options may be granted only to our employees. All options will be subject to terms, conditions, restrictions, and limitations established by the Committee, as long as they are consistent with the terms of the 2006 Plan.
The Committee will determine when an option will vest and become exercisable. No option will be exercisable more than ten years after the date of grant (or, in the case of an incentive stock option granted to a 10% shareholder, five years after the date of grant). Unless otherwise provided in the option award agreement, options terminate within a certain period of time following a participants termination of employment or service for any reason other than cause (12 months) or for cause (30 days).
Generally, the exercise price of a stock option granted under the 2006 Plan may not be less than the fair market value of the common stock on the date of grant. However, the exercise price may be less if the option is granted in connection with a transaction and complies with special rules under Section 409A of the Code. Incentive stock options must be granted at 100% of fair market value (or, in the case of an incentive stock option granted to a 10% shareholder, 110% of fair market value).
The exercise price of a stock option may be paid (1) in cash, (2) in the discretion of the Committee, with previously acquired nonforfeitable, unrestricted shares of common stock that have been held for six months and that have an aggregate fair market value at the time of exercise equal to the total exercise price, or (3) a combination of those shares and cash. In addition, in the discretion of the Committee, the exercise price may be paid by delivery to us or our designated agent of an executed irrevocable option exercise form together with irrevocable instructions to a broker-dealer to sell or margin a sufficient portion of the shares of common stock with respect to which the option is exercised and deliver the sale or margin loan proceeds directly to us to pay the exercise price and any required withholding taxes.
Stock Appreciation Rights (SARs). A stock appreciation right entitles the participant to receive an amount in cash and/or shares of Common Stock, as determined by the Committee, equal to the amount by which our common stock appreciates in value after the date of the award. The Committee will determine when the SAR will vest and become exercisable. Generally, the exercise price of a SAR will not be less than the fair market value of the common stock on the date of grant. However, the exercise price may be less if the stock is granted in connection with a transaction and complies with special rules under Section 409A of the Code. No SAR will be exercisable later than ten years after the date of the grant. The Committee will set other terms, conditions, restrictions and limitations on SARs, including rules as to exercisability after termination of employment or service.
Stock Awards. Stock awards are shares of common stock awarded to participants that are subject to no restrictions. Stock awards may be issued for cash consideration or for no cash consideration.
Restricted Stock and Restricted Stock Units (RSUs). Restricted stock is shares of common stock that must be returned to us if certain conditions are not satisfied. The Committee will determine the restriction period and may impose other terms, conditions, and restrictions on restricted stock, including vesting upon achievement of performance goals pursuant to a performance award and restrictions under applicable securities laws. The Committee also may require the participant to pay for restricted stock. Subject to the terms and conditions of the award agreement related to restricted stock, a participant holding restricted stock will have the right to receive dividends on the shares of restricted stock during the restriction period, vote the restricted stock, and enjoy all other shareholder rights related to the shares of common stock. Upon expiration of the restriction period, the participant is entitled to receive shares of common stock not subject to restriction.
Restricted stock units are fictional shares of common stock. The Committee will determine the restriction period and may impose other terms, conditions, and restrictions on RSUs. Upon the lapse of restrictions, the participant is entitled to receive one share of common stock or an amount of cash equal to the fair market value of one share of common stock as provided in the award agreement. An award of RSUs may include the grant of a tandem cash dividend right or dividend unit right. A cash dividend right is a contingent right to receive an amount in cash equal to the cash distributions made with respect to a share of common stock during the period
67
the RSU is outstanding. A dividend unit right is a contingent right to have additional RSUs credited to the participant equal to the number of shares of common stock (at fair market value) that may be purchased with the cash dividends. Restricted stock unit awards are considered nonqualified deferred compensation subject to Section 409A of the Code and will be designed to comply with that section.
