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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Pinnacle Gas Resources (MM) | NASDAQ:PINN | NASDAQ | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0.321 | 0 | 01:00:00 |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
| ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
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For the fiscal year ended December 31, 2009 |
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OR |
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period from to |
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Commission file no. 001-33457
Pinnacle Gas Resources, Inc.
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of incorporation or organization) |
30-0182582
(I.R.S. Employer Identification No.) |
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1 E. Alger Street Sheridan, Wyoming (Address of principal executive offices) |
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82801 (Zip code) |
Registrant's telephone number, including area code: (307) 673-9710
Securities Registered Pursuant to Section 12(b) of the Exchange Act:
| Title of Each Class | Name of Each Exchange on Which Registered | |
|---|---|---|
| Common Stock | Nasdaq Global Market |
Securities Registered Pursuant to Section 12(g) of the Exchange Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this Chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
| Large Accelerated Filer o | Accelerated Filer o |
Non-Accelerated Filer
o
(Do not check if a smaller reporting company) |
Smaller Reporting Company ý |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
The aggregate market value of the registrant's common stock held by non-affiliates of the registrant was approximately $7,357,503 as of June 30, 2009 (based on a closing price of $0.38 per share). This figure excludes shares of common stock beneficially owned of 10,360,262.
30,320,525 shares of the registrant's common stock were outstanding as of March 30, 2010.
PINNACLE GAS RESOURCES, INC.
Index to Form 10-K
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
We are including the following discussion to inform you of some of the risks and uncertainties that can affect our company and to take advantage of the "safe harbor" protection for forward-looking statements that applicable federal securities law affords. Various statements in this annual report on Form 10-K, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. These include statements relating to such matters as:
When we use the words "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this annual report on Form 10-K speak only as of the date of this report. We disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
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When you consider these forward-looking statements, you should keep in mind these factors and the other factors discussed under the "Risk Factors" section of this annual report on Form 10-K for the year ended December 31, 2009.
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PART I
ITEMS 1 AND 2 BUSINESS AND PROPERTIES
General
Pinnacle Gas Resources, Inc. (Pinnacle), is an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. We primarily focus our efforts on the development of coalbed methane, or CBM, properties located in the Rocky Mountain region, and we are a substantial holder of CBM acreage in the Powder River Basin. We have assembled a large, predominantly undeveloped CBM leasehold position, which we believe positions us for significant long-term growth in production and proved reserves. In addition, we own approximately 90% of the rights to develop conventional and unconventional oil and natural gas in zones below our existing CBM reserves. Substantially all of our undeveloped acreage as of December 31, 2009 was located in the northern end of the Powder River Basin in northeastern Wyoming and southern Montana.
As of December 31, 2009, we owned natural gas and oil leasehold interests in approximately 424,000 gross (308,000 net) acres, approximately 90% of which were undeveloped. At December 31, 2009, we had estimated net proved reserves of 15.0 Bcf, based on the first day of the month, twelve month average Colorado Interstate Gas, or CIG, index price of approximately $3.04 per Mcf. These net proved reserves were located on approximately 10% of our net acreage. Based on our drilling results to date, analysis of drilling logs and third-party results in adjacent areas, we believe that our remaining undeveloped CBM acreage has substantial commercial potential. None of our acreage or producing wells is associated with coal mining operations.
As of December 31, 2009, we owned interests in 571 gross (319 net) producing wells and operated 97% of these wells. During the year ended December 31, 2009, we drilled 1 gross (1 net) well and produced an average of 7.6 MMcf per day net to our interest. During 2008, we drilled 117 gross (82 net) wells and produced an average of 10.6 MMcf per day net to our interest.
The continued credit crisis and related turmoil in the global financial system have had an adverse impact on our business and financial condition. In addition, the price of natural gas declined significantly in 2008 and has remained low in 2009. Therefore, total capital expenditures were limited to $4.2 million in 2009. As a result of low CIG index prices, the economic climate and our limited capital resources, we expect to continue operating during 2010 with a reduced capital expenditure plan. Under our plan, we will generally make expenditures only as necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. Our capital expenditure budget for 2010 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources. On February 23, 2010, Pinnacle Gas Resources, Inc. entered into a merger agreement with Powder Holdings, LLC (please see Note 19).
Our Powder River Basin and Green River Basin CBM Projects
During the period from our formation in June 2003 to December 31, 2009, we completed 777 gross (435 net) of the 818 gross (469 net) CBM wells that were drilled in the Powder River and Green River Basins. As necessary infrastructure becomes available, we expect to complete the remaining gross wells drilled through December 31, 2009.
Powder River Basin
Our Powder River Basin properties are located in Wyoming and Montana. Our acreage position in the northern end of the Powder River Basin is generally contiguous, providing us with critical mass and the ability to execute large-scale development projects in our operating areas.
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Green River Basin
On April 20, 2006, we acquired undeveloped natural gas properties, including related interests and assets, located in the Green River Basin of Wyoming from Kennedy Oil for an aggregate purchase price of approximately $27.0 million in cash. Our Green River Basin properties are located in the northeast area of Sweetwater County, Wyoming. As of December 31, 2009, our properties in the Green River Basin consisted of approximately 33,000 gross (32,000 net) undeveloped acres for prospective CBM development in the Fort Union Big Red Coal formation. As of December 31, 2009, we operated 100% of this acreage. As part of our initial acquisition, we also acquired 20 shut-in wells and 23 approved drilling permits and a 65% working interest in existing deep rights below the base of the Fort Union formation. We have begun developing a water management system for the Green River Basin areas. We are currently waiting on approval of our water management plan from the Wyoming Bureau of Land Management which we expect to receive in late 2010. It is more expensive to drill in the Green River Basin because of the increased depth of the wells, the increased cost of water management in the area and the need for additional infrastructure.
As of December 31, 2009, we had 14 approved drilling permits for our Green River Basin properties. We are in the process of applying for an additional 16 drilling permits which we expect to be approved in 2010. In addition, we are in the process of applying for 34 drilling permits for conventional wells, which we expect to be approved in 2010. As of December 31, 2009, we had no proved reserves established in our Green River Basin properties.
Summary of Our Powder River and Green River Basin Properties
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Producing
Wells as of December 31, 2009 |
Producing
Wells as of December 31, 2008 |
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Estimated
Total Net Acres(1) |
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Gross | Net | Gross | Net | |||||||||||||
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Powder River Basin |
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Recluse |
341 | 166 | 427 | 209 | 16,000 | ||||||||||||
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Cabin Creek |
142 | 95 | 156 | 104 | 38,000 | ||||||||||||
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Kirby |
22 | 14 | 23 | 15 | 43,000 | ||||||||||||
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Deer Creek |
66 | 44 | 57 | 38 | 41,000 | ||||||||||||
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Bear Creek |
0 | 0 | 0 | 0 | 64,000 | ||||||||||||
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Bradshaw |
0 | 0 | 0 | 0 | 69,000 | ||||||||||||
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Other |
0 | 0 | 0 | 0 | 5,000 | ||||||||||||
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Green River Basin |
0 | 0 | 0 | 0 | 32,000 | ||||||||||||
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Total |
571 | 319 | 663 | 366 | 308,000 | ||||||||||||
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Our History
We were formed as a Delaware corporation in June 2003 by funds affiliated with DLJ Merchant Banking III, Inc., which we refer to collectively as DLJ Merchant Banking, and subsidiaries of Carrizo Oil & Gas, Inc., or Carrizo, and U.S. Energy Corporation, or U.S. Energy. Carrizo and U.S. Energy contributed oil and gas reserves and leasehold interests in approximately 81,000 gross (40,000 net) acres in exchange for shares of our common stock and options to purchase shares of our common stock. DLJ Merchant Banking completed several cash investments in us in exchange for shares of our common stock, Series A Redeemable Preferred Stock, and warrants to purchase additional shares of our common stock, and has been instrumental in providing capital to drive our growth. As of December 31, 2009, DLJ Merchant Banking and Carrizo owned approximately 32.3% and 8.4% of our outstanding common stock, respectively.
In April 2006, we completed a private offering of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors. Immediately prior to the initial closing of our private placement, DLJ Merchant Banking exchanged all of their warrants for 6,894,380 shares of common stock in a tax-free reorganization and each of Carrizo and U.S. Energy entered into a cashless exercise of all of their options for 584,102 shares of common stock, in each case based on the private placement price of $11.00 per share. Following the initial closing of our private placement, we redeemed all of the outstanding shares of Series A Redeemable Preferred Stock held by DLJ Merchant Banking with a portion of the proceeds we received in the private placement. In addition, following the final closing of our private placement, we used a portion of the proceeds we received in the private placement to repurchase an aggregate of 1,587,598 shares of common stock from DLJ Merchant Banking at a price per share equal to the private placement price of $11.00 per share less the initial purchaser's discount and placement fee. On September 22, 2006, DLJ Merchant Banking purchased all of the 2,459,102 shares of our common stock held by U.S. Energy and its affiliates in a private transaction.
In May 2007, we completed an initial public offering of 3,750,000 shares of our common stock at a public offering price of $9.00 per share.
In addition to the initial contribution of leasehold interests to us by U.S. Energy and Carrizo, during the period from our formation in June 2003 to December 31, 2009, we acquired leasehold interests covering approximately 343,000 gross (268,000 net) acres, primarily from three significant acquisitions:
Please see the information under the heading "Our Powder River Basin and Green River Basin CBM Projects—Green River Basin" in this annual report.
Capital Expenditure Plan
The continued credit crisis and related turmoil in the global financial system have had an adverse impact on our business and financial condition. In addition, the prices of oil and natural gas declined significantly in 2008 and have remained low in 2009. During the year ended December 31, 2009, we drilled 1 gross (1) net well. We curtailed substantially all new drilling in 2009, and we have shut-in a
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number of wells that are not economic at current natural gas price levels. If natural gas prices remain low, we expect to continue to operate with a reduced capital expenditure plan. Under our reduced capital expenditure plan, we would generally make such expenditures only as necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. The CIG index price has been extremely volatile during 2008 and 2009 and at times reached unusually low levels. For instance, the CIG monthly index price per Mcf was $1.33 on April 14, 2009 and $5.75 on December 30, 2009. If we do not have sufficient cash flows and cannot obtain capital through our credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves and maintain production levels could be greatly limited. If natural gas prices do not improve, we will consider alternatives to increase liquidity, including asset sales and issuances of equity. Our capital expenditure budget for 2010 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources. For a discussion of our credit facility and other matters that may limit our ability to execute our 2010 capital expenditure plan, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity—Credit Facility."
Throughout 2009, we actively marketed certain assets to raise additional capital and are also reviewing alternatives for raising additional capital through equity and debt financing, capital restructuring and possible mergers (please see Note 19 in the notes to the audited financial statements). We sold our high pressure gas gathering system in our Cabin Creek project area in Wyoming and our remaining interest in the Arvada project area in Wyoming in April 2009. In addition, we entered into a Merger Agreement dated February 23, 2010 (please see Note 19 in the notes to the audited financial statements). Although we are pursuing various alternatives to provide additional liquidity, there is no assurance of the likelihood or timing of any of these transactions.
Overview of the CBM Industry and the Powder River Basin
CBM is natural gas that is trapped within buried coal and is stored, or adsorbed, onto the internal surfaces of the coal. Geologists have long known that coal was the source for natural gas found in many conventional accumulations, but coalbeds were not targeted for production due to high water content and minimal natural gas production. Following a West Virginia mine explosion in 1968, the U.S. Bureau of Mines began to examine ways of removing methane from coal prior to mining. The Bureau of Mines demonstrated that CBM can be produced when large volumes of water are pumped from a coal seam. In a process known as dewatering or depressuring, a submersible pump is set below the coal seam, and the water column is pumped down, reducing the pressure in the coals. As pressure within the coalbed formation is reduced, CBM is released through a process called desorption. CBM then moves into naturally occurring cracks, or cleats, in the coal, and then to the production wells. Cleats are natural fractures which have formed in the coals, usually as a result of the coalification process and geological stresses. Because the cleats are generally filled with water, the static water level above the coal must be reduced, which then lowers the reservoir pressure allowing desorption to occur. Thus, unlike producing from a conventional natural gas reservoir, reservoir pressure in a coalbed formation must generally be reduced to allow for production of CBM. Because of the necessity to remove water and reduce the pressure within the coal seam, CBM, unlike conventional hydrocarbons, often will not show immediately on initial production testing. Coalbed formations typically require extensive dewatering and depressuring before desorption can occur and the methane begins to flow at commercial rates.
In the past 20 years, CBM in the United States has evolved into a major component of the United States natural gas production. According to the US Energy Information Administration, CBM provides approximately 9% of daily natural gas production in the United States. The Rocky Mountain region, due to its immense coal reserve base, is a significant source of United States CBM production, and there are more than 26,000 CBM wells in the Powder River Basin. The primary CBM basins include the San Juan, Green River, Raton, Powder River and Uinta Basins in the western United States.
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Future CBM production is expected to increase substantially due to the economic viability of the resources and the tremendous reserve potential of the numerous, virtually undeveloped U.S. coal basins. Within the Rocky Mountain region, the Powder River Basin has become a major CBM producing basin. According to the U.S. Department of Energy 2002 Powder Basin Coalbed Methane Development and Produced Water Management Study, the Montana portion of the Powder River Basin is estimated to have substantial recoverable reserves. According to the Wyoming Oil and Gas Conservation Commission, approximately 1.3 Bcf of CBM has been produced from the Powder River Basin per day in 2009.
The Powder River Basin is an asymmetrical structure and sedimentary basin bounded by the Bighorn and Black Hills uplift and the Casper Arch. The Paleocene Fort Union formation crops out along the basin margin and is overlain by the Eocene Wasatch formation in the central and western part of the basin. The Wasatch and Fort Union formations contain numerous coalbeds, some of which approach 250 feet in total thickness. The Fort Union formation is divided, in ascending stratigraphic order, into the Tullock, Lebo, and Tongue River members, with the majority of coal and CBM production being produced from the Tongue River member.
The majority of Powder River Basin CBM reserves are found in the Fort Union formation. Extensive drilling in the Fort Union formation has provided supporting data indicating that this formation contains numerous coalbeds which are generally continuous, extremely permeable and relatively shallow (less than 1,000 feet deep) and low in rank (geologic maturity) compared to other coals in the Rocky Mountains.
Drilling and Production
CBM wells in the Powder River Basin are drilled with small truck mounted water well rigs and are drilled and completed using two basic completion techniques. The first and most common drilling technique is open hole completion. The well is drilled to the top of the target coal seam and production casing is set and cemented back to the surface. The coal seam is then drilled out and under-reamed to open up more coal face to production. The second completion technique is to drill through the base of the target coal and then set casing and cement to the surface. The well is then completed by perforating the casing at the target coal. In completion techniques, the borehole and coal face are then cleaned out and flushed by pumping approximately 600 barrels of formation water at high rates into the coal face. Once the well is completed, a submersible pump is run into the well on production tubing to pump the water from the coal seam. After the coal is depressurized, gas flows up the casing to the wellhead. At the wellhead, the gas and water are metered. The gas then flows to a central compressor station where it is compressed into a high-pressure pipeline. The water is sent through an underground pipeline for beneficial use or disposal. CBM production must be continuous to ensure a constant low-pressure gas flow and to sustain a commercially viable operation.
We have developed specific drilling, cementing and completion technology that we have adapted to the rank, depth and thickness of the coals found in all of our operating areas. Our drilling, completion and production practices utilize technological advances in cementing, multiple zone completions and programmable submersible pumps. We have developed drilling and cementing techniques that minimize the damage to coal zones, preserve the potential of coals behind pipe and reduce cementing costs. Multiple zone completions allow for the successful perforation of multiple zones which reduces costs and gives us the ability to sustain production from coals less than ten feet in thickness. Programmable submersible pumps and telemetry allow us to implement aggressive production management programs on our wells and projects.
Conventional gas wells are typically 8,000 to 20,000 feet deep and initially produce large volumes of gas relative to water. Natural gas normally does not require assistance to move to the surface, and over time, gas production declines and water production may increase. In contrast, CBM wells generally range from 300 to 4,000 feet. In the early stages of CBM production, large quantities of water and low
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quantities of gas are produced. Water production is initiated to lower the downhole pressure which allows the methane to release from the coal. The water volumes eventually decline and gas quantities begin to rise. In most cases, assistance to bring the gas to surface is not needed for the final period of production.
Water Production and Management
Water production and disposal is a key issue in CBM development. CBM-produced water in Wyoming and Montana must have a beneficial use, which is generally defined as using the water for agricultural, irrigation, commercial, domestic, industrial, municipal, mining, hydropower production, recreational, stock watering and fisheries, wildlife and wetlands maintenance purposes or dust suppression. Currently, the management of CBM-produced water depends on the quality of the produced water. The water produced in CBM operations can vary from very high quality (meeting state and federal drinking standards) to very low quality (having a very high concentration of dissolved solids, making it unsuitable for reuse). Testing of the produced water determines the disposal method.
Produced water is handled by utilizing one or several of the following approved methods:
We include water gathering and water disposal costs in our hook-up, infrastructure and water management cost estimate of between $62,000 and $109,000 per well depending on the location and the number of wells drilled on an 80-acre spacing unit.
Recovery Characteristics
The primary variables that affect recovery of CBM are coal thickness, gas content and permeability. Coal thickness refers to the actual thickness of the coal layer and is used to estimate how many tons of coal underlies a section of land. The estimate of the number of tons per section is multiplied by the estimated gas content of such lands to estimate the gas in place for the section. Gas content in coal is measured in terms of standard cubic feet per ton. Sufficient coal permeability is a prerequisite for economic gas flow rates because gas and water must be able to flow to the wellbore. Most gas and water flow through the cleats and other fractures in the coal. Cleat spacing is influenced by a variety of factors and greatly affects permeability.
Powder River Basin CBM Production Overview
The Powder River Basin is located in northeastern Wyoming and southern Montana. The Powder River Basin is rich in natural resources with significant reserves of oil and gas as well as some of the world's thickest coal seams. The Powder River Basin holds the distinction of being the leading coal-producing area in the United States, and in recent years, has become one of the most active areas for oil and gas drilling.
We target an average of three coal seams per location and have up to five coal seams that we believe are capable of commercial production. We expect that many of our wells will be completed to more than one coal seam, and thus we may drill less than three wells per location. The coal seams that
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we target are part of the Fort Union formation and include the Canyon, Cook, Wall, Pawnee and Flowers-Goodale (the Roberts equivalent) coals, which are found at depths ranging from 200 to 1,500 feet and are each approximately 15 to 60 feet thick.
Our wells generally reach total depth in one day and cost between $95,000 and $122,000 per well to drill and complete, depending on location, coal zones perforated and depth. Hook-up, infrastructure and water management costs are between $62,000 and $71,000 per well in the Powder River Basin. Powder River CBM wells are drilled with small truck mounted water well rigs and are completed as either single or multiple zone producers. In a single coal completion, we top set the casing in the first foot of coal and complete the well by under-reaming the coal with a 12-inch diameter tool. In a multiple zone completion, we typically top set and under-ream the deepest coal seam and perforate the upper coal seams sequentially. Our general production profile for a CBM well shows production of water for 30 to 90 days prior to initial gas production. The lowering of the static water level reduces the coal formation pressure and allows the gas to desorb from the coal and migrate to the well bore. Gas production typically inclines steeply for an average of nine months, peaking at an average of over 100 Mcf per day. A period of relatively flat production at peak continues for three to four months and then declines at an annual rate of approximately 35% over a five to seven year period. Produced water is handled by discharging it through one or more of several approved methods.
Our CBM wells in the Powder River Basin have all been drilled and cemented in anticipation of completing more than one coal seam per well bore. In our project areas, depending on the thickness of and horizontal separation between coal seams, we generally complete several coals in one well upon initial hook-up. Coal seams thicker than 25 feet are initially drilled as stand alone wells. Coal seams with less than 100 feet of vertical separation are completed simultaneously at initial hook-up. Our development activities include an active program to sequentially complete upper coal seams in wells that are producing from a single coal seam since being initially drilled and completed. We presently have over 150 wells that have been identified in the Recluse area for further completions in upper coals. Our completion strategy generally is to wait for the lower coal zones' measured pressure to reach or equal the measured pressure of the upper zones. Once the measured pressures are determined to be equal, the upper zones are perforated and completed. Sequential completion of upper coal seams typically costs $14,000 per coal seam. We expect that multiple zone completions can increase the economic life of a well, increase previously unbooked behind pipe reserves from several thinner coal seams and enhance our rate of return.
Green River Basin CBM Production Overview
The Green River Basin is primarily located in southwestern Wyoming, and our assets are located in the eastern half of the Wyoming portion of the Green River Basin. According to the U.S. Department of Energy 2004 Coal Bed Methane Primer, the Green River Basin has significant potential CBM reserves in place. The Green River Basin is an increasingly active basin for natural gas and CBM exploration and drilling. Our Green River Basin acreage position is offset by multiple fields producing from conventional reservoirs in the Lance, Lewis and Almond sandstones. In 2009, there were approximately 31 CBM projects in the eastern half of the Green River Basin with a total of 176 CBM wells drilled. These projects are being developed by approximately 13 operators targeting coals in the Mesaverde, Fort Union and Wasatch formations.
The Fort Union Big Red Coal, which we are targeting, is found at depths between 2,500 to 6,500 feet. The Fort Union coals, including the Big Red Coal, aggregate approximately 100 feet in thickness. The Big Red Coal accounts for up to 50 feet of the thickness. The Fort Union coals on our acreage have excellent permeability and gas saturation of generally 200 to 400 scf per ton of coal. In addition to the Big Red Coal, CBM potential exists in other coals of the Fort Union formation and in coals in the Wasatch and Mesaverde formations.
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We anticipate developing the Green River Basin CBM reserves primarily on 160-acre spacing. The 14 gross (14 net) wells drilled as of December 31, 2009 on the acreage have generally reached total depth in five days. We estimate that future wells will cost an average of $787,000 to drill, complete and hook up. We intend to complete the wells by under-reaming the coal or drilling through the coal and perforating the coal formation. Our estimated production profile assumes little gas production for three to five months as the well is dewatered and the formation pressure lowered, a steep incline in production for the following 12 months, peak production for 18 to 24 months and then a slow decline in production of approximately 10% per year over a 20 to 25 year period. We estimate the standard reserve life of a well in the Green River Basin will be approximately 25 years.
Operations
CBM Development, Projects and Operations
Our properties in the Powder River Basin are primarily located in northeastern Wyoming and southern Montana and are generally contiguous, providing us with critical mass and the ability to execute large scale development projects in our operating areas. As of December 31, 2009, we owned leasehold interests in approximately 391,000 gross (276,000 net) acres in the Powder River Basin, approximately 97% of which we operated. As of December 31, 2009, we also owned leasehold interests in 33,000 gross (32,000 net) acres in the Green River Basin in Wyoming.
Most of our development drilling is in areas of known natural gas reserves and involves much lower risk than the exploratory type of drilling that is required when searching for new natural gas reserves. During the period from our formation in June 2003 to December 31, 2009, we completed 777 gross (435 net) of the 818 gross (469 net) CBM wells we drilled in the Powder River and Green River Basins. As necessary infrastructure becomes available, we expect to complete the remaining gross wells drilled through December 31, 2009. During the year ended December 31, 2009, we drilled 1 gross (1 net) well. During the year ended December 31, 2008, we drilled 117 gross (82 net) wells and connected 110 gross (77 net) wells to our low-pressure gathering system. At December 31, 2009, we were producing natural gas from approximately 571 gross (319 net) CBM wells at a net rate of 7.6 MMcf per day. The continued credit crisis and related turmoil in the global financial system have had an adverse impact on our business and financial condition. In addition, the prices of oil and natural gas declined significantly in 2008 and have remained low in 2009. Therefore, total capital expenditures were limited to $3.7 million in 2009. As a result of low CIG index prices, the economic climate and our limited capital resources, we expect to continue operating during 2010 with a reduced capital expenditure plan. Under our plan, we will generally make expenditures only as necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. Our capital expenditure budget for 2010 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources.
Our drilling locations target the Canyon, Cook, Wall, Pawnee and Flowers-Goodale (the Roberts equivalent) coal seams in the Powder River Basin, which are found at depths ranging from 200 to 1,500 feet, and the Fort Union Big Red Coal in the Green River Basin, which is found at depths ranging from 2,500 to 6,500 feet. Each coal seam is approximately 15 to 60 feet thick. As of December 31, 2009 and based on the first day of the month, twelve month average CIG index price of approximately $3.04 per Mcf, Netherland, Sewell & Associates, Inc., or NSAI, had identified over 900 economic completions, consisting of 494 proved, 125 probable and 316 possible, across our approximately 5,010 drilling locations, assuming one coal seam per well. We expect that many of our wells will be completed to more than one coal seam.
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Wyoming—Powder River Basin
Our principal Wyoming properties in the Powder River Basin are located in two distinct project areas: Recluse and Cabin Creek. As of December 31, 2009, we held approximately 96,000 gross (59,000 net) acres in the Powder River Basin in Wyoming for prospective CBM development and we operated over 96% of this acreage.
Approximately 52% of our gross acreage in the Powder River Basin in Wyoming is on U.S. federal land, and is subject to additional regulations not applicable to state or fee leases. Permitting new wells in Wyoming on federal land involves submitting a plan of development, or POD, to the Wyoming division of the United States Bureau of Land Management, or Wyoming BLM, and is subject to an environmental assessment and a review period. Typically, it takes three to six months to complete the permitting process and receive approval from the Wyoming BLM. Permitting new wells on state and fee land requires approval from the Wyoming Oil and Gas Conservation Commission and the approval process typically takes 30 to 60 days. Please see the information under the heading "Regulations—Permitting Issues for Federal Lands" in this section of this annual report for further information.
As of December 31, 2009, we had 257 approved drilling permits for our Wyoming properties in the Powder River Basin and we are in the process of applying for an additional 302 drilling permits which we expect to be approved in 2010 and 2011.
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Montana—Powder River Basin
Our Powder River Basin properties in Montana are located in four project areas: Kirby, Deer Creek, Bear Creek and Bradshaw. As of December 31, 2009, we held approximately 295,000 gross (217,000 net) acres in Montana for prospective CBM development and we operated 100% of this acreage. During the year ended December 31, 2009, we drilled 1 gross (1 net) wells in these areas.
Because CBM development in Montana is still in its early stages, the permitting process is not as streamlined in Montana as it is in Wyoming. Permitting new wells in Montana on federal land involves submitting a plan of development, or POD, which typically covers approximately 30 to 100 80-acre locations, to the Montana division of the United States Bureau of Land Management, or Montana BLM, and is subject to an environmental evaluation under the National Environmental Policy Act and a review period. Permitting new wells on state and fee land involves submitting a POD, which typically covers 25 to 100 80-acre locations, to the Montana Oil and Gas Conservation Commission, and is also subject to an environmental evaluation under the National Environmental Policy Act and a review period. An injunction which prohibited the Montana BLM from approving any CBM drilling permits in certain federal lands in the Montana portion of the Powder River Basin was lifted in December 2008. The primary lease term of federal acreage covered by the injunction was suspended during the time period that the injunction was in effect. The suspension will add an additional three to five years to the primary term depending on the origination date of all affected federal leases. Fee and state permits were unaffected by the injunction. Approximately 69% of our gross acreage in Montana is on U.S. federal land. Prior to the issuance of the injunction, the permit approval process for federal lands typically took about one to two years. The permit approval process for fee and state lands typically takes three to six months. See "—Regulations—Permitting Issues for Federal Lands" for further discussion of the Montana federal permitting process and injunction.
As of December 31, 2009, we had 32 approved drilling permits for our Montana properties. We are in the process of applying for an additional 238 drilling permits, 123 of which are on federal lands and 115 of which are on state or fee lands. We expect these permits to be approved from 2010 through 2012. We are currently evaluating drilling plans for 2010 in light of the current economic and gas pricing environment.
As of December 31, 2009, we had approximately 2.8 Bcf of net proved reserves in Kirby based on the first day of the month, twelve month average CIG index price of approximately $3.04 per Mcf.
We acquired this acreage as part of the acquisition of properties from Marathon Oil Corp. in March 2005 and we operate 100% of the acreage. We began development in 2005 in the Dietz
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POD which is located in the Deer Creek area just to the southeast of Kirby. As of December 31, 2009, we were producing approximately 0.1 gross (0.0 net) MMcf per day from approximately 66 gross (44 net) wells in this area. During the year ended December 31, 2009 there were no wells drilled. We transport our Deer Creek gas production through the Bitter Creek Pipeline.
As of December 31, 2009, we had 0.5 Bcf of proved reserves in Deer Creek. Approximately 79% of our gross acreage in Deer Creek is on U.S. federal land.
As of December 31, 2009, we had no proved reserves in Bear Creek. Approximately 89% of our gross acreage in Bear Creek is on U.S. federal land, and as of December 31, 2009, we had no drilling permits for Bear Creek.
As of December 31, 2009, we had no proved reserves in Bradshaw. Approximately 81% of our gross acreage in Bradshaw is on U.S. federal land, and as of December 31, 2009, we had no drilling permits for Bradshaw.
Wyoming—Green River Basin
On April 20, 2006, we acquired undeveloped natural gas properties, including related interests and assets, located in the Green River Basin of Wyoming from Kennedy Oil. The initial acquisition included approximately 30,000 gross (29,000 net) undeveloped acres for prospective CBM development in the Fort Union Big Red Coal formation. As of December 31, 2009, we owned 33,000 gross (32,000 net) undeveloped acres and we operated 100% of this acreage. As part of the acquisition, we also acquired 20 shut-in wells and 23 approved drilling permits and a 65% working interest in existing deep rights below the base of the Fort Union formation. As of December 31, 2009, we had drilled 14 gross (14 net) wells. As of December 31, 2009, we had 14 approved permits for our Green River Basin properties. We are in the process of applying for an additional 16 drilling permits which we expect to be approved in 2010. In addition, we are in the process of applying for 34 drilling permits for conventional wells which we expect to be approved in 2010. As of December 31, 2009, we had no proved reserves in the Green River Basin.
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Exploration & Production Activities
Producing Wells and Acreage
The following table sets forth certain information regarding our ownership of productive wells and total acreage as of December 31, 2007, 2008 and 2009. For purposes of this table, productive wells are wells producing gas or dewatering.
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Approximate Leasehold Acreage | ||||||||||||||||||||||
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Productive Wells | Developed | Undeveloped | Total | |||||||||||||||||||||
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Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||
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December 31, 2007 |
634 | 342 | 33,120 | 22,200 | 460,880 | 293,800 | 494,000 | 316,000 | |||||||||||||||||
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December 31, 2008 |
663 | 366 | 47,000 | 31,800 | 430,000 | 300,200 | 477,000 | 332,000 | |||||||||||||||||
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December 31, 2009 |
571 | 319 | 47,080 | 31,850 | 376,920 | 276,150 | 424,000 | 308,000 | |||||||||||||||||
Lease Expirations
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Expiring Acres 2010(1) | Expiring Acres 2011(1) | Held by Production | Suspended | ||||||||||||||||||||||
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Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
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Wyoming |
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Recluse |
200 | 100 | 0 | 0 | 33,975 | 15,847 | 0 | 0 | ||||||||||||||||||
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Cabin Creek |
40 | 11 | 0 | 0 | 28,540 | 18,599 | 0 | 0 | ||||||||||||||||||
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Green River Basin |
640 | 640 | 10,560 | 10,560 | 9,460 | 9,460 | 6,062 | 5,582 | ||||||||||||||||||
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Montana |
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Bear Creek |
6,559 | 3,692 | 0 | 0 | 1,120 | 800 | 0 | 0 | ||||||||||||||||||
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Deer Creek |
2,409 | 2,107 | 520 | 260 | 6,421 | 4,656 | 0 | 0 | ||||||||||||||||||
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Bradshaw |
11,729 | 6,079 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||
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Kirby |
480 | 155 | 0 | 0 | 24,404 | 11,990 | 0 | 0 | ||||||||||||||||||
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Totals |
22,057 | 12,784 | 11,080 | 10,820 | 103,920 | 61,352 | 6,062 | 5,582 | ||||||||||||||||||
We were also granted suspension of certain state and federal leases in the Green River Basin totaling 6,062 gross (5,582 net) acres. The suspensions were requested primarily due to a lack of necessary infrastructure for well dewatering and gas transportation. In addition, the suspensions were granted pending approval of certain surface containment and discharge options by the BLM as well as completion of the BLM's environmental assessment of the Red Desert watershed area.
Natural Gas Reserves
The following table summarizes the reserve estimate and analysis of net proved reserves of natural gas as of December 31, 2007, 2008 and 2009, in accordance with SEC guidelines. The data for the periods listed was prepared by NSAI in Dallas, Texas. The present value of estimated future net
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revenues from these reserves was calculated on a non-escalated price basis discounted at 10% per year. As of December 31, 2009, there were no proved reserves related to our Green River Basin assets.
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As of December 31, | |||||||||||
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2007 | 2008 | 2009 | |||||||||
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Estimated net proved reserves: |
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Proved developed producing (MMcf) |
7,442 | 10,465 | 5,047 | |||||||||
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Proved developed non-producing (MMcf) |
3,016 | 4,947 | 6,234 | |||||||||
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Total proved developed (MMcf) |
10,458 | 15,412 | 11,281 | |||||||||
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Proved undeveloped (MMcf) |
15,263 | 12,307 | 3,673 | |||||||||
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Total proved reserves (MMcf) |
25,721 | 27,719 | 14,954 | |||||||||
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Future cash flows before income taxes (in millions) |
$ | 65.0 | $ | 47.3 | $ | 11.6 | ||||||
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Standardized measure (in millions)(1) |
$ | 38.6 | $ | 32.1 | $ | 7.6 | ||||||
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Price used for computing reserves(2) |
$ | 6.040 | $ | 4.605 | $ | 3.035 | ||||||
Summary of Well Activity
Our drilling, recompletion, abandonment and acquisition activities for the periods indicated are shown below:
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Year Ended December 31, | |||||||||||||||||||
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2007 | 2008 | 2009 | |||||||||||||||||
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Gross | Net | Gross | Net | Gross | Net | ||||||||||||||
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Wells Drilled: |
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Capable of Production |
87 | 61 | 117 | 82 | 1 | 1 | ||||||||||||||
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Dry |
0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
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Wells Acquired |
0 | 0 | 3 | 3 | 0 | 0 | ||||||||||||||
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Wells Abandoned |
1 | 1 | 16 | 9 | 53 | 38 | ||||||||||||||
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Net Increase (decrease) in Capable wells |
86 | 60 | 104 | 76 | (52 | ) | (37 | ) | ||||||||||||
We had no exploratory wells as of December 31, 2009. We are currently evaluating drilling plans for 2010 in light of the current economic and gas pricing environment.