Performance Awards. A performance award is an award payable in cash or common stock (or a combination thereof) upon the achievement of certain performance goals over a performance period. Performance awards may be combined with other awards to impose performance criteria as part of the terms of the other awards. For each performance award, the Committee will determine (1) the amount a participant may earn in the form of cash or shares of common stock or a formula for determining the amount payable to the participant, (2) the performance criteria and level of achievement versus performance criteria that will determine the amount payable or number of shares of common stock to be granted, issued, retained and/or vested, (3) the performance period over which performance is to be measured, which may not be shorter than one year, (4) the timing of any payments to be made, (5) restrictions on the transferability of the award, and (6) other terms and conditions that are not inconsistent with the 2006 Plan.
The maximum amount that may be paid in cash pursuant to a performance award each fiscal year is $1 million. If an award provides for a performance period longer than one fiscal year, the limit will be multiplied by the number of full fiscal years in the performance period. The performance measure(s) to be used for purposes of performance awards may be described in terms of objectives that are related to the individual participant or objectives that are company-wide or related to a subsidiary, division, department, region, function or a business unit in which the participant is employed, and may consist of one or more or any combination of the following criteria:
| Earnings or earnings per share (whether on a pre-tax, after-tax, operational or other basis) |
| Accomplishment of mergers, acquisitions, dispositions, public offerings or similar extraordinary business transactions | |||
| Return on equity | | One or more operating ratios | |||
| Return on assets or net assets | | Stock price | |||
| Revenues | | Total shareholder return | |||
| Income or operating income | | Cash flow or EBITDA | |||
| Expenses or costs or expense levels or cost levels | | Net borrowing, debt leverage levels, credit quality | |||
| Return on capital or invested capital or other | or debt ratings | ||||
related financial measures | | Net asset value per share | ||||
| Capital expenditures | | Profit margin | |||
| Economic value added | | Operating profit | |||
| Individual business objectives | | Growth in reserves | |||
| Growth in production | | Finding and development cost per Mcf | |||
| Reserve replacement ratio |
Performance awards may be designed to comply with the performance-based compensation requirements of Section 162(m) of the Code. Section 162(m) of the Code limits our income tax deduction for compensation paid to our Chief Executive Officer and each of our four other highest paid officers to $1 million each year. There is an exception to the $1 million deduction limitation for performance-based compensation. To the extent that awards are intended to qualify as performance-based compensation under Section 162(m), the performance criteria will be established in writing by the Committee not later than 90 days after the commencement of the performance period, based on one or more, or any combination, of the performance criteria listed above. The Committee may reduce, but not increase, the amount payable and the number of shares to be granted, issued, retained or vested pursuant to a performance award. Prior to payment of compensation under a performance award intended to comply with Section 162(m), the Committee will certify the extent to which the performance goals and other criteria are achieved.
Other Incentive Awards. The Committee may grant other incentive awards under the 2006 Plan based upon, payable in or otherwise related to, shares of common stock if the Committee determines that the other incentive
68
awards are consistent with the purposes of the plan. Other incentive awards will be subject to any terms, conditions, restrictions, or limitations established by the Committee. Payment of other incentive awards will be made at the times and in the forms, which may be cash, shares of common stock, or other property, established by the Committee.
New Plan Benefits. The number of awards that will be received by or allocated to our executive officers, independent directors, and employees under the 2006 Plan is undeterminable at this time.
Corporate Change. Unless an award agreement provides otherwise, in the event of a participants involuntary termination of employment or service other than for death, cause, or inability to perform or a voluntary termination for good reason, within one year after a corporate change affecting us (which may include, among others, our dissolution or liquidation, certain reorganizations, a merger or consolidation, the sale of all or substantially all of our assets and our affiliates), any time periods, conditions or contingencies relating to exercise or realization of, or lapse of restrictions under, awards will be automatically accelerated or waived so that (1) if no exercise of the award is required, the award may be realized in full at the time of termination, or (2) if exercise of the award is required, the award may be exercised in full beginning at the time of termination. In addition, to the extent surrender or settlement of awards will not result in negative tax consequences to participants, the Committee may, without consent of a participant, (1) require participants to surrender any outstanding options or stock appreciation rights in exchange for an equivalent amount of cash, common stock, securities of another company or any combination thereof equal to the difference between fair market value of the common stock and the exercise or grant price, or (2) require that participants receive payments in settlement of restricted stock, restricted stock units (and related cash dividend rights and dividend unit rights, as applicable), performance awards or other incentive awards in an amount equivalent to the value of those awards.