Gas Gathering, Transportation and Compression
We have constructed and plan to continue to construct additional low-pressure gas gathering systems to transport natural gas from the wellhead to compression stations as part of the completion of a well. As of December 31, 2009, we owned and operated approximately 295 miles of low-pressure gas gathering pipelines primarily in the Recluse and Cabin Creek areas of Wyoming. We use third-party services to compress and transport our natural gas to market in return for compression and transportation fees.
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We use Anadarko Petroleum Corporation ("Anadarko") for compression and transportation services in our Squaw Creek area of the Recluse Prospect and Clear Creek Energy Services, LLC ("CCES") for compression services in the Ring of Fire area of our Recluse Prospect. We have constructed the low-pressure gathering infrastructure to the inlet of the compression facilities for both the Squaw Creek and Ring of Fire areas. Both Anadarko and CCES charge a fee plus allocated fuel for compressing our gas. Anadarko transports our gas to Glenrock on the Fort Union Gas Gathering Line where we take title to the gas and have the ability to sell the gas to a third party purchaser or to Anadarko. CCES delivers our gas to us at the outlet of their compression facilities where we have the ability to sell the gas to a third party purchaser. Gas at the tailgate of CCES' compression facility can move north on Grasslands Pipeline or south on Thunder Creek Gas Gathering System.
We have a low-pressure gas gathering agreement and a high-pressure gathering and compression agreement with Bitter Creek Pipelines, LLC for the Kirby and Deer Creek prospects. Under the low-pressure gas gathering agreement, Bitter Creek Pipelines constructed a central compression site to compress a maximum daily quantity of gas for delivery into Bitter Creek's Pipelines' high-pressure gathering line in exchange for a gathering payment comprised of a commodity rate based on average daily volumes and monthly demand charges based on the number of compression sites and compressors. Pursuant to the high-pressure gas gathering agreement, Bitter Creek Pipelines transports a maximum daily quantity of our gas on its high-pressure line in exchange for a demand fee, gathering rate and processing service fee, as applicable. The rates under these agreements will be adjusted annually for inflation. The Bitter Creek Pipelines high-pressure line delivers our gas to the Bitter Creek Landeck Compressor Station for redelivery north into Williston Basin Interstate Pipeline Company and/or south into Thunder Creek Gas Services, LLC and any other future delivery points on the Bitter Creek Pipelines system. The Bitter Creek Pipelines pipeline and compression facilities became operational in late August 2006. The low-pressure gas gathering agreement has an initial term of ten years, and the high-pressure gas gathering agreement has an initial term of five years, in each case, from August 28, 2006, the effective date of the agreements. Each gas gathering agreement will be automatically renewable after the initial term on a month-to-month basis, unless terminated by either party upon 60 days notice. In addition, after five years, if Bitter Creek Pipelines determines that it is no longer economically feasible to provide services under the low-pressure gas gathering agreement, it may terminate the low-pressure gas gathering agreement in its sole discretion with 60 days written notice.
Pursuant to a gas gathering agreement, we utilize Cantera Gas Holdings, LLC to gather and compress our gas in the Cabin Creek area. We have connected this area to the Big Horn Gas Gathering Pipeline, which takes our gas to multiple outlets. Pursuant to construction and field operation agreement between us and Bighorn Gas Gathering, L.L.C., a subsidiary of Cantera Natural Gas, Bighorn Gas Gathering is constructing and operating, and we agreed to pay the costs of the construction and operation of, the gas gathering extension that connects our properties in the Cabin Creek area to the Big Horn Gas Gathering Pipeline. The construction and operating agreement has an initial term of one year and continues on a month-to-month basis thereafter unless terminated by either party upon 90 days' written notice. For five years after October 2006, the effective date of the agreement, Big Horn Gas Gathering has an option to purchase the gas gathering extension from us. Under certain circumstances, Big Horn Gas Gathering also has a right of first refusal with respect to the extension. In 2008, Cantera Gas Holdings, LLC and Big Horn Gas Gathering, LLC were acquired by Copano Natural Gas. On April 8, 2009, Big Horn Gas Gathering, LLC purchased our high pressure pipeline and compression facility in our Cabin Creek area for $3.1 million net to our interest.
Natural gas in the Powder River Basin is transported by three intrastate gathering pipelines, Thunder Creek Gas Gathering, Fort Union Gas Gathering and the Kinder Morgan Lateral, and one interstate pipeline, the Grasslands Pipeline. According to the Wyoming Oil and Gas Conservation Commission, gas transported from the Powder River Basin as of December 31, 2009 was approximately 1.6 Bcf per day, with remaining available capacity of approximately 0.2 Bcf per day, or 14% of the total
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capacity. The gas is moved to marketing hubs in southern Wyoming or western North Dakota, where pipeline interconnections enable gas to move to distribution centers, primarily in the midwestern and southern United States. However, a surplus of natural gas arriving at these marketing hubs from the Powder River Basin and elsewhere relative to the available takeaway capacity from these hubs has caused Rocky Mountain gas to generally trade at a discount to the NYMEX natural gas index price. From January 1, 2009 through December 31, 2009, Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.38 to a discount of $2.53 with an average differential of a discount of $1.06.
Transportation of natural gas and access to throughput capacity has a direct impact on natural gas prices in the Rocky Mountain region, where our operations are concentrated. As drilling activity increases throughout the Rocky Mountain region, additional production may come on line, which could cause bottlenecks or capacity constraints. Generally speaking, a surplus of natural gas production relative to available transportation capacity has a negative impact on prices. Conversely, as capacity increases, and bottlenecks are eliminated, prices generally increase. The Rockies Express Pipeline, which was completed to Audrain County, Missouri in early 2008 and completed to Monroe County, Ohio in 2009, has increased takeaway capacity by approximately 1.8 Bcf per day from key marketing hubs. We expect that the completion of additional proposed pipelines will help reduce the differential between gas produced in the Rocky Mountain region and the NYMEX natural gas index price. Additional proposed pipelines are scheduled to be completed in late 2010 and 2011. General economic conditions and the future demand for natural gas may change the timing of proposed pipelines.
Marketing and Customers
We currently have a contract with Enserco Energy Inc. to purchase the gas at the tailgate of the Clear Creek compression facility in Recluse and at the Landeck compressor station for gas delivered from our Kirby and Deer Creek project areas. Pursuant to an agreement with United Energy Trading, United Energy Trading currently purchases our gas at Glenrock Wyoming after the compression and transportation from our Squaw Creek and Cabin Creek areas. Both Enserco Energy and United Energy Trading have extensive experience in gas marketing services in the Rocky Mountain region and specifically in the Powder River Basin and surrounding gas producing basins. Our contractual arrangements with Enserco Energy and United Energy Trading are based on the CIG index price and are cancelable upon thirty and sixty days' written notice, respectively, if we determine there are more attractive purchasing arrangements in the marketplace. During the year ended December 31, 2008, Enserco Energy and United Energy Trading purchased 46% and 54% of our gas sold, respectively. During the year ended December 31, 2009, Enserco Energy and United Energy Trading purchased 45% and 55% of our gas sold, respectively. In the event that Enserco Energy or United Energy Trading were to experience financial difficulties or were to no longer purchase our natural gas, we could, in the short-term, experience difficulty in our marketing of natural gas, which could adversely affect our results of operations.
Hedging Activities
We seek to reduce our exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. Our fixed-price contracts are comprised of energy swaps and collars. These contracts allow us to predict with greater certainty the effective natural gas prices to be received for hedged production and provide a benefit to operating cash flows and earnings when market prices are less than the fixed prices provided by the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling prices and floors provided in those contracts. With regard to hedging arrangements, our credit facility provides that acceptable commodity hedging arrangements
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cannot be greater than 80 to 85%, depending on the measurement date, of our monthly production from our hydrocarbon properties that are used in the borrowing base determination, and that the fixed or floor price of our hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.
The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of December 31, 2009. As of December 31, 2009, we had hedged volumes through December 2010. Please see Note 6 and Note 10 in the notes to the audited financial statements appearing elsewhere in this report for further information regarding our derivatives.
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Year Ending
December 31, 2010 |
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(Unaudited)
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Natural Gas Swaps: |
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Contract volumes (MMBtu) |
2,007,500 | |||
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Weighted-average fixed price per MMBtu(1) |
$ | 4.79 | ||
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Fair Value, net (thousands)(2) |
$ | (1,375 | ) | |
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Total Natural Gas Contracts: |
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Contract volumes (MMBtu) |
2,007,500 | |||
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Fixed-price sales |
$ | 4.79 | ||
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Fair value, net (thousands)(2) |
$ | (1,375 | ) | |
Competition
We compete with a number of other potential purchasers of oil and gas leases and producing properties, many of which have greater financial resources than we do. The bidding for oil and gas leases has become particularly intense in the Powder River Basin with bidders evaluating potential acquisitions with varying product pricing parameters and other criteria that result in widely divergent bid prices. The presence of bidders willing to pay prices higher than are supported by our evaluation criteria could further limit our ability to acquire oil and gas leases. In addition, low or uncertain prices for properties can cause potential sellers to withhold or withdraw properties from the market. In this environment, we cannot guarantee that there will be a sufficient number of suitable oil and gas leases available for acquisition or that we can obtain oil and gas leases or obtain financing for or participants to join in the development of prospects.
In addition to competition for leasehold acreage in the Powder River Basin, the oil and gas exploration and production industry is intensely competitive as a whole. We compete against well-established companies that have significantly greater financial, marketing, personnel and other resources than we do. This competition could have a material adverse effect on our ability to execute our plan and our profitability.
Seasonal Nature of Business
Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage
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facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in certain areas of the Rocky Mountain region. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.
Employee and Labor Relations
We have reduced our full-time employees to 38 as of March 29, 2010 as a result of cost cutting measures. We believe that our relationships with our employees are good. None of our employees are covered by a collective bargaining agreement. From time to time, we use the services of independent consultants to perform various professional services, particularly in the areas of legal and regulatory services. Independent contractors often perform well drilling and production operations, including pumping, maintenance, dispatching, inspection and testing. Reductions in full-time employees were due to general economic conditions and low natural gas prices in the Rocky Mountain region. While we believe the employees in place are integral to our future business plans, our liquidity and ability to attract capital will determine future staffing levels.
We depend to a large extent on the services of certain key management personnel and the loss of any could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees, including our executive officers.
Regulations
The natural gas industry is subject to regulation by federal, state and local authorities on matters such as employee health and safety, permitting, bonding and licensing requirements, air quality standards, water pollution, the treatment, storage and disposal of wastes, plant and wildlife protection, storage tanks, the reclamation of properties and plugging of oil wells after gas operations are completed, the discharge or release of materials into the environment, and the effects of gas well operations on groundwater quality and availability and on other resources. In addition, the possibility exists that new legislation or regulations may be adopted or new interpretations of existing laws and regulations may be issued that would have a significant impact on our operations or our customers' ability to use gas and may require us or our customers to change our or their operations significantly or incur substantial costs.
Climate change regulation is one area of potential future environmental law development. Studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases," may be contributing to warming of the Earth's atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases. The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases from sources within the U.S. between 2012 and 2050. In addition, at least 17 states have developed initiatives to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The Environmental Protection Agency, or EPA, is separately considering whether it will regulate greenhouse gases as "air pollutants" under the existing federal Clean Air Act. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases, including methane or carbon dioxide in areas in which we conduct business, could result in changes to the consumption and demand for natural gas and could have adverse effects on our business, financial position, results of operations and prospects. These changes could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to
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authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief, or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.
We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. We have internal procedures and policies to ensure that our operations are conducted in substantial regulatory compliance.
Environmental Regulation of Gas Operations
Numerous governmental permits, authorizations and approvals are required for gas operations. In order to obtain such permits, authorizations and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas or related activities may have upon the environment. Compliance with the terms of such permits, authorizations and approvals and all other requirements imposed by such authorities may be costly and time consuming and may delay or limit commencement or continuation of exploration or production operations. Moreover, failure to comply may result in the imposition of significant fines, penalties and injunctions. Future legislation or regulations may increase and/or change the requirements for the protection of the environment, health and safety and, as a consequence, our activities may be more closely regulated. This type of legislation and regulation, as well as future interpretations of existing laws, may result in substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which cannot be predicted. Further, the imposition of new or revised environmental laws, regulations or requirements could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste.
While it is not possible to quantify the costs of compliance with all applicable federal, state and local environmental laws, those costs have been and are expected to continue to be significant. We did not make any capital expenditures for environmental control facilities for the years ended December 31, 2008 or 2009. Any environmental costs are in addition to well closing costs, property restoration costs and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits, gather and submit required data to regulatory authorities, characterize and dispose of wastes and effluents, and maintain management operational practices with regard to potential environmental liabilities. Compliance with these federal and state environmental laws has substantially increased the cost of gas production, but is, in general, a cost common to all domestic gas producers.
The magnitude of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to the lack of specific environmental, geologic, and hydrogeologic information available with respect to many sites, the potential for new or changed laws and regulations, the development of new drilling, remediation, and detection technologies and environmental controls, and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations. Further, given the retroactive nature of certain environmental laws, we have
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incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances, oil, natural gas, other petroleum products or other substances; environmental conditions; and damage to natural resources arising from properties and facilities currently or previously owned or operated as well as sites owned by third parties to which we sent waste materials for disposal.
We may be subject to various generally applicable federal environmental and related laws, including the following:
as well as state laws of similar scope and substance in each state in which we operate.
Regulatory requirements not directly applicable to us, but governing the ability of federal, state, or local governments to issue approvals, permits, or authorizations, or to take other actions, may also affect our operations. Such requirements include, without limitation, the National Environmental Policy Act and similar state statutory or regulatory requirements.
These environmental laws require monitoring, reporting, permitting and/or approval of many aspects of gas operations. Both federal and state inspectors regularly inspect facilities during construction and during operations after construction. We have ongoing environmental management, compliance and permitting programs designed to assist in compliance with such environmental laws. We believe that we have obtained or are in the process of obtaining all required permits under federal and state environmental laws for our current gas operations. Further, we believe that we are in substantial compliance with such permits. However, violations of permits, failure to obtain permits or other violations of federal or state environmental laws could cause us to incur significant liabilities to correct such violations, to provide additional environmental controls, to obtain required permits or to pay fines which may be imposed by governmental agencies. New permit requirements and other requirements imposed under federal and state environmental laws may cause us to incur significant additional costs that could adversely affect our operating results.
Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose "strict liability" for environmental contamination. Such laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of natural gas and oil production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas.
Common law theories of recovery may apply to operations where the presence, release, storage, transportation or use of natural gas or production waste is alleged to cause personal injury, illness or
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property damage as a result. The theories of negligence, trespass and strict liability have been used by land owners, individuals or trespassers to invoke claims for recovery of personal injuries, illness, property damage, loss of profits and related claims. Generally, such common law claims by third parties are not preempted by federal or state environmental laws, rules or regulations and may be used by plaintiffs in state law claims or as supplemental jurisdiction claims in conjunction with federal or state statutory environmental litigation.
In addition, state laws often require some form of remedial action such as closure of inactive pits and plugging of abandoned wells to prevent pollution from former or suspended operations. Legislation has been proposed and continues to be evaluated in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as "hazardous wastes." This reclassification would make such wastes subject to much more stringent and expensive storage, treatment, disposal and clean up requirements. If such legislation were to be enacted, it could have a significant adverse impact on our operating costs, as well as the natural gas and oil industry in general. Initiatives to regulate further the disposal of natural gas and oil wastes are also proposed in certain states from time to time and may include initiatives at county, municipal and local government levels. These various initiatives could have a similar adverse impact on us.
From time to time, we have been the subject of investigations, administrative proceedings and litigation by government agencies and third parties relating to environmental matters. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us.
Federal Regulation of the Sale and Transportation of Gas
Various aspects of our operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission, or FERC, regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which gas could be sold. While "first sales" by producers of natural gas, and all sales of condensate and natural gas liquids, can be made currently at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the Natural Gas Policy Act in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.
We own certain natural gas in-field low-pressure pipelines that we believe meet the traditional tests which FERC has used to establish a pipeline's status as a gatherer under section 1(b) of the Natural Gas Act, 16 U.S.C. § 717(b) and are therefore not subject to FERC jurisdiction.
Additional proposals and proceedings that might affect the gas industry are pending before Congress, FERC, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.
Beginning in 1992, FERC issued a series of orders ("Order No. 636") which required interstate natural gas pipelines to provide transportation service separate or unbundled from the pipeline's sales of gas. In addition, Order No. 636 required interstate natural gas pipelines to provide open access transportation on a non-discriminatory basis that treats similarly situated shippers equally. The courts
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affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, and FERC has since reviewed and modified its open access regulations. In particular, FERC has reviewed its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost of service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, FERC issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to "fine tune" the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include:
(1) waiving the price ceiling for short-term capacity release transactions until September 30, 2002 (which was reversed pursuant to an order on remand issued by FERC on October 31, 2002);
(2) permitting value oriented peak/off peak rates to better allocate revenue responsibility between short-term and long-term markets;
(3) permitting term differentiated rates, in order to better allocate risks between shippers and the pipeline;
(4) revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties;
(5) retaining the right of first refusal and the five year matching cap for long-term shippers at maximum rates, but significantly narrowing the right of first refusal for customers that FERC does not deem to be captive; and
(6) adopting new web site reporting requirements that include daily transactional data on all firm and interruptible contracts and daily reporting of scheduled quantities at points or segments.
The new reporting requirements became effective on September 1, 2000. FERC has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if FERC does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our low-pressure gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services. In addition, FERC's approval of transfers of previously regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to FERC regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.
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State Regulation of Gas Operations
Our operations are also subject to regulation at the state and, in some cases, the county, municipal and local governmental levels. Such regulations include requiring permits for the construction, drilling and operation of wells, maintaining bonding requirements in order to drill or operate wells, regulating the surface use and requiring the restoration of properties upon which wells are drilled, requiring the proper plugging and abandonment of wells, and regulating the disposal of fluids used and produced in connection with operations. Our operations are also subject to various state conservation laws and regulations. These include regulations that may affect the size of drilling and spacing units or proration units, the density of wells which may be drilled, and the mandatory unitization or pooling of gas properties. In addition, state conservation regulations may establish the allowable rates of production from gas wells, may prohibit or regulate the venting or flaring of gas, and may impose certain requirements regarding the ratability of gas production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory and nonpreferential purchase and/or transportation requirements, but does not generally entail rate regulation. These regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.
Permitting Issues for Federal Lands
Approximately 69% and 61% of our gross acreage in Montana and Wyoming, respectively, is on U.S. federal land. Federal leases in Montana and Wyoming must be developed pursuant to the U.S. BLM's Resource Management Plans. Federal leases are also subject to the National Environmental Policy Act and Federal Land Policy Management Act. The National Environmental Policy Act process imposes obligations on the federal government that may result in legal challenges and potentially lengthy delays in obtaining project permits or approvals. The Montana and Wyoming BLMs have been subject to several lawsuits from various environmental and tribal groups challenging Resource Management Plan amendments and supporting Environmental Impact Statements addressing CBM development in Montana and Wyoming. In 2003, the Montana BLM and Wyoming BLM each amended their Resource Management Plans based in part on Environmental Impact Statements prepared pursuant to the National Environmental Policy Act. Shortly after the issuance of the Environmental Impact Statements and amended Resource Management Plans, various plaintiffs brought legal actions challenging the Montana and Wyoming Environmental Impact Statements and Resource Management Plans. There have been at least five federal district court challenges to the Montana Environmental Impact Statements.
In April and June 2005, the Montana BLM in Miles City, Montana issued suspensions of operations for the majority of our federal leases in Montana. The suspensions were issued based upon the court order issued on April 5, 2005 by the U.S. District Court of Montana which required the BLM to complete SEIS to address phased development of coal bed natural gas. The U.S. Ninth Circuit Court of Appeals also issued an order on May 31, 2005 which enjoined the BLM from approving coal bed natural gas production projects in the Powder River Basin of Montana. Both of these actions placed limitations on lease development until completion of the SEIS.
The 2005 injunction was lifted by the Ninth Circuit Court of Appeals on October 29, 2007. The record of decision (ROD) for the SEIS was signed by the BLM on December 30, 2008. In accordance with the original District Court order, the ROD went into effect on January 14, 2009. The Suspension of Operations and Production for the suspended leases was terminated effective February 1, 2009. Leases that were suspended were placed back into an active lease status with the primary term increasing for approximately three to five years due to the time period the leases were in suspension.
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In addition to federal regulation, our federal leases are subject to certain state regulations which require governmental agencies to evaluate the potential environmental impact of a proposed project on government owned lands.
Employee Health and Safety
We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements and general industry standards regarding recordkeeping requirements and the monitoring of occupational exposure to regulated substances.
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.
Risks Related to Our Business
Due to the recent financial and credit crisis, we may not be able to obtain funding, or obtain funding on acceptable terms, to meet our future capital needs, which could negatively affect our business, results of operations and financial condition.
The continued credit crisis and the related turmoil in the global financial system have had an adverse impact on our business and financial condition, and we may face major challenges if conditions in the financial markets do not improve. Currently, we are not able to borrow additional amounts under our credit facility. As a result, we curtailed substantially all new drilling in 2009 and if our operating cash flow is not sufficient to carry out our drilling plans for 2010, we will be required to reduce the number of wells we drill or seek alternative sources of financing. However, due to the financial crisis, financing through the capital markets or otherwise may not be available to us on acceptable terms or at all. If additional funding is not available, or is available only on unfavorable terms, we may be unable to implement our drilling plans, make capital expenditures, withstand a further downturn in our business or the economy in general, or take advantage of business opportunities that may arise. Any further curtailment of our operations would have an additional adverse effect on our revenues and results of operations. In addition, current economic conditions have led to reduced demand for, and lower prices of, oil and natural gas, and a sustained decline the price of natural gas would adversely affect our business, results of operations and financial condition. Please read "The volatility of natural gas and oil prices could have a material adverse effect on our business" below. Further, the economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments. Also, market conditions could have an impact on our natural gas and oil derivatives transactions if our counterparties are unable to perform their obligations or seek bankruptcy protection.
Our contemplated merger agreement may not be consummated.
We have entered an Agreement and Plan of Merger, as further described in Note 19 in the notes to the audited financial statements herein and will file a proxy statement with the SEC shortly. There
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can be no assurances that the contemplated merger transaction will occur. If the merger is not consummated, we will continue to need additional capital to successfully operate our business.
Our credit facility has substantial restrictions and financial covenants that may affect our ability to successfully operate our business. In addition, we may have difficulty returning to compliance with certain financial covenants.
Our credit facility imposes certain operational and financial restrictions on us. These restrictions, among other things, limit our ability to:
These limitations are subject to a number of important qualifications and exceptions. In addition, our credit facility requires us to maintain certain financial ratios and to satisfy certain financial conditions which may require us to reduce our debt or to take some other action in order to comply with them. These restrictions in our credit facility could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our credit facility.
We are not in compliance with the current ratio financial covenant and certain other covenants related to accounts payable, permitted liens and permitted debt under our credit facility, and would be in default absent a waiver or amendment. On January 13, 2010, the lenders waived compliance with the current ratio as of December 31, 2009 through June 15, 2010, and with such other restrictive covenants, subject to certain financial caps. We have also not been in compliance with certain financial covenants for the last seven quarters, but obtained waivers and/or amendments in each instance. In addition, the final maturity date of the funds outstanding under our credit facility has accelerated to June 15, 2010. As a result of such non-compliance, we are unable to borrow additional funds under our credit agreement.
Please see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility," for a discussion of our credit facility.
Our development activities could require significant outside capital, which may not be available or could change our risk profile.
We expect to make substantial capital expenditures in the development of natural gas reserves in the future as part of our business strategy. In general, we intend to finance our capital expenditures in the future through cash flow from operations and the incurrence of indebtedness. However, due to limitations in our credit facility, we are currently unable to borrow additional amounts. In addition, our business experienced reduced cash flows during 2009 due to low natural gas prices. Future cash flows and the availability of financing will be subject to a number of variables such as:
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If we are unable to fund our planned activities with the combination of cash flow from operations and availability under our credit facility, we may have to obtain additional financing through the issuance of debt and/or equity. Recent conditions in the financial markets have had an adverse impact on our ability to access equity and capital markets. As a result, the availability of credit has become more expensive and difficult to obtain, and the cost of equity capital has also become more expensive. Some lenders are imposing more stringent restrictions on the terms of credit and there may be a general reduction in the amount of credit available in the markets in which we conduct business. The negative impact on the tightening of the credit markets will have a material adverse effect on us. In addition, the distribution levels of new equity issued may be higher than our historical levels, making additional equity issuances more expensive. Further, issuing equity securities to satisfy our financing requirements could cause substantial dilution to our stockholders. The level of our debt financing could also materially affect our operations and significantly affect our financial risk profile.
If our revenues decrease due to lower natural gas and oil prices, decreased production or other reasons, and if we could not obtain capital through our credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves or maintain production levels could be greatly limited.
The volatility of natural gas and oil prices could have a material adverse effect on our business.
Our revenues, profitability and future growth and the carrying value of our natural gas and oil properties depend to a large degree on prevailing natural gas and oil prices. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon natural gas and oil prices. Prices for natural gas and oil are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas and oil, uncertainties within the market and a variety of other factors in large part beyond our control, such as:
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In the past, natural gas prices have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2009, the NYMEX natural gas index price ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu, while the CIG natural gas index price ranged from a high of $5.75 per MMBtu to a low of $1.33 per MMBtu. During the year ended December 31, 2008, the NYMEX natural gas index price ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu, while the CIG natural gas index price ranged from a high of $10.26 per MMBtu to a low of $1.00 per MMBtu.
In addition to downward pressure on prices caused by reduced domestic demand, some analysts expect near-term domestic gas prices to fall further due to additional gas supplies from lower-cost resource plays, including shale, that use new exploration and production technologies and from foreign gas imports through existing and new natural gas liquefaction capacity.
A sharp decline in natural gas prices would result in a commensurate reduction in our revenues, income and cash flows from the production of natural gas and could have a material adverse effect on our borrowing base and proved reserves. In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss, and even relatively modest drops in prices can significantly affect our financial results and impede our growth.
Lower natural gas prices may not only decrease our revenues on a per unit 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. For example, if natural gas prices decline by $0.10 per Mcf, then the pre-tax PV-10 of our proved reserves as of December 31, 2009 would decrease from $7.6 million to $7.3 million.
Low natural gas prices may result in impairments of our oil and gas properties.
Accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. As such, we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period such impairment charges are taken. We reported impairments of our oil and gas properties of approximately $21.5 million and $60.9 million for the years ended December 31, 2008 and 2009, respectively, due to low CIG index prices. A further decline in gas prices or an increase in operating costs subsequent to the measurement date or reductions in the economically recoverable quantities could result in the recognition of additional impairments of our gas properties in future periods.
Approximately 66% of our total proved reserves as of December 31, 2009 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.
As of December 31, 2009, approximately 24% of our total proved reserves were undeveloped and approximately 42% were developed non-producing. We plan to develop and produce all of our proved reserves in the future, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced in the time periods we have planned, at the costs we have budgeted, or at all. Due to expectations of low natural gas prices in 2010, we have deferred drilling of our undeveloped reserves to future years which has affected the present value of future net cash flows for these reserves.
Our estimated reserves are based on many assumptions, some of which may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
This annual report contains estimates of natural gas reserves, and the future net cash flows attributable to those reserves, prepared by Netherland, Sewell & Associates, Inc., our independent petroleum and geological engineers. There are numerous uncertainties inherent in estimating quantities
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of proved reserves and cash flows from such reserves, including factors beyond our and Netherland, Sewell & Associates, Inc.'s control. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to those reserves, is a function of: (1) the available data; (2) the accuracy of assumptions regarding future natural gas and oil prices and future development and exploitation costs and activities; and (3) engineering and geological interpretation and judgment. Reserves and future cash flows may be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in this report. Any significant variance between these assumptions and actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this annual report were prepared by Netherland, Sewell & Associates, Inc. in accordance with the rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.
The present value of future net cash flows from our 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 proved reserves on prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:
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 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.
We may not be able to find, acquire or develop additional natural gas reserves that are economically recoverable.
The rate of production from natural gas and oil properties declines as reserves are depleted. As a result, we must locate, acquire and develop new natural gas and oil reserves to replace those being depleted by production. We must do this even during periods of low natural gas and oil prices when it is difficult to raise the capital necessary to finance activities. 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 find or acquire and develop additional reserves at an acceptable cost or have necessary financing for these activities in the future.
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The development of natural gas properties involves substantial risks that may result in a total loss of investment.
The business of exploring for, developing and operating natural gas and oil properties involves a high degree of business and financial risks, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:
A productive well may become uneconomic in the event that unusual quantities of water or other deleterious substances are encountered which impair or prevent the production of natural gas and/or oil from the well. In addition, production from any well may be unmarketable if it is contaminated with unusual quantities of water or other deleterious substances. We may drill wells that are unproductive or, although productive, do not produce natural gas and/or oil in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, a successful completion of a well does not ensure a profitable return on the investment.
We may not adhere to our proposed drilling schedule.
Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:
Substantial development activities could require significant outside capital, which may not be available or could change our risk profile.
We expect to make substantial capital expenditures in the development of natural gas reserves in the future as part of our business strategy. In general, we intend to finance our capital expenditures in
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the future through cash flow from operations and the incurrence of indebtedness. However, due to limitations in our credit facility, we are currently unable to borrow additional amounts. In addition, our business has experienced reduced cash flows during 2009 due to low natural gas prices. Future cash flows and the availability of financing will be subject to a number of variables such as:
If we are unable to fund our planned activities with the combination of cash flow from operations and availability under our credit facility, we may have to obtain additional financing through the issuance of debt and/or equity. Recent conditions in the financial markets have had an adverse impact on our ability to access equity and capital markets. As a result, the availability of credit has become more expensive and difficult to obtain, and the cost of equity capital has also become more expensive. Some lenders are imposing more stringent restrictions on the terms of credit and there may be a general reduction in the amount of credit available in the markets in which we conduct business. The negative impact of the tightening credit markets has and will continue to have a material adverse effect on us. In addition, the distribution levels of new equity issued may be higher than our historical levels, making additional equity issuances more expensive. Further, issuing equity securities to satisfy our financing requirements could cause substantial dilution to our stockholders. The level of our debt financing could also materially affect our operations and significantly affect our financial risk profile.
If our revenues decrease due to lower natural gas and oil prices, decreased production or other reasons, and if we could not obtain capital through our credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves or maintain production levels could be greatly limited.
We must obtain governmental permits and approvals for drilling operations, which can result in delays in our operations, 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 issuances in the Rocky Mountain region. Compliance with the requirements imposed by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations and/or fines. For example, in the ordinary course of our business, we have received notices of violation or orders to cease production with respect to certain of our wells that have resulted in production delays and/or fines. Similar regulatory or legal actions in the future may materially interfere with our operations or otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. 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 profitability.
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Our natural gas sales are dependent on two customers and the loss of these customers or their inability to pay for our gas would adversely affect our ability to market our gas.
We market substantially all our natural gas to two purchasers. During the year ended December 31, 2009, Enserco Energy and United Energy Trading purchased 45% and 55% of our gas sold, respectively. In the event that Enserco Energy or United Energy Trading experienced financial difficulties or no longer purchased our natural gas, we could, in the short-term, experience difficulty in our marketing of natural gas, which could adversely affect our results of operations.
We may be adversely affected by natural gas prices in the Rocky Mountain region.
Substantially all of our properties are geographically concentrated at the northern end of the Rocky Mountain region. The price received by us for the natural gas production from these properties is determined mainly by factors affecting the regional supply of and demand for natural gas, as well as the general availability of pipeline capacity to deliver natural gas to the market. Based on recent experience, regional differences could cause a negative basis differential between the published indices generally used to establish the price received for regional natural gas production and the actual price we receive for natural gas production. For example, from January 1, 2009 through December 31, 2009, Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.38 to a discount of $2.53, and the differential averaged a discount of $1.06.
The majority of our properties are located in a five-county region in the northern end of the Powder River Basin in northeastern Wyoming and southern Montana, making us vulnerable to risks associated with having our production concentrated in one area.
The majority of our properties are geographically concentrated in a five-county region in the northern end of the Powder River Basin in northeastern Wyoming and southern Montana. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact this area.
We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.
Our operations are subject to hazards and risks inherent in producing and transporting natural gas and oil, such as fires, natural disasters, explosions, pipeline ruptures, spills and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our and others' properties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, existing insurance policies may not be renewed and other desirable insurance may not be available on commercially reasonable terms, if at all. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.
Our use of hedging arrangements could result in financial losses or reduce our income.
We currently engage in hedging arrangements to reduce our exposure to fluctuations in the prices of natural gas for a significant portion of our current natural gas production. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, the counterparty to the hedging contract defaults on its contract obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefits we would
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otherwise receive from increases in prices for natural gas. Please see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation—Quantitative and Qualitative Disclosures About Market Risk—Hedging Activities and Items 1 and 2, Business and Properties— Operations—Hedging Activities.
Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.
The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration.
In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would have an adverse effect on our business.
We may incur losses as a result of title deficiencies in the properties in which we invest.
It is our practice in acquiring natural gas and oil leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of natural gas and oil lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.
Prior to the drilling of a natural gas or oil well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. A title review conducted in connection with our credit facility revealed title defects on numerous properties. We have cured these defects and do not believe they will have a material adverse effect on our business or operations. Our failure to cure any future title defects may adversely impact our ability in the future to increase production and reserves. In addition, if a title review reveals that a lease or interest has been purchased in error from a person who was not the owner, our interest would be worthless.
We may incur losses in our acreage position due to the expiration of leases.
Our leasehold position is subject to leases with terms which expire from 2010 to 2019. Our leases may not be held by production and may consequently expire if we are unable to develop them in a timely manner. In addition, leases held by production which are subsequently shut-in due to low natural gas prices may also expire if we are unable to make shut-in payments.
We are subject to environmental regulation that can materially adversely affect the timing and cost of our operations.
Our exploration and production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase
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the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, we are subject to legislation regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. Such laws and regulations have been frequently changed in the past, and we are unable to predict the ultimate cost of compliance as a result of any future changes. The adoption or enforcement of stricter regulations could have a significant impact on our operating costs, as well as on the natural gas and oil industry in general. Compliance with environmental laws and regulations can be very complex, and therefore, no assurances can be given that such environmental laws and regulations will not have a material adverse effect on our business, financial condition and results of operations.
Our operations could result in liability for personal injuries, property damage, discharge of hazardous materials, remediation and clean up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, but we do not believe that insurance coverage for environmental damages that occur over time, or complete coverage for sudden and accidental environmental damages, is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the right to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.
We are subject to complex governmental regulations which may materially adversely affect the cost of our business and result in delays in our operations.
Numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. We may be required to make large expenditures to comply with these regulatory requirements. Any increases in the regulatory burden on the natural gas and oil industry created by new legislation would increase our cost of doing business and could result in delays in our operations, and consequently, adversely affect our profitability.