Withholding Taxes. All applicable withholding taxes will be deducted from any payment made under the 2006 Plan, withheld from other compensation payable to the participant, or be required to be paid by the participant prior to the making of any payment of cash or common stock under the 2006 Plan. Payment of withholding taxes may be made by withholding shares of common stock from any payment of common stock due or by the delivery by the participant to us of previously acquired shares of common stock, in either case having an aggregate fair market value equal to the amount of the required withholding taxes. No payment will be made and no shares of common stock will be issued pursuant to any award made under the 2006 Plan until the applicable tax withholding obligations have been satisfied.
Transferability. No award may be sold, transferred, pledged, exchanged, or disposed of, except by will or by the laws of descent and distribution. If provided in the award agreement, nonqualified stock options may be transferred by a participant to a permitted transferee. In connection with a divorce, a participant may request that we agree to observe the terms of a domestic relations order with respect to all or part of an award granted to a participant. Our decision regarding such a request will be made by the Committee based upon our best interests. The Committees decision need not be uniform between participants.
Amendment. Our board of directors may suspend, terminate, amend, or modify the 2006 Plan, but may not without the approval of the holders of a majority of the shares of our common stock make any alteration or amendment that operates (1) to increase the total number of shares of common stock that may be issued under the 2006 Plan (other than adjustments in connection with certain corporate reorganizations and other events), (2) to change the designation or class of persons eligible to receive awards under the 2006 Plan, or (3) to effect any change for which stockholder approval is required by or necessary to comply with applicable law or the listing requirements of the Nasdaq National Market or any exchange or association on which our common stock is then listed or quoted. Upon termination of the 2006 Plan, the terms and provisions thereof will continue to apply to awards granted before termination. No suspension, termination, amendment, or modification of the plan will adversely affect in any material way any award previously granted under the 2006 Plan, without the consent of the participant.
Effectiveness. The 2006 Plan became effective in April 2006. Unless terminated earlier, the 2006 Plan will terminate on the day before the tenth anniversary of the effective date.
69
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information as of March 31, 2006 with respect to the beneficial ownership of our common stock by (i) 5% stockholders, (ii) our directors, (iii) our named executive officers, and (iv) our executive officers and directors as a group before this offering and after the completion of this offering.
Unless otherwise indicated in the footnotes to this table each of the stockholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned.
Amount(1) |
Percentage of Shares Beneficially Owned(2) |
||||||||||
Name and Address of Beneficial Owner |
Before Offering |
After Offering |
Before Offering |
After Offering |
|||||||
Yorktown Energy Partners IV, L.P. 410 Park Avenue New York, New York 10022 |
16,202,696 | 14,047,275 | 49.7 | % | 37.2 | % | |||||
W. Howard Keenan, Jr. 410 Park Avenue New York, New York 10022 |
16,202,696 | (3) | 14,047,275 | 49.7 | % | 37.2 | % | ||||
J. Darby Seré 909 Fannin, Suite 3208 Houston, Texas 77010 |
1,440,150 | (4) | 1,248,569 | 4.4 | % | 3.3 | % | ||||
William C. Rankin 909 Fannin, Suite 3208 Houston, Texas 77010 |
1,260,300 | (5) | 1,092,644 | 3.8 | % | 2.9 | % | ||||
Philip G. Malone 5336 Stadium Trace Parkway Suite 206 Birmingham, Alabama 35244 |
887,368 | (6) | 769,324 | 2.7 | % | 2.0 | % | ||||
Brett S. Camp 5336 Stadium Trace Parkway Suite 206 Birmingham, Alabama 35244 |
887,368 | (7) | 769,324 | 2.7 | % | 2.0 | % | ||||
J. Hord Armstrong, III 909 Fannin, Suite 3208 Houston, Texas 77010 |
| | | % | | % | |||||
James C. Crain 909 Fannin, Suite 3208 Houston, Texas 77010 |
| | | % | | % | |||||
Stanley L. Graves 909 Fannin, Suite 3208 Houston, Texas 77010 |
| | | % | | % | |||||
Charles D. Haynes 909 Fannin, Suite 3208 Houston, Texas 77010 |
| | | % | | % | |||||
All executive officers and directors as a group (nine persons) |