In addition, from time to time we may be subject to legal proceedings and claims as a result of these regulations. Please see Item 3, Legal Proceedings, for a description of material pending litigation.
We operate in a highly competitive environment and our competitors may have greater resources than us.
The natural gas and oil industry is intensely competitive and we compete with other companies, many of which are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low oil and gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete, our operating results and financial position may be adversely affected.
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The coal beds from which we produce methane gas contain water that may hamper our ability to produce gas in commercial quantities.
Coal beds contain water that must be reduced in order for the gas to desorb from the coal and flow to the well bore. Where groundwater produced from our coalbed methane 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 explore alternative methods of disposal such as re-injections or water treatment facilities. The costs to dispose of this produced water may increase if any of the following occur:
Our ability to remove and dispose of sufficient quantities of water from a coal seam will determine whether or not we can produce gas in commercial quantities from that seam. The cost of water disposal may affect our profitability.
Our coalbed methane wells typically have a shorter reserve life and lower rates of production than conventional natural gas wells, which may adversely affect our profitability during periods of low natural gas prices.
The shallow coals from which we produce natural gas in the Powder River Basin typically have a seven to eight year reserve life and have lower total reserves and produce at lower rates than most conventional natural gas wells. We depend on drilling a large number of wells each year to replace production and reserves in the Powder River Basin and to distribute operational expenses over a larger number of wells. A decline in natural gas prices could make certain wells uneconomical because production rates are lower on an individual well basis and may be insufficient to cover operational costs.
We may have difficulty managing growth in our business.
Because of our small size, growth in accordance with our business plan, if achieved, will place a significant strain on our financial, technical, operational and management resources. If we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
Our success depends on our key management personnel, the loss of any of whom could disrupt our business.
The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. The loss of services of any of our key managers could have a material adverse effect on our business. We have not obtained "key man" insurance for any members of our management. Mr. Peter G. Schoonmaker is our Chief Executive Officer and President, and Mr. Ronald T. Barnes is our Chief Financial Officer, Senior Vice President and Secretary. The loss of the services of either of these individuals, or other key personnel, may adversely affect our business and
33
prospects. We currently do not have employment agreements or non-competition agreements with any of the members of our management other than Mr. Schoonmaker and Mr. Barnes.
Some of our directors may have conflicts of interest because they are also currently affiliates, directors or officers of entities that make investments in the energy sector and/or may compete with us. The resolution of these conflicts of interest may not be in our or our stockholders' best interests.
Robert L. Cabes, Jr. and Jeffrey P. Gunst, two of our directors, serve as Principal and Vice President, respectively, of Avista Capital Holdings, L.P., or Avista, a private equity firm that makes investments in the energy sector. Messrs. Cabes and Gunst provide consulting services to certain DLJ Merchant Banking portfolio companies through arrangements with MB Advisory Partners, LLC, an affiliate of Avista. In addition, Sylvester P. Johnson, IV serves as President, Chief Executive Officer and a director of Carrizo. F. Gardner Parker is a director of Carrizo and Susan C. Schnabel is a Managing Director of DLJ Merchant Banking which holds a 32.3% equity stake in us. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our stockholders' best interest. In addition, our certificate of incorporation limits the fiduciary duties of our directors in conflict of interest situations, among other things.
Our failure to complete and integrate future acquisitions successfully could reduce our earnings and slow our growth.
We may be unable to identify potential acquisitions or to make acquisitions on terms that we consider economically acceptable. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our growth strategy may be hindered if we are not able to obtain such financing or regulatory approvals. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.
Properties we acquire may not produce as expected, may be in an unexpected condition and may subject us to increased costs and liabilities, including environmental liabilities. Although we review acquired properties prior to acquisition in a manner consistent with industry practices, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit us to become sufficiently familiar with the properties to assess fully their condition, any deficiencies, and development potential. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties or properties with known adverse conditions and will sample the remainder. In addition, environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
The coal beds from which we produce may be drained by offsetting production wells.
Our drilling locations are spaced primarily using 80-acre spacing. Producing wells located on the 80-acre spacing units contiguous with our drilling locations may drain the acreage underlying our wells. If a substantial number of productive wells are drilled on spacing units adjacent to our properties, it
34
could have an adverse impact on the economically recoverable reserves of our properties that are susceptible to such drainage.
We may not be able to keep pace with technological developments in our industry.
The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other natural gas and oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.
Because we are a relatively small company, we have been and expect to continue to be disproportionately negatively impacted by the cost of compliance with securities laws and regulations.
The Sarbanes-Oxley Act of 2002, or the Act, which became law in July 2002, has required changes in the corporate governance, securities disclosure and compliance practices of public companies. The SEC has promulgated rules pursuant to the Act covering a variety of subjects, including corporate governance guidelines. Compliance with these rules has significantly increased our legal, financial and accounting costs. In addition, compliance with these rules has required the dedication of a significant amount of the time of management and the board of directors and may make it more difficult for us to attract and retain qualified directors, particularly independent directors, or qualified executive officers. Because we are a small company with relatively few employees, we have been disproportionately negatively impacted by these rules and regulations.
As directed by Section 404 of the Act, the SEC adopted rules requiring public companies to include a report of management on the company's internal control over financial reporting in their annual reports on Form 10-K that contains an assessment by management of the effectiveness of the company's internal control over financial reporting. Beginning with our annual report on Form 10-K for the fiscal year ending December 31, 2010, the public accounting firm auditing the Company's financial statements must attest to and report on managements assessment of the effectiveness of the Company's internal control over financial reporting. If management is unable to conclude that we have effective internal control over financial reporting, or if our independent auditors are unable to provide us with an unqualified report as to the effectiveness of our internal control over financial reporting, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our securities.
We are a small company with limited resources. The number and qualifications of our finance and accounting staff are limited, and we have limited monetary resources. We experience difficulties in attracting qualified staff with requisite expertise due to our profile and a generally tight market for staff with expertise in these areas. We retained a consultant to assist us in the process of testing and evaluating our internal control over financial reporting. A key risk is that management will not timely remediate any deficiencies that may be identified as part of the review process.
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Risks Related to our Relationship with DLJ Merchant Banking and Other Initial Stockholders
Our founding stockholders have substantial influence over the outcome of certain stockholder votes and may exercise this voting power in a manner adverse to our other stockholders.
DLJ Merchant Banking beneficially owns approximately 32.3% of our outstanding common stock. Accordingly, DLJ Merchant Banking is in a position to have a substantial influence on the outcome of certain matters requiring a stockholder vote, including the election of directors and the adoption of certain amendments to our certificate of incorporation.
In addition, Carrizo beneficially owns approximately 8.4% of our outstanding common stock. This ownership, when combined with that of DLJ Merchant Banking, constitutes slightly less than a majority of our common stock and could have the effect of delaying or preventing a change in control of or otherwise discouraging a potential acquirer from attempting to obtain control of us. In addition, the interests of these stockholders may differ from those of our other stockholders, and these stockholders may vote their common stock in a manner that may adversely affect our other stockholders.
Risks Relating to Our Common Stock
The price of our common stock may be volatile and you may not be able to resell your shares at a favorable price.
The market price of our common stock may be volatile and you may not be able to resell your shares at or above the price you paid for such shares. During 2009, the closing price of our common stock ranged from a high of $0.52 per share to a low of $0.13 per share. The following factors could affect our stock price:
36
The market for purchases and sales of our common stock may be very limited, and the sale of a limited number of shares could cause the price to fall sharply.
Although our common stock is listed for trading on the NASDAQ Global Market, our securities are currently relatively thinly traded. Accordingly, it may be difficult to sell shares of common stock quickly without significantly depressing the value of the stock. Unless we are successful in developing continued investor interest in our stock, sales of our stock could continue to result in major fluctuations in the price of the stock.
We may not be able to maintain compliance with NASDAQ's continued listing requirements.
We must comply with NASDAQ's continued listing requirements in order to maintain our listing on NASDAQ's Global Market. These continued listing standards include requirements addressing the number of shares publicly held, market value of publicly held shares, stockholder's equity, number of round lot holders, and a $1.00 minimum closing bid price. Our stock price has generally been below the $1.00 minimum bid requirement since October 2008. Ordinarily, if a company's closing bid price is below $1.00 for 30 consecutive trading days, it receives a notice from NASDAQ that it will be subject to delisting if it fails to regain compliance within 180 days following the date of the notice letter by maintaining a minimum bid closing price of at least $1.00 for ten consecutive business days. NASDAQ notified us on September 15, 2009 that a deficiency existed regarding this rule. NASDAQ further sent us a Staff Determination Letter on March 16, 2010 notifying us that we have not complied with the closing bid price and will be delisted. On March 22, 2010 we requested a hearing regarding the delisting order; however, there can be no assurance that our hearing will be successful and our stock could be delisted immediately.
In order to regain compliance with the $1.00 minimum bid requirement, we would have to attain a stock price of at least $1.00 per share for a minimum of 10 consecutive business days prior to the expiration of 180 days from the date of the notice letter from NASDAQ, but the NASDAQ may in its discretion require that we maintain a bid price of at least $1.00 per share for a period in excess of 10 consecutive business days.
The delisting of our common stock would adversely affect the market liquidity for our common stock, the per share price of our common stock and impair our ability to raise capital that may be needed for future operations. Delisting from NASDAQ could also have other negative results, including the potential loss of confidence by customers and employees, the loss of institutional investor interest and fewer business development opportunities. In addition, we would be subject to a number of restrictions regarding the registration and qualification of our common stock under federal and state securities laws.
If our common stock is not eligible for quotation on another market or exchange, trading of our common stock could be conducted in the over-the-counter market or on an electronic bulletin board established for unlisted securities such as the Pink Sheets or the OTC Bulletin Board. In such event, it could become more difficult to dispose of, or obtain accurate quotations for the price of our common stock, and there would likely also be a reduction in our coverage by security analysts and the news media, which could cause the price of our common stock to decline further.
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If our stock price trades below $1.00 for a sustained period and we face delisting on the NASDAQ, we may seek to implement a reverse stock split. However, reverse stock splits frequently result in a loss in stockholder value as the actual post-split price is often lower than the pre-split price, adjusted for the split. Accordingly, a reverse stock split may not solve the listing requirement deficiency even if implemented.
The percentage ownership evidenced by the common stock is subject to dilution.
We are authorized to issue up to 100,000,000 shares of common stock and are not prohibited from issuing additional shares of such common stock. Shareholders do not have statutory "preemptive rights" and therefore are not be entitled to maintain a proportionate share of ownership by buying additional shares of any new issuance of common stock before others are given the opportunity to purchase the same. Accordingly, shareholders percentage ownership, as a holder of the common stock, will be subject to change as a result of the sale of any additional common stock or other equity interests in us.
Anti-takeover provisions in our certificate of incorporation, our bylaws and Delaware law could prohibit a change of control that our stockholders may favor and which could affect our stock price.
Provisions in our second amended and restated certificate of incorporation, our amended and restated bylaws, and applicable provisions of the Delaware General Corporation Law may make it more difficult and expensive for a third party to acquire control of us, even if a change of control would be beneficial to the interests of our stockholders. These provisions could discourage potential takeover attempts and could adversely affect the market price of our common stock. Our certificate of incorporation and bylaws:
In addition, Section 203 of the Delaware General Corporation Law may discourage, delay or prevent a change in control by prohibiting us from engaging in a business combination with an interested stockholder for a period of three years after the person becomes an interested stockholder.
38
Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our credit facility restrict the payment of dividends without the prior written consent of the lenders. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.
ITEM 1B
UNRESOLVED STAFF COMMENTS
None.
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of its business. In addition, like other natural gas and oil producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As a result, it is extremely difficult to reasonably quantify future environmental and regulatory related expenditures.
The following represent legal actions in which we are involved. No assurance can be given that these legal actions will be resolved in our favor. However we believe, based on our experiences to date, that these matters will not have a material adverse impact on our business, financial position or results of operations.
We, together with the State of Montana, the Montana Department of Environmental Quality, the Montana Board of Oil and Gas Conservation and the Department of Natural Resources, were named as defendants in a lawsuit (Civil Cause No. DV-05-27) filed on May 19, 2005 in the Montana 22nd Judicial District Court, Bighorn County by Diamond Cross Properties, LLC relating to the Coal Creek POD. The plaintiff is a surface owner with properties located in Big Horn County and Rosebud County, Montana where we have a lease for approximately 10,300 acres, serve as operator and own a working interest in the minerals under lease. The plaintiff sought to permanently enjoin the State of Montana and its administrative bodies from issuing licenses or permits, or authorizing the removal of ground water from under the plaintiff's ranch. In addition, the plaintiff further sought to preliminarily and permanently enjoin us on the basis that our operations lacked adequate safeguards required under the Montana state constitution. On August 25, 2005, the district judge issued an order denying without prejudice the application for temporary restraining order and preliminary injunction requested by the plaintiff. The case was appealed by the plaintiff to the Montana Supreme Court. On November 16, 2005, the Montana Supreme Court issued an order that denied enjoining the Coal Creek POD, and subsequently, the Montana Supreme Court remanded the case back to the district court for a decision on the merits.
We, together with the defendants above, were also named as defendants in a related lawsuit (Civil Cause No. DV-05-70) filed on September 21, 2005 in the Montana 22nd Judicial District Court, Bighorn County by Diamond Cross Properties, LLC relating to the Dietz POD. The plaintiff sought similar relief as in the Coal Creek POD suit. The two cases were combined.
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On July 14, 2008, the district court issued a summary judgment order in the combined case, and the order was subsequently entered as a judgment on August 15, 2008. As a result, we have continued our operations in the two project areas. To date, there has been no appeal by the plaintiff.
In April and September 2005, the U.S. Bureau of Land Management in Miles City, Montana issued suspensions of operations for the majority of our federal leases in Montana. The suspensions were issued based upon a court order issued on April 5, 2005 by the U.S. District Court of Montana that required the BLM to complete a Supplemental Environmental Impact Statement (SEIS) to address phased development of coal bed natural gas. The U.S. Ninth Circuit Court of Appeals also issued an order on May 31, 2005 which enjoined the BLM from approving coal bed natural gas production projects in the Powder River Basin of Montana. Both of these actions placed limitations on lease development until completion of the SEIS.
The 2005 injunction was lifted by the Ninth Circuit Court of Appeals on October 29, 2007. The record of decision (ROD) for the SEIS was signed by the BLM on December 30, 2008 and went into effect on January 14, 2009. The Suspension of Operations and Production for the suspended leases was terminated effective February 1, 2009. We have received letters from the BLM with amended lease terms of the affected leases. Leases that were suspended have been placed back into an active lease status with the primary term increasing for approximately three to five years based on the time period the leases were in suspension.
On July 6, 2009, we filed suit (Cause No. DV09-35) against Big Sky Energy LLC and Quaneco L.L.C., in the Twenty-Second Judicial District Court, Big Horn County, Montana alleging claims for breach of contract, breach of implied covenant of good faith and fair dealing, tortious interference with business, tortious interference with contractual relations and slander of title. We are amending the complaint to add a foreclosure action against Big Sky Energy LLC's and Quaneco L.L.C.'s collective interest in the developed properties in Montana for non payment of invoices in the amount of $298,689.
We had previously filed suit (Cause DV-07-02) against Quaneco L.L.C. in the Twenty-Second Judicial District Court, Big Horn County, Montana for breach of contract and foreclosure of liens to collect $3,717,046 for joint interest bills that remained unpaid for over two years through September 19, 2007. A Settlement Agreement and Release of All Claims including payment of the $ 3,717,046 to us by Quaneco L.L.C. was reached on October 19, 2007.
We will continue to vigorously pursue payment of the amounts owed including interest and attorney's fees along with foreclosure proceedings and any other rights and remedies available to us pursuant to the Joint Operating Agreement dated June 23, 2003, as amended.
We were named as a defendant in litigation brought by RLI Insurance Company (Civil Cause No. 09-CV-157-J) filed in United States District Court for the District of Wyoming on July 6, 2009. The complaint alleges that we failed to provide $1,439,360 in additional collateral requested by plaintiff to secure certain bonds issued by plaintiff on our behalf. Plaintiff seeks the additional bond collateral plus attorney's fees and costs. On March 18, 2010, Pinnacle Gas Resources, Inc. and RLI Insurance Company entered into a Tolling Agreement. The agreement stipulates that the parties agree to drop all claims and counter claims in the litigation captioned RLI Insurance Company v. Pinnacle Gas Resources, Inc., Case No. 09-CV-157-J (D. Wyo.), without prejudice. The agreement further stipulates that each party will extend the period within which either party may institute a claim, counterclaim, action or proceeding up to and including June 16, 2010. The agreement also obligates us to continue to solicit market quotes for the purpose of replacing all bonds or bonding relationships which exist between us and RLI Insurance Company.
We are aware of two purported class action lawsuits related to the Merger and Merger Agreement filed against some or all of the following: Thomas McGonagle, Peter Schoonmaker, Robert Cabes,
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Jeffery Gunst, Sylvester Johnson, F. Gardner Parker, Susan Schnabel, Pinnacle Gas Resources, Inc., DLJ Merchant Banking Partners III, L.P., Powder Holdings, LLC and Powder Acquisition Co. The lawsuits and dates of filing are as follows: Pennsylvania Avenue Fund, et al. v. Thomas McGonagle, et al. , (filed March 5, 2010); and Harry Gordon, et al. v. Pinnacle Gas Resources, Inc., et al (filed March 10, 2010). On March 24, 2010, the Delaware Court of Chancery entered an order consolidating the two actions under the caption in re Pinnacle Gas shareholder litigation C.A. No.—5313-CC (Del Ch.) and appointing co-lead counsel.