20,677,882 | 17,927,136 | 61.4 | % | 46.3 | % |
(1) | Unless otherwise indicated, all shares of stock are held directly with sole voting and investment power. Securities not outstanding, but included in the beneficial ownership of each such person are deemed to be outstanding for the purpose of computing the percentage of outstanding securities of the class owned by such person, but are not deemed to be outstanding for the purpose of computing percentage of the class owned by any other person. The total number includes shares issued and outstanding as of March 31, 2006, plus shares which the owner shown above has the right to acquire within 60 days after the date of this prospectus. |
(2) | For purposes of calculating the percent of the class outstanding held by each owner shown above with a right to acquire additional shares, the total number of shares excludes the shares which all other persons have the right to acquire within 60 days after the date of this prospectus, pursuant to the exercise of outstanding stock options and warrants. |
70
(3) | Represents shares of common stock owned by Yorktown Energy Partners IV, L.P. W. Howard Keenan, Jr. is a member and a manager of the general partner of Yorktown Energy Partners IV, L.P. and may be deemed to beneficially own the shares held by that entity. |
(4) | Includes options to purchase up to 479,960 shares of common stock, which are exercisable within 60 days from the date of this prospectus and 456,000 shares of common stock that are held in an investment limited partnership under the control of Mr. Seré, and for which he holds voting and dispositive power. |
(5) | Includes options to purchase up to 560,040 shares of common stock, which are exercisable within 60 days from the date of this prospectus, and 400,000 shares of common stock that are held in an investment limited partnership under the control of Mr. Rankin, and for which he holds voting and dispositive power. |
(6) | Includes 443,684 shares of common stock held by the spouse of Philip G. Malone. |
(7) | Includes 443,684 shares of common stock held by the spouse of Brett S. Camp. |
71
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
On April 14, 2005, the merger date of our majority-owned subsidiary with and into GeoMet, we issued to each minority interest owner and holder of incentive stock options of our majority-owned subsidiary an option to purchase shares of our common stock at the per share exchange value of $7.64 (the non-dilution option). Within 30 days of issuance, the holder of the non-dilution option could exercise the option to purchase shares of our common stock with cash or a loan from us, up to a certain amount of our shares of common stock to prevent any dilution that resulted from the merger. Notes issued to purchase any stock are full recourse, earn interest at an annual rate of 6%, and mature on the earlier of April 14, 2009 or 60 days after the holder ceases to be an employee or the occurrence of a Triggering Transaction as defined in the non-dilution option agreement. The option holders exercised non-dilution options to purchase 1,456,660 shares of our common stock. The option holders financed the exercise of these options using approximately $10.9 million in notes and $0.2 million in cash. Certain of our executive officers and members of their families held approximately $4.5 million of these notes. All of the loans to our officers and their family members were repaid in full with interest upon the closing of our private equity offering in January 2006, as were all but $400,000 of the loans to others.
On December 8, 2000, GeoMet was formed through the issuance of 7.2 million shares of common stock for $18 million in cash to Yorktown Energy Partners IV, L.P., our controlling stockholder, which is a partnership managed by Yorktown Partners LLC and organized in 1999 to make direct investments in the energy industry on behalf of certain institutional investors, and 800,000 shares of common stock to certain of our executive officers for $400,000 in cash and notes receivable in the amount of $1.6 million under the terms of an agreement between us, Yorktown, and such officers. The notes were issued only to certain executive officers, were full recourse, and accrued interest at an annual rate of 5.87% and were to become due and payable on April 14, 2009, or earlier upon certain circumstances. These loans to our officers were repaid with interest upon the closing of our private equity offering in January 2006.