The Complaints are substantially similar and allege, among other things, that the Merger would be the product of a flawed process and that the consideration to be paid to our stockholders in the Merger would be unfair and inadequate. The Complaints further allege, among other things, that our officers and directors breached their fiduciary duties by, among other things, taking actions designed to deter higher offers from other potential acquirers and failing to maximize the value of Pinnacle to its stockholders. In addition, the lawsuits allege that DLJ, as a controlling stockholder of Pinnacle, violated fiduciary duties to Pinnacle stock holders. These lawsuits seek, among other relief, injunctive relief from joining the transaction and costs of the action, including reasonable attorney's fees. We believe that these lawsuits are without merit and intend to vigorously defend against them.
Regulations
Our oil and gas operations are subject to various federal, state and local laws and regulations. We could incur significant expense to comply with the new or existing laws and non-compliance could have a material adverse effect on our operations.
Environmental
We produce significant amounts of water from our wells. If future wells produce water of a lesser quality than allowed under state laws or if water is produced at rates greater than we can dispose of, we could incur additional costs to dispose of the water.
ITEM 4
SUBMISSIONS OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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PART II
ITEM 5
MARKET FOR REGISTRANT'S COMMON STOCK, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Shares of our common stock are traded on the NASDAQ Global Market under the symbol "PINN." As of March 30, 2010, we had 30,320,525 shares of common stock outstanding held of record by approximately 22 record holders.
The following table sets forth, for the periods indicated, the high and low sales prices for our common stock. The last reported sales price of our common stock on March 29, 2010 was $0.32 per share.
|
|
Sales Price Range per Share of Common Stock | |||||||
|---|---|---|---|---|---|---|---|---|
|
|
High | Low | ||||||
|
Year ended December 31, 2009 |
||||||||
|
Fourth quarter |
$ | 0.45 | $ | 0.30 | ||||
|
Third quarter |
0.44 | 0.29 | ||||||
|
Second quarter |
0.52 | 0.20 | ||||||
|
First quarter |
0.43 | 0.13 | ||||||
|
Year ended December 31, 2008 |
||||||||
|
Fourth quarter |
$ | 1.22 | $ | 0.24 | ||||
|
Third quarter |
3.40 | 1.19 | ||||||
|
Second quarter |
4.01 | 2.22 | ||||||
|
First quarter |
5.10 | 2.55 | ||||||
We have not paid any dividends on our common stock to date and we do not expect to pay any dividends in the foreseeable future. Our credit facility prohibits the payment of dividends to stockholders without the prior written consent of the lenders.
The information required by this item regarding securities authorized for issuance under equity compensation plans is incorporated herein by reference to the information set forth in Item 12 of this Annual Report on Form 10-K.
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Performance Graph
The following graph presents a comparison of the yearly percentage change in the cumulative total return on our common stock over the period from May 15, 2007, the first trading date after pricing our initial public offering, to December 31, 2009, with the cumulative total return of the Russell 2000 Index and the American Stock Exchange (AMEX) Natural Resources Industry Index over the same period. The graph assumes that $100 was invested on May 15, 2007 in our common stock at the closing market price at the beginning of this period and in each of the other two indices and the reinvestment of all dividends, if any.
The graph is presented in accordance with requirements of the SEC. Stockholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.
Comparison of Cumulative Total Return
Among Pinnacle Gas Resources, the Amex Natural Resources Index,
and Russell 2000 Index
Pursuant to SEC rules, the foregoing graph is not deemed "filed" with the SEC. We made no repurchases of our common stock in the fourth quarter of 2009.
|
|
5/14/2007 | 6/29/2007 | 9/28/2007 | 12/31/2007 | 3/31/2008 | 6/30/2008 | 9/30/2008 | 12/31/2008 | 3/31/2009 | 6/30/2009 | 9/30/2009 | 12/31/2009 | |||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Pinnacle Gas Resources, Inc. |
$ | 100.00 | 87.00 | 55.00 | 51.00 | 28.00 | 40.00 | 14.00 | 3.00 | 3.00 | 4.00 | 5.00 | 4.00 | ||||||||||||||||||||||||
|
Russell 2000 Index |
$ |
100.00 |
101.00 |
98.00 |
93.00 |
84.00 |
84.00 |
83.00 |
61.00 |
51.00 |
62.00 |
73.00 |
76.00 |
||||||||||||||||||||||||
|
AMEX Natural Resources Index |
$ |
100.00 |
106.00 |
111.00 |
114.00 |
108.00 |
116.00 |
81.00 |
59.00 |
64.00 |
71.00 |
77.00 |
81.00 |
||||||||||||||||||||||||
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ITEM 6
SELECTED FINANCIAL DATA
The following tables set forth our selected historical financial 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 selected historical financial data should be read in conjunction with Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation and our financial statements and related notes included elsewhere in this document.
|
|
Year Ended December 31, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2005 | 2006 | 2007 | 2008 | 2009 | ||||||||||||
|
Statement of Operations Data: |
|||||||||||||||||
|
Revenues |
|||||||||||||||||
|
Gas sales |
$ | 14,136 | $ | 12,196 | $ | 13,141 | $ | 22,441 | $ | 8,328 | |||||||
|
Realized gain/(loss) on derivatives(1) |
(1,610 | ) | 663 | 4,511 | 1,973 | $ | 6,642 | ||||||||||
|
Income from earn-in joint venture agreement |
1,629 | 379 | — | — | — | ||||||||||||
|
Total revenues |
14,155 | 13,238 | 17,652 | 24,414 | 14,970 | ||||||||||||
|
Operating expenses |
|||||||||||||||||
|
Lease operating expenses |
1,781 | 2,993 | 4,721 | 6,450 | 3,847 | ||||||||||||
|
Production taxes |
1,637 | 1,198 | 1,397 | 1.941 | 836 | ||||||||||||
|
Marketing and transportation |
1,582 | 1,962 | 3,464 | 4,694 | 3,658 | ||||||||||||
|
General and administrative, net |
2,267 | 4,343 | 5,179 | 6,674 | 3,310 | ||||||||||||
|
Depreciation, depletion, amortization and accretion |
5,622 | 6,673 | 6,516 | 9,322 | 5,617 | ||||||||||||
|
Impairment of oil and gas properties |
— | — | 18,225 | 21,521 | 60,927 | ||||||||||||
|
Total operating expenses |
12,889 | 17,169 | 39,502 | 50,602 | 78,195 | ||||||||||||
|
Operating income (loss) |
1,266 | (3,931 | ) | (21,850 | ) | (26,188 | ) | (63,225 | ) | ||||||||
|
Other income (expense) |
|||||||||||||||||
|
Gain (loss) on derivatives(1) |
(3,205 | ) | 6,699 | (2,300 | ) | 3,789 | (5,720 | ) | |||||||||
|
Interest income |
17 | 720 | 677 | 162 | 56 | ||||||||||||
|
Other income |
129 | 484 | 379 | 626 | 408 | ||||||||||||
|
Unrealized derivative loss |
— | (26 | ) | — | — | — | |||||||||||
|
Interest expense |
(47 | ) | (168 | ) | (283 | ) | (125 | ) | (271 | ) | |||||||
|
Total other income (expense) |
(3,106 | ) | 7,709 | (1,527 | ) | 4,452 | (5,527 | ) | |||||||||
|
Net income (loss) |
$ | (1,840 | ) | $ | 3,778 | $ | (23,377 | ) | $ | (21,736 | ) | $ | (68,752 | ) | |||
|
Preferred dividends, related party |
(5,409 | ) | (20,964 | ) | — | — | — | ||||||||||
|
Net income (loss) attributable to common stockholders |
$ | (7,249 | ) | $ | (17,186 | ) | $ | (23,377 | ) | $ | (21,736 | ) | $ | (68,752 | ) | ||
|
Net income (loss) per common share |
|||||||||||||||||
|
Basic and diluted |
$ | (1.42 | ) | $ | (0.87 | ) | $ | (0.86 | ) | $ | (0.75 | ) | $ | (2.32 | ) | ||
|
Weighted average shares outstanding |
|||||||||||||||||
|
Basic and diluted(2) |
5,094,800 | 19,783,118 | 27,281,680 | 29,096,411 | 29,579,388 | ||||||||||||
44
value. Our management has chosen not to use hedge accounting for these arrangements. For the years ended December 31, 2009, 2008, 2007, 2006 and 2005 we have classified the realized gains and losses as revenue and unrealized gains and losses as other income/expense in the statements of operations. We feel that this presentation fairly presents revenues derived from operations because the gains and losses on derivatives are comprised of a significant unrealized gain or loss for future periods which is not reflective of current operations.
|
|
Year Ended December 31, | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2005 | 2006 | 2007 | 2008 | 2009 | |||||||||||
|
|
(In thousands)
|
|||||||||||||||
|
Statement of Cash Flows Data: |
||||||||||||||||
|
Net cash provided by (used in) operating activities |
$ | 8,792 | $ | 6,029 | $ | (16,685 | ) | $ | 7,582 | $ | (1,405 | ) | ||||
|
Net cash provided by (used in) investing activities |
(25,301 | ) | (63,880 | ) | (9,423 | ) | (26,858 | ) | 6,620 | |||||||
|
Net cash provided by (used in) financing activities |
15,582 | 59,941 | 29,497 | 11,471 | (5,386 | ) | ||||||||||
|
Other Financial Data: |
||||||||||||||||
|
Capital expenditures—exploration and production |
$ | 20,866 | $ | 62,340 | $ | 14,006 | $ | 27,217 | $ | 4,247 | ||||||
|
|
As of December 31, | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2005 | 2006 | 2007 | 2008 | 2009 | |||||||||||
|
|
(In thousands)
|
|||||||||||||||
|
Balance Sheet Data: |
||||||||||||||||
|
Cash and cash equivalents |
$ | 2,672 | $ | 4,762 | $ | 8,151 | $ | 346 | $ | 175 | ||||||
|
Property and equipment, net |
63,529 | 127,189 | 125,011 | 123,147 | 59,232 | |||||||||||
|
Total assets |
77,081 | 150,332 | 146,593 | 138,340 | 64,500 | |||||||||||
|
Long-term debt (including current portion)(1) |
828 | 807 | 786 | 12,263 | 6,891 | |||||||||||
|
Total liabilities |
23,897 | 31,503 | 20,756 | 33,061 | 27,127 | |||||||||||
|
Redeemable preferred stock(2) |
31,400 | — | — | — | — | |||||||||||
|
Total stockholders' equity |
21,784 | 118,829 | 125,837 | 105,279 | 37,373 | |||||||||||
45
ITEM 7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
The discussion and analysis that follows should be read together with Item 6, Selected Financial Data and the accompanying financial statements and notes related thereto that are included elsewhere in this annual report. It includes forward-looking statements that may reflect our estimates, beliefs, plans and expected performance. The forward-looking statements are based upon events, risks and uncertainties that may be outside our control. Our actual results could differ significantly from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, market prices for natural gas and oil, regulatory changes, estimates of proved reserves, economic conditions, competitive conditions, development success rates, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this annual report, including in Item 1A, Risk Factors, all of which are difficult to predict. As a result of these assumptions, risks and uncertainties, the forward-looking matters discussed may not occur.
Overview
We are an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. We primarily focus our efforts on the development of CBM properties located in the Powder River Basin in northeastern Wyoming and southern Montana. In addition, in April 2006, we acquired properties located in the Green River Basin in southern Wyoming. As of December 31, 2009, we owned natural gas and oil leasehold interests in approximately 424,000 gross (308,000 net) acres, approximately 90% of which were undeveloped. As of December 31, 2009, we had estimated net proved reserves of approximately 15.0 Bcf based on the first day of the month, twelve month average CIG index price of approximately $3.04 per Mcf.
The continued credit crisis and related turmoil in the global financial system have had an adverse impact on our business and financial condition. In addition, the prices of oil and natural gas declined significantly in 2008 and has remained low in 2009. Therefore, total capital expenditures were limited to $4.2 million in 2009. As a result of low CIG index prices, the economic climate and our limited capital resources, we expect to continue operating during 2010 with a reduced capital expenditure plan. Under our plan, we will generally make expenditures only as necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. Our capital expenditure budget for 2010 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources.
We were formed in June 2003 as a Delaware corporation through a contribution of proved producing properties and undeveloped leaseholds by subsidiaries of Carrizo and U.S. Energy and a cash contribution from DLJ Merchant Banking.
In April 2006, we completed a private placement of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors. In May 2007, we completed our initial public offering of 3,750,000 shares of common stock. Please see the information under the heading "Liquidity and Capital Resources—Cash Flow from Financing Activities—Sales and Issuances of Equity" in this Item 7 for further information regarding issuances of equity to our initial stockholders.
Shares of our common stock are traded on the NASDAQ Global Market under the symbol "PINN."
Significant Developments
Amendment and Waiver to Credit Agreement. On January 13, 2010, we entered into a Seventh Amendment and Waiver to Credit Agreement (" Waiver Agreement ") with the lenders party thereto. The
46
Waiver Agreement provided that the lenders would waive (i) our compliance with certain restrictions based on the current ratio in the Credit Agreement, (ii) certain requirements pertaining to the aging of certain accounts payable, and (iii) certain restrictions regarding the amount of liens we have. Default remedies available to the lenders under the Credit Agreement include acceleration of all principal and interest amounts due under the Credit Agreement. The Waiver Agreement extends the waiver period for these items until the earlier of June 15, 2010 and the date of any default arising out of a breach or non-compliance with the Credit Agreement not expressly waived in the Waiver Agreement or a breach of the Waiver Agreement.
In addition, the Waiver Agreement amends the definition of "Final Maturity Date" under the Credit Agreement to the earlier of (i) June 15, 2010 or (ii) the date that is thirty days following the earlier of (A) the date the merger (please see Note 19 in the notes to the financial statements) is withdrawn or terminated in whole or in part or (B) the date that the lenders have been advised that the merger will not proceed.
Entry into a Merger Agreement. On February 23, 2010, we entered into an Agreement and Plan of Merger (the "Merger Agreement") with Powder Holdings, LLC, a Delaware limited liability company ("Powder"), and Powder Acquisition Co., a Delaware corporation and a direct, wholly owned subsidiary of Powder ("Merger Sub"). Powder is controlled by an investor group led by Scotia Waterous (USA) Inc. and includes certain members of our management team. Further details regarding this Merger Agreement will be described in our proxy statement and Schedule 13e-3 filed with the SEC.
The Merger Agreement provides that, upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with us, and we will continue as the surviving corporation (the "Merger"). Subject to the terms and conditions of the Merger Agreement, at the effective time and as a result of the Merger, each outstanding share of common stock, par value $.01 per share, we have (other than shares as to which appraisal rights are properly exercised under Delaware law and shares owned by us, Powder, Merger Sub or their respective subsidiaries) will be converted into the right to receive a cash amount of $0.34 per share (the "Merger Consideration"). In addition, at the effective time of the Merger, (a) each outstanding and unexercised stock option and stock appreciation right will be cancelled and the holder of such option or stock appreciation right will receive a single lump sum cash payment equal to the product of: (i) the excess, if any, of the Merger Consideration over the exercise price or base price, as applicable, per share subject to such option or right, multiplied by (ii) the total number of shares of common stock subject to such option or right and (b) each outstanding restricted stock award, whether or not then vested, will be cancelled and the holder of such restricted stock award will receive a single lump sum cash payment equal to the product of (i) the Merger Consideration, multiplied by (ii) the total number of shares of common stock subject to such award.
The obligations of the parties to consummate the Merger are subject to the satisfaction or waiver of certain closing conditions, including (a) approval of the Merger by the holders of not less than a majority of our common stock, excluding common stock held by DLJ Merchant Banking Partners III, L.P. and affiliated investment funds (collectively, "DLJ") or our chief executive officer or chief financial officer, which condition cannot be waived by the parties (the "Stockholder Approval"), and (b) the absence of any injunction, restraint or prohibition on the completion of the Merger. Each party's obligation to close the Merger is also subject to the accuracy of certain representations and warranties of, and compliance with certain covenants by, the parties to the Merger Agreement, in each case as set forth in the Merger Agreement. In addition, Powder and Merger Sub's obligations to complete the Merger are subject to certain additional conditions, including: (i) the absence of any material adverse effect on us; (ii) we obtain a waiver from the lenders under its credit agreement, for a period of 60 days following the effective time of the Merger, of the change of control event resulting from the Merger; and (iii) DLJ contributing all of its shares of common stock from us to Powder in exchange for ownership interests therein in accordance with the terms of a contribution agreement
47
among Powder, DLJ and Scotia Waterous (USA), Inc., in each case, as set forth in the Merger Agreement. We, Powder and Merger Sub have made customary representations and warranties in the Merger Agreement.
The Merger Agreement contains certain termination rights for both us and Powder, including in the event the Merger is not consummated by August 23, 2010 or Stockholder Approval has not been obtained on or before such date. The Merger Agreement further provides that, upon termination of the Merger Agreement under specified circumstances, we may be required to pay Powder a termination fee of $1,000,000 (which is reduced to $500,000 under certain circumstances) and reimbursement of Powder's out-of-pocket fees and expenses of up to $600,000 in connection with the Merger Agreement.
Reserve estimation and disclosure requirement. In January 2010, the FASB issued ASU 2010-03 to amend oil and gas reserve accounting and disclosure guidance that aligns the oil and gas reserve estimation and disclosure requirements of FASB Accounting Standards Codification ("ASC") Topic 932 ("Extractive Industries—Oil and Gas") with the requirements of SEC release 33-8995. These releases are effective for financial statements issued on or after January 1, 2010. We have adopted this guidance for all reporting periods ending on or after December 31, 2009. This release changes the accounting and disclosure requirements surrounding oil and natural gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. One of the most significant changes is in the prices used in reserve calculations, and for use in disclosure, calculation of depreciation, depletion and amortization of oil and gas properties and accounting impairment tests. Prices will no longer be based on a single-day, period-end price. Rather, they will be based on either the preceding twelve month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.
The new rule requiring the first day of the month, twelve month average price for oil and natural gas resulted in a lower average price for our reserves calculations for 2009 than if we had used the previous method utilizing the current price at period-end. As a result, under the new rule we were required to record an impairment of our properties for the year ending December 31, 2009. No such impairment would have been required under the previous FASB rule.
Economic and natural gas pricing environment. During 2009, the global economy experienced a significant downturn. The downturn, which began over concerns related to the U.S. financial markets, spread to other industries, including the energy industry. The initial effects of the downturn restricted the capital and credit markets to a degree that has not been seen in a number of decades in the United States. We have been able to partially mitigate the constraints imposed by the current economic climate through utilization of cash flows from operations.
The fear of global recession led to an immediate drop in demand for natural gas, primarily by industrial users, which in turn led to a significant reduction in natural gas prices. The natural gas index price in the Rocky Mountain region averaged $6.24 per Mcf for the twelve months ended December 31, 2008 but only $3.07 per Mcf for the twelve months ended December 31, 2009. This decrease in price has caused us to reevaluate our 2010 business plan. We have curtailed drilling, except for wells that will hold significant blocks of acreage, and have also reduced administrative, operating and transportation costs. Even with cost reductions and a flexible capital spending budget, the current natural gas pricing and economic environment remains challenging. We are exploring strategic alternatives to increase our capital resources.
Critical Accounting Policies
The most subjective and complex judgments used in the preparation of our financial statements are:
48
Oil and Gas Properties
We use the full cost method of accounting for oil and gas producing activities. Under this method, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, are capitalized within a cost center. Our oil and gas properties are all located within the United States, which constitutes a single cost center. We capitalize certain lease operating expenses associated with exploration and development of unevaluated oil and gas properties. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of gas properties and the gain significantly alters the relationship between capitalized costs and proved gas reserves of the cost center. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred.
Depreciation, depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves and asset retirement obligations. We invest in unevaluated oil and gas properties for the purpose of exploration for proved reserves. The costs of such assets, including exploration costs on properties where a determination of whether proved oil and gas reserves will be established is still under evaluation, and any capitalized interest and lease operating expenses, are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. We recorded an impairment of unevaluated properties of $36.7 million, $5.6 million and $0.7 million as of December 31, 2009, 2008 and 2007, respectively. Abandonment of unproved properties is also accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.
Substantially all remaining unproved property costs are expected to be developed and included in the amortization base ratably over the next three to five years. Salvage value is taken into account in determining depletion rates and is based on our estimate of the value of equipment and supplies at the time the well is abandoned. The estimated salvage value of equipment included in determining the depletion rate was $6.8 million, $7.3 million and $6.4 million as of December 31, 2009, 2008, and 2007, respectively.
Under the full cost method of accounting rules, capitalized costs less accumulated depletion and related deferred income taxes may not exceed a "ceiling" value which is the sum of (1) the present value discounted at 10% of estimated future net revenue using current costs and the first day of the month, twelve month average price, including the effects of derivative instruments designated as cash flow hedges but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, less any related income tax effects; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of costs or estimated fair value of unproved properties; less (4) the income tax effects related to differences in the book to tax basis of oil and gas
49
properties. This is referred to as the "full cost ceiling limitation." If capitalized costs exceed the limit, the excess must be charged to expense. The expense may not be reversed in future periods. At the end of each quarter, we calculate the full cost ceiling limitation. At December 31, 2009, the capitalized cost of our oil and gas properties exceeded the full cost ceiling limitation by approximately $3.1 million based upon the first day of the month, twelve month average price of approximately $3.04 per Mcf. An impairment of approximately $3.1 million was therefore recorded in the fourth quarter of 2009, resulting in a total impairment for the year ended December 31, 2009 of approximately $60.9 million. The impairment of our oil and gas properties resulted from low commodity prices in 2009 combined with the impairment of unevaluated properties which were moved into the full cost pool. A decline in gas prices or an increase in operating costs subsequent to the measurement date or reductions in economically recoverable quantities could result in the recognition of additional impairments of our oil and gas properties in future periods.
The present value of estimated future net revenues was computed by applying current oil and gas prices for quarters prior to December 31, 2009 and the average first day of the month price during the twelve month period ended December 31, 2009 for the quarter ended December 31, 2009 to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be included in developing and producing the proved reserves assuming the continuation of existing economic conditions. For the first three quarters of 2009, subsequent commodity price increases could be utilized to calculate the ceiling value. See Note 1 in the Notes to the audited financial statements appearing elsewhere in this report for a discussion of changes in the ceiling test as of December 31, 2009.
Gas Sales
We use the sales method for recording natural gas sales. Sales of gas applicable to our interest in producing natural gas and oil leases are recorded as revenues when the gas is metered and title transferred pursuant to the gas sales contracts covering our interest in gas reserves. During such times as our sales of gas exceed our pro rata ownership in a well, such sales are recorded as revenues unless total sales from the well have exceeded our share of estimated total gas reserves underlying the property at which time such excess is recorded as a gas imbalance liability. At December 31, 2009, 2008 and 2007, no such liability was recorded. Although there was no liability recorded for prior periods, gas reserves are an estimate and are updated on an annual and interim basis. Gas pricing, expenses and production may impact future gas reserves remaining which in turn, could impact the recording of liabilities in the future. Gas sales accruals at December 31, 2009, 2008 and 2007 were based on the actual volume statements from our purchasers and distribution process. If accruals were to change by 10% at year end, the impact would have been a $124,000 change for 2009, a $209,000 change for 2008 and a $306,000 change for 2007.
50
Asset Retirement Obligations
We follow certain accounting provisions that apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. These provisions require us to recognize an estimated liability for costs associated with the abandonment of our oil and gas properties.
A liability for the fair value of an asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset is recorded at the time a well is completed or acquired. The increased carrying value is depleted using the units-of-production method, and the discounted liability is increased through accretion over the remaining life of the respective oil and gas properties.
The estimated liability is based on historical gas industry experience in abandoning wells, including estimated economic lives, external estimates as to the cost to abandon the wells in the future and federal and state regulatory requirements. Our liability is discounted using our best estimate of our credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimated abandonment costs, changes in well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells. For example, a 10% change in our estimated retirement costs would have a $294,000 effect on our asset retirement obligation liability at December 31, 2009.
The following is a summary of our asset retirement obligation activity for the years ended December 31, 2009 and 2008 (in thousands):
|
|
Year Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | |||||
|
Beginning balance of asset retirement obligations |
$ | 3,366 | $ | 2,767 | |||
|
Additional obligations added during the period |
2 | 399 | |||||
|
Obligations settled during the period |
(137 | ) | (48 | ) | |||
|
Revisions in estimates |
(466 | ) | — | ||||
|
Accretion expense |
172 | 248 | |||||
|
Ending balance of asset retirement obligations |
$ | 2,937 | $ | 3,366 | |||
Inventory
We have acquired inventory of oil and gas equipment, primarily tubulars, to take advantage of quantity pricing and to secure a readily available supply. Inventory is valued at the lower of average cost or market. Inventory is used in the development of gas properties and to the extent it is estimated that it will be billed to other working interest owners during the next year, it is included in current assets. Otherwise, it is recorded in non-current assets. The price of steel is a primary factor in valuing our inventory. Under the valuation method of lower of average cost or market, a 10% reduction in the price of steel would have caused a $45,000 reduction in our inventory valuation as of December 31, 2009. The market price of steel is evaluated each quarter using prices quoted by authorized vendors in the area.
Property and Equipment
Property and equipment is comprised primarily of a building, computer hardware and software, vehicles and equipment, and is recorded at cost. Renewals and betterments that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation and amortization are provided using the straight-line method over the estimated useful
51
lives of the assets, ranging as follows: buildings—30 years; computer hardware and software—3 to 5 years; machinery, equipment and vehicles—5 years; and office furniture and equipment—3 to 5 years.
Long-Lived Assets
Long-lived assets for property, plant and equipment to be held and used in our business are reviewed for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. When the carrying amounts of long-lived assets exceed the fair value, which is generally based on discounted expected future cash flows, we record impairment. No impairments were recorded during the year's ended December 31, 2009, 2008 and 2007.
General and Administrative Expenses
General and administrative expenses are reported net of amounts allocated and billed to working interest owners of gas properties operated by us. The administrative expenses billed to working interest owners may change in accordance with the terms of the joint operating agreements. Administrative expenses are charged to working interest owners based on productive well counts. A 10% change in well counts for the year ended December 31, 2009 would have increased or decreased our expenses billed to working interest owners by approximately $122,000. As we operate and drill additional wells in the future, additional administrative expenses will be charged to the working interest owners when the wells become productive.
Income Taxes
We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities are recognized for the expected future tax consequences of temporary differences between the financial statement and tax bases of assets and liabilities. If appropriate, deferred tax assets are reduced by a valuation allowance which reflects expectations of the extent to which such assets will be realized. As of December 31, 2009 and December 31, 2008, we recorded a full valuation allowance for our net deferred tax asset.
On January 1, 2007, we adopted accounting provisions that prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This provision requires that we recognize in our consolidated financial statements only those tax positions that are "more-likely-than-not" of being sustained as of the adoption date, based on the technical merits of the position. As a result of the implementation of the provision, we performed a comprehensive review of our material tax positions in accordance with these recognition and measurement standards. As a result of this review, we did not identify any material deferred tax assets that required adjustment. As of December 31, 2009, 2008 and 2007, we had not recorded any material uncertain tax positions.
Our policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2009, 2008 and 2007, we had not recognized any interest or penalties in our statement of operations or statement of financial position.
We are subject to the following material taxing jurisdictions: U.S. federal. We also have material operations in the state of Wyoming; however, Wyoming does not impose a corporate income tax. We also have material operations in the state of Montana and are subject to a corporate income tax on income generalized in that jurisdiction. The tax years that remain open to examination by the U.S. Internal Revenue Service are years 2005 through 2009. Due to our net operating loss carry forwards, the Internal Revenue Service may also adjust the amount of loss realizable under examination back to 2003.
52
Derivatives
We use derivative instruments to manage our exposure to fluctuating natural gas prices through the use of natural gas swap and option contracts. We account for derivative instruments or hedging activities under authoritive guidance prescribed by FASB that requires us to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Please see "Note 6—Derivatives" in the notes to the audited financial statements appearing elsewhere in this annual report for additional discussion of derivatives.
We periodically hedge a portion of our oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. Our management decided not to use hedge accounting for these agreements. Therefore, in accordance with certain accounting provisions, the changes in fair market value are recognized in earnings.
Stock-Based Compensation
Effective January 1, 2006, we adopted an accounting provision which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards. This accounting provision also requires that the benefits of tax deductions in excess of compensation cost recognized for stock awards and options ("excess tax benefits") be presented as financing cash inflows in the statement of cash flows.
Under this accounting provision, compensation expense for all share-based payments granted subsequent to January 1, 2006, based on the estimated grant date fair value, has been recorded in each of the years ended December 31, 2009, 2008 and 2007. We record compensation expense related to non-employees under these provisions and recognize compensation expense over the vesting periods of such awards.
As required by this provision we have computed the fair value of options and stock appreciation rights (SARs) granted using the Black-Scholes option pricing model. In order to calculate the fair value of the options and SARs, certain assumptions are made regarding components of the model, including risk-free interest rate, volatility, expected dividend yield, and expected option life. Changes to the assumptions could cause significant adjustments to valuation. For options granted before January 1, 2006, expected volatility was not considered because we were a private company at the grant date of these options. For stock option and SARs grants after January 1, 2006, we estimated the volatility rate of our common stock at the date of the grant based on the historical volatility. We factored in expected retention rates combined with vesting periods to determine the average expected life. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of the grant. No options or SARs were granted during the year ended December 31, 2009.
|
|
Year Ended December 31, | ||||||||
|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | ||||||
|
Expected Volatility |
169% | N/A | 35% | ||||||
|
Dividend Yield |
— | N/A | — | ||||||
|
Risk Free Interest Rate |
2.55% | N/A | 4.79% to 4.80% | ||||||
|
Weighted Average Expected Life (in years) |
5 | N/A | 5 | ||||||
53
Accounts Receivable
Our revenue producing activities are conducted primarily in Wyoming. We grant credit to qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industry in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, record an allowance for doubtful accounts based upon historical experience and any specific customer collection issues identified. We recorded an allowance of $100,000 as of December 31, 2009 and December 31, 2008.
Transportation Costs
We account for transportation costs under authoritative guidance prescribed by the FASB related to the accounting for shipping and handling fees and costs, whereby amounts paid for transportation are classified as operating expenses.
Legal Estimates
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. We account for these costs under an accounting provision, which states that a loss contingency be recorded if it is probable that a liability has been incurred and it is reasonably estimatable. At each of December 31, 2009, 2008 and 2007, we recorded no expenses for legal proceedings.
Per Share Information
Basic earnings (loss) per share is computed by dividing net income (loss) from continuing operations attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents such as stock options and warrants. Diluted net loss per share is the same as basic net loss per share for all periods presented because potential common stock equivalents were anti-dilutive. For all periods in which there was a net loss attributable to stockholders, all of our stock options and warrants were anti-dilutive. Common stock equivalents of 842,280, 676,250, and 871,000 at December 31, 2009, 2008, and 2007, respectively, were excluded because they were anti-dilutive due to the net loss attributable to stockholders incurred in such periods.
A summary of the net loss per share calculation is shown below (in thousands, except per share amounts):
|
|
For the Years Ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
Net loss |
$ | (68,752 | ) | $ | (21,736 | ) | $ | (23,377 | ) | |
|
Common shares outstanding: |
||||||||||
|
Weighted average common shares outstanding at beginning of period |
29,096 | 27,282 | 19,783 | |||||||
|
Weighted average common shares issued |
483 | 1,814 | 7,499 | |||||||
|
Weighted average common shares outstanding—basic |
29,579 | 29,096 | 27,282 | |||||||
|
Weighted average common shares outstanding—diluted |
29,579 | 29,096 | 27,282 | |||||||
|
Net loss per share—basic |
$ | (2.32 | ) | $ | (0.75 | ) | $ | (0.86 | ) | |
|
Net loss per share—diluted |
$ | (2.32 | ) | $ | (0.75 | ) | $ | (0.86 | ) | |
54
Recent Accounting Pronouncements
For information concerning recent accounting pronouncements, please see Note 1 in the notes to the audited financial statements appearing elsewhere in this report.
Trends Affecting Our Business
The continued credit crisis and related turmoil in the global financial system have had an adverse impact on our business and financial condition. In addition, the prices of oil and natural gas declined significantly in 2008 and have remained low in 2009. As a result of low CIG index prices, the economic climate and our limited capital resources, we expect to continue operating during 2010 with a reduced capital expenditure plan. Under our plan, we will generally make expenditures only as are necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled.
Historically, natural gas prices have been extremely volatile, and we expect that volatility to continue. For example, during the year ended December 31, 2009, the NYMEX natural gas index price ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu, while the CIG natural gas index price ranged from a high of $5.75 per MMBtu to a low of $1.33 per MMBtu. During the year ended December 31, 2008, the NYMEX natural gas index price ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu, while the CIG natural gas index price ranged from a high of $10.26 per MMBtu to a low of $1.00 per MMBtu. Changes in natural gas pricing have impacted our revenue streams, production taxes, prices used in reserve calculations, borrowing base calculations and the carrying value of our properties and the valuation of potential property acquisitions. During the year ended December 31, 2009, estimated future gas prices had an impact on both our revenues and the costs attributable to our future operations. We expect that changing natural gas prices will continue to impact our operations and financial results in the future.
Transportation of natural gas and access to throughput capacity has a direct impact on natural gas prices in the Rocky Mountain region, where our operations are concentrated. As drilling activity increases throughout the Rocky Mountain region, additional production may come on line, which could cause bottlenecks or capacity constraints. Generally speaking, a surplus of natural gas production relative to available transportation capacity has a negative impact on prices. Conversely, as capacity increases, and bottlenecks are eliminated, prices generally increase. Although there is currently adequate transportation capacity out of the Powder River Basin, a surplus of natural gas arriving at key marketing hubs from the Powder River Basin and elsewhere relative to available takeaway capacity from these hubs has caused Rocky Mountain gas to generally trade at a discount to the NYMEX natural gas index price. For example, from January 1, 2009 through December 31, 2009, Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.38 to a discount of $2.53 per MMBtu, with an average differential of a discount of $1.06 per MMBtu. We expect that the completion of additional proposed pipelines will help reduce the differential between gas produced in the Rocky Mountain region and the NYMEX natural gas index price. Additional proposed pipelines are scheduled to be completed in late 2010 and 2011. General economic conditions and the future demand for natural gas may change the development schedule of proposed pipelines.
The U.S. House of Representatives recently passed the American Clean Energy and Security Act of 2009 which, if passed into law, will establish a federal cap-and-trade system. Under this system, major producers of greenhouse gas emissions would be required to acquire emission allowances, either through purchases at auctions or through trades with other allowance holders, and then surrender the allowances to the government. If a regulated party could not acquire sufficient allowances or reduce its emissions to the level of the allowances that it did acquire, the party would face regulatory penalties. This legislation would initially cover electrical generation facilities and would phase in coverage of
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other industrial sources of emissions and natural gas and fossil fuel distribution. If this or similar legislation is enacted into law, it could have a material adverse effect on our operations through significant increases in operating costs and decreases in the demand for natural gas.