In 2003, we increased the authorized common stock by 8,000,000 shares and issued 4,000,000 and 8,000,000 shares of common stock on May 19 and September 22, respectively at $2.50 per share, to the existing stockholders in proportion to their original ownership, for cash of $27.3 million and notes receivable of $2.7 million. On April 27, 2004, we issued 4,000,000 shares of common stock at $2.50 per share, to our existing stockholders in proportion to their original ownership, for cash of $9.1 million and notes receivable of $0.9. The notes were issued only to certain executive officers, were full recourse and accrued interest at an annual rate of 5.87% and were to become due and payable on April 14, 2009, or earlier upon certain circumstances. In connection with the closing of our private equity offering in January 2006, all of these loans were repaid in full with interest.
On July 21, 2003, we loaned Mr. Rankin, our chief financial officer, $250,000 to provide liquidity in connection with a divorce settlement so that Mr. Rankin could retain ownership of his shares of common stock. The note was full recourse and accrued interest at an annual rate of 5.87% and was to become due and payable on April 14, 2009, or earlier upon certain circumstances. The loan was repaid in full with interest upon the closing of our private equity offering in January 2006.
72
The following table and related footnotes set forth certain information regarding the selling stockholders. The number of shares in the column Number of Shares of Common Stock Offered Hereby represents all of the shares that each selling stockholder is offering under this prospectus. To our knowledge, each of the selling stockholders has sole voting and investment power as to the shares shown, except as disclosed in this prospectus or to the extent this power may be shared with a spouse. Beneficial ownership as shown in the table below has been determined in accordance with the applicable rules and regulations promulgated under the Exchange Act. Except as noted in this prospectus, none of the selling stockholders is a director or an executive officer of ours or an affiliate of such person.
Selling Stockholders |
Number of Shares of Common Stock Owned Prior to the Offering(1) |
Number of Shares of Common Stock Offered |
Number of Shares of Common Stock Owned After the Offering(1) |
Percentage of Shares of Common Stock Owned After Completion of the Offering | |||||
Yorktown Energy Partners IV, L.P.* |
16,202,696 | 2,155,421 | 14,047,275 | 37.2% | |||||
J. Darby Seré* |
1,440,150 | (2) | 191,581 | 1,248,569 | 3.3% | ||||
William C. Rankin* |
1,260,300 | (3) | 167,656 | 1,092,644 | 2.9% | ||||
Philip G. Malone* |
443,684 | 59,022 | 384,662 | 1.0% | |||||
Connie G. Malone* |
443,684 | 59,022 | 384,662 | 1.0% | |||||
Brett S. Camp* |
443,684 | 59,022 | 384,662 | 1.0% | |||||
Gayla F. Camp* |
443,684 | 59,022 | 384,662 | 1.0% | |||||
The Jeffrey and Charlene Smith Living Trust |
887,365 | 118,045 | 769,320 | 2.0% | |||||
J. Neil Walden, Jr. |
443,684 | (4) | 59,022 | 384,662 | 1.0% | ||||
Floyd H. Briscoe, Jr. |
498,134 | 66,266 | 431,868 | 1.1% | |||||
C. Olivia Pescatore |
443,684 | 59,022 | 384,662 | 1.0% | |||||
Melinda Briscoe |
139,829 | 18,601 | 121,228 | 0.3% | |||||
Franz Froelicher & Margarete Froelicher-Grundman |
46,706 | 6,213 | 40,493 | 0.1% | |||||
Jaime Aramis Arevalo |
54,177 | (5) | 7,207 | 46,970 | 0.1% | ||||
Terry David Burns |
72,861 | (6) | 9,693 | 63,168 | 0.2% | ||||
Cindy R. Lewis |
54,177 | (7) | 7,207 | 46,970 | 0.1% | ||||
William Marshall Young |
54,177 | (8) | 7,207 | 46,970 | 0.1% | ||||
Phillip Dunn |
37,365 |