The U.S. Congress is currently considering legislation that would amend the Safe Drinking Water Act to eliminate an existing exemption from federal regulation of hydraulic fracturing activities. Hydraulic fracturing is a common process in our industry of creating artificial cracks or fractures in deep underground formations through the pressurized injection of water or other materials. The resulting fractures allow natural gas and oil to flow more freely to a producing well. This process is often necessary to produce economically viable quantities of oil and natural gas from many reservoirs. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. If adopted, the proposed amendment to the Safe Drinking Water Act could result in additional regulations and permitting requirements at the federal level. These additional regulations and permitting requirements could lead to significant operational delays and increased operating costs as well as encumbering field enhancements through fracturing.
Results of Operations
Net loss attributable to stockholders for the year ended December 31, 2009 was $68.8 million, or $2.32 per diluted share, on total revenues of $15.0 million. Other income for the year ended December 31, 2009 included a $5.7 million unrealized loss associated with the change in the fair valuation of our natural gas hedges in place in accordance with certain accounting provisions. Absent such change in the valuation of hedges, we would have shown a loss of $63.1 million. In addition, we recorded an impairment of $60.9 million for the year ended December 31, 2009. Absent the impairment and unrealized loss on derivatives, we would have shown a loss of $2.2 million for the year ended December 31, 2009. This compares to net loss attributable to stockholders of $21.7 million for the year ended December 31, 2008 on total revenue of $24.4 million. Adjusted for an unrealized gain in the fair valuation of our natural gas hedges in place of $3.8 million shown in other income along with recorded impairments of $21.5 million, our results for the year ended December 31, 2008 would have been a net loss attributable to common stockholders of $4.0 million.
In order to provide a measure of stability to the cash flow in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk, we chose to periodically hedge a portion of our oil and gas production using swap and collar agreements. We account for our derivative instruments under certain accounting provisions which require us to record derivative instruments at their fair value. Management has chosen not to use hedge accounting for these arrangements. Therefore, in accordance with these provisions, changes in the fair market value are recognized in earnings.
Year Ended December 31, 2009 Compared To Year Ended December 31, 2008
Gas sales volume.
Gas sales volume decreased 29%, from 3,881 MMcf in the year ended December 31, 2008 to 2,775 MMcf in the year ended December 31, 2009. Average daily sales volume was 7.6 MMcf for the year ended December 31, 2009 as compared to 10.6 MMcf for the year ended December 31, 2008, a 3.0 MMcf per day decrease. The decrease resulted primarily from shutting in wells due to low natural gas prices.
Gas sales revenue.
Revenue from gas sales decreased approximately $14.1 million during the year ended December 31, 2009, to approximately $8.3 million, a 63% decrease compared to the year ended December 31, 2008. This decrease was primarily due to a decrease in gas sales volume coupled with a
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decrease in the average realized price per Mcf. The average realized price per Mcf decreased approximately 48%, from $5.78 per Mcf in the year ended December 31, 2008 to $3.01 per Mcf in the year ended December 31, 2009.
Derivatives.
For the year ended December 31, 2009, we had an unrealized loss of $5.7 million compared to an unrealized gain of $3.8 million for the year ended December 31, 2008. The unrealized gain or loss is noncash income or expense based primarily on the Black-Scholes model for valuing future cash flows utilizing price volatility with a normal discount rate for our costless collars in place and an intrinsic model for our swaps in place. The unrealized hedge loss for the year ended December 31, 2009 was primarily due to future gas prices being higher than the weighted average floor price of our future hedge positions.
Realized hedges settled during the years ended December 31, 2009 and 2008 resulted in a realized gain of $6.6 million and $2.0 million, respectively. The realized hedge gain for the year ended December 31, 2009 was primarily due to the fact that gas prices were lower than the weighted average floor price of our hedges in place.
Lease operating expenses.
Lease operating expenses decreased $2.6 million in the year ended December 31, 2009 to $3.8 million, a 40% decrease compared to the year ended December 31, 2008. This decrease resulted primarily from a reduction in the productive well count, contract services, fuel, workover, and water management related costs offset partially by an increase in surface use expenses in the productive cycle during the year ended December 31, 2009. On an Mcf basis, lease operating expenses decreased 16% from $1.66 per Mcf in the year ended December 31, 2008 to $1.39 per Mcf in the year ended December 31, 2009.
Production taxes.
Production taxes decreased $1.1 million in the year ended December 31, 2009 to $0.8 million, a 57% decrease from the year ended December 31, 2008. Production taxes generally correlate to gross sales revenue because production taxes are based on a percentage of sales value. In Wyoming, the percentage averages 11% to 13%, depending on rates in effect for the respective year, while in Montana the percentage averages 9%. The decrease in production taxes for the year ended December 31, 2009 was primarily due to decreased revenues associated with decreased volume and realized pricing. On an Mcf basis, production taxes were $0.30 per Mcf for the year ended December 31, 2009 and $0.50 per Mcf for the year ended December 31, 2008, a 40% decrease, which correlates to the decrease in the price per Mcf received in the year ended December 31, 2009 from the year ended December 31, 2008.
Marketing and transportation.
Marketing and transportation expenses decreased approximately $1.0 million in the year ended December 31, 2009 to approximately $3.7 million, a 22% decrease from the year ended December 31, 2008. The decrease related primarily to a decrease in transportation fees and compression due to lower production volumes. On an Mcf basis, marketing and transportation expenses increased 9% to $1.32 per Mcf in the year ended December 31, 2009 from $1.21 per Mcf in the year ended December 31, 2008.
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General and administrative expenses, net.
General and administrative expenses are offset by operating income from drilling and production activities for which we can charge an overhead fee to nonoperating working interest owners. These well operating overhead fees were $1.2 million and $1.8 million for the year ended December 31, 2009 and December 31, 2008, respectively, a 33% decrease. General and administrative expenses, net, decreased $3.4 million in the year ended December 31, 2009 to $3.3 million. On an Mcf basis, general and administrative expenses, decreased 30% from $1.72 per Mcf in the year ended December 31, 2008 to $1.20 per Mcf in the year ended December 31, 2009. The decrease in general and administrative expenses was primarily a result of staff and pay reductions. In addition, during the twelve months ended December 31, 2008, general and administrative expenses included a $2.1 million charge related to the failed Quest merger.
Depreciation, depletion, amortization and accretion.
Depreciation, depletion, amortization and accretion expense decreased $3.7 million for the year ended December 31, 2009 to $5.6 million, a 40% decrease compared to the year ended December 31, 2008. The decrease was primarily due to a decrease in the capitalized basis in our full cost pool at December 31, 2009. On an Mcf basis, the depreciation, depletion, amortization and accretion rate decreased to $2.03 per Mcf in the year ended December 31, 2009 from $2.40 per Mcf in the year ended December 31, 2008.
Impairment.
At December 31, 2009, the capitalized cost of our oil and gas properties exceeded the full cost ceiling limitation by approximately $60.9 million based upon a natural gas price of approximately $3.04 per Mcf (based on the first day of the month, twelve month average per Mcf on the Colorado Interstate Gas Rocky Mountain Index) in effect at that date. Therefore, we recorded an impairment of $60.9 million for the year ended December 31, 2009. An impairment was taken of $21.5 million for the year ended December 31, 2008. For further information regarding this impairment, please see Note 1—"Basis of Presentation" in the notes to the audited financial statements appearing elsewhere in this annual report. A decline in natural gas prices or an increase in operating costs in the economically recoverable quantities could result in the recognition of additional impairments of our oil and gas properties in future periods.
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Gas sales volume.
Gas sales volume increased 15% from 3,389 MMcf in the year ended December 31, 2007 to 3,881 MMcf in the year ended December 31, 2008. Daily sales volume averaged 10.6 MMcf for the year ended December 31, 2008 as compared to 9.3 MMcf for the year ended December 31, 2007, a 1.3 MMcf per day increase. The increase was primarily due to production coming online in our Cabin Creek, Kirby and Deer Creek project areas. Although volumes increased in 2008 overall, our volumes were reduced by approximately 1.3 MMcf per day from September 1, 2008 through December 31, 2008 due to low natural gas pricing, weather interruptions and pipeline flow interruptions due to hydrostatic testing.
Gas sales revenue.
Revenue from gas sales increased $9.3 million in the year ended December 31, 2008 to $22.4 million, a 71% increase compared to the year ended December 31, 2007. This increase was primarily due to an increase in the average realized price per Mcf during the first three quarters of 2008, compared to average prices in 2007, along with increased gas sales volume. The average realized
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price per Mcf increased 49%, from $3.88 per Mcf in the year ended December 31, 2007 to $5.78 per Mcf in the year ended December 31, 2008.
Derivatives.
For the year ended December 31, 2008, we had an unrealized gain of $3.8 million compared to an unrealized loss of $2.3 million for the year ended December 31, 2007. The unrealized gain is noncash income based primarily on the Black-Scholes model for valuing future cash flows utilizing price volatility with a normal discount rate for our costless collars in place and an intrinsic model for our swaps in place. Hedges settled in the year ended December 31, 2008 resulted in a realized gain of $2.0 million compared to hedge gains of $4.5 million in the year ended December 31, 2007. The hedge gains were primarily due to the fact that gas prices were lower than our weighted average floor price of our hedges in place.
Lease operating expenses.
Lease operating expenses increased $1.7 million in the year ended December 31, 2008 to $6.5 million, a 37% increase compared to the year ended December 31, 2007. This increase resulted from an increase in the number of wells in the productive cycle during 2008, along with a workover program which replaced or repaired pumps, increased generator rental and diesel fuel costs, and increased water treatment costs in our Cabin Creek area. On an Mcf basis, lease operating expenses increased 19% from $1.39 per Mcf in the year ended December 31, 2007 to $1.66 per Mcf in the year ended December 31, 2008. The increase per Mcf was primarily due to a number of wells being in the early stages of their productive life cycle as production did not increase proportionately to the number of wells coming online. Increases in generator rental and associated fuel costs while waiting on permanent power and increased water management costs associated with water treatment in our Cabin Creek area also contributed to our higher lease operating expenses.
Production taxes.
Production taxes increased $0.5 million in the year ended December 31, 2008 to $1.9 million, a 39% increase from the year ended December 31, 2007. The increase in production taxes was directly correlated to gross sales revenue because production taxes in Wyoming and Montana are based on a percentage of sales value. The percentage averages 11% to 13%, depending on rates in effect for the respective year in Wyoming and 9% in Montana. The increase in production taxes was partially offset by a surplus of ad valorem taxes over-withheld from 2004 through 2006 based on the estimated mill levy rate compared to the actual rate. On an Mcf basis, production taxes were $0.50 per Mcf for the year ended December 31, 2008 and $0.41 per Mcf for the year ended December 31, 2007, a 21% increase, which correlates to the increase in the price per Mcf received in 2008 from 2007 partially offset by the ad valorem tax surplus netted against the expense.
Marketing and transportation.
Marketing and transportation expenses increased $1.2 million in the year ended December 31, 2008 to $4.7 million, a 36% increase from the year ended December 31, 2007. The increase related primarily to the increased sales volume in 2008 together with a slight increase in transportation fees and compression due to inflationary adjustments in the applicable contracts along with additional compression, which enabled us to move gas on additional high-pressure transportation systems and fees for compression design capacity which was not used. On an Mcf basis, marketing and transportation expenses increased 18% to $1.21 per Mcf in the year ended December 31, 2008 from $1.02 per Mcf in the year ended December 31, 2007.
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General and administrative expenses, net.
General and administrative expenses are offset by operating income from drilling and production activities for which we can charge an overhead fee to nonoperating working interest owners. These well operating overhead fees were $1.8 million in the year ended December 31, 2008, a 18% increase. General and administrative expenses, net increased $1.5 million in the year ended December 31, 2008 to $6.7 million from $5.2 million in the year ended December 31, 2007. This increase was due primarily to a $2.1 million charge related to merger costs attributable to the failed Quest Resource Corporation merger, which was partially offset by cost saving measures, including staff reductions, which we implemented in late 2008. On a Mcf basis, general and administrative expenses, net increased 13%, from $1.53 per Mcf in the year ended December 31, 2007 to $1.72 per Mcf in the year ended December 31, 2008. Absent the $2.1 million merger related charges, general and administrative expenses would have been $0.99 per Mcf for the year period ended December 31, 2008.
Depreciation, depletion, amortization and accretion.
Depreciation, depletion, amortization and accretion expense increased $2.8 million for the year ended December 31, 2008 to $9.3 million, a 43% increase compared to the year ended December 31, 2007. This increase was due to an increase in capital expenditures that were added into the full cost pool used for the computation of depletion, as well as increased production. On an Mcf basis, the depreciation, depletion, amortization and accretion rate increased 25% to $2.40 per Mcf in the year ended December 31, 2008 from $1.92 per Mcf in the year ended December 31, 2007.
Impairment.
At December 31, 2008, the capitalized cost of our oil and gas properties exceeded the full cost ceiling limitation by approximately $21.5 million based upon a natural gas price of approximately $4.61 per Mcf (based on the CIG index) in effect at that date. The full impairment was taken in the fourth quarter of 2008. This compares to an $18.2 million impairment which was primarily taken in the first quarter of 2007. For further information regarding this impairment, please see Note 1 in the notes to the audited financial statements appearing elsewhere in this report. A decline in natural gas prices or an increase in operating costs subsequent to the measurement date or reductions in economically recoverable quantities could result in the recognition of additional impairments of our oil and gas properties in future periods.
Liquidity and Capital Resources
In the past, our primary sources of liquidity have been private and public sales of our equity securities, cash provided by operating activities, and debt financing. All of these sources have been negatively impacted by the current economic climate, its impact on our industry, and by significant fluctuations in oil and gas prices, operating costs, and volumes produced. We have no control over the market prices for oil and natural gas, although we are able to influence the amount of our net realized revenues related to gas sales through the use of derivative contracts. A decrease in market prices would reduce expected cash flow from operating activities and could reduce the borrowing base of our credit facility as well as the value of assets we might consider selling. Historically, decreases in the market prices have limited our industry's access to the capital markets. During these challenging times, we have reduced our administrative, operating and transportation costs. We are also actively marketing asset sales and exploring other strategic alternatives and capital restructuring options.
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Credit Facility . Effective February 12, 2007, we entered into a credit facility which permits borrowings up to the borrowing base as designated by the administrative agent. As of December 31, 2009 and December 31, 2008, we had $6.1 million and $11.5 million, respectively, of debt outstanding under the facility. As described below, we are currently unable to borrow additional amounts under the credit facility due to covenant limitations and may be further limited in the future based on borrowing base limitations.
As of December 31, 2008, the borrowing base under the credit facility was approximately $13.2 million. The borrowing base was subject to automatic reductions for approximately $666,667 per month until it reached $10.5 million on April 1, 2009. As of April 14, 2009, the borrowing base was further reduced to $9.0 million, subject to automatic reductions of $500,000 per month until it reached $6.5 million on October 1, 2009. As of October 20, 2009, the borrowing base was subject to automatic reductions of $200,000 per month until it reaches maturity or until a redetermination is received.
The borrowing base is determined on a semi-annual basis and at such other additional times, up to twice yearly, as may be requested by either us or the administrative agent and is determined by the administrative agent in accordance with customary practices and standards for loans of a similar nature, although such determination is at the administrative agent's discretion as the credit agreement does not provide a specific borrowing base formula.
Borrowings under this credit facility may be used solely to acquire, explore or develop oil and gas properties and for general corporate purposes. The credit facility matures June 15, 2010.
Our obligations under the credit facility are secured by liens on (i) no less than 90% of the net present value of the oil and gas to be produced from our oil and gas properties that are included in the borrowing base determination, calculated using a discount rate of 10% per annum and reserve estimates, prices and production rates and costs, (ii) options to lease, seismic options, permits, and records related to such properties, and (iii) seismic data.
Borrowings under our credit facility, as amended, bear interest either: (i) at the greater of the one month London Interbank Offered Rate, or LIBOR, plus 1.00% or a domestic bank rate, plus in either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) on a sliding scale from the one, two, three or six month LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization. The weighted average interest rate as of December 31, 2009 was 5.0%. The credit agreement provides for various fees, including a quarterly commitment fee of 0.5% per annum and engineering fees to the administrative agent in connection with a borrowing base determination. In addition, the credit facility provided for an up front fee of $27,000, which was paid on the closing date of the credit facility, and an additional arrangement fee of 1% based on utilization. Borrowings under this credit facility may be prepaid without premium or penalty, except on Eurodollar advances.
The credit agreement contains covenants that, among other things, restrict our ability, subject to certain exceptions, to do the following:
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With regard to hedging arrangements, our credit agreement provides that acceptable commodity hedging arrangements cannot cover greater than 80 to 85%, depending on the measurement date, of our monthly production from our hydrocarbon properties that are used in the borrowing base determination, and that the fixed or floor price of our hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.
The credit agreement, as amended, also requires that we satisfy certain affirmative covenants, meet certain financial tests, maintain certain financial ratios and make certain customary indemnifications to lenders and the administrative agent. The financial covenants include requirements to maintain: (i) a ratio of EBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) a ratio of current assets to current liabilities of not less than 1.00 to 1.00, (iii) a total debt to annualized EBITDA ratio of not more than 3.0 to 1.0, (iv) a quarterly total senior debt to annualized EBITDA ratio equal to or less than 3.0 to 1.0, and (v) a total proved PV-10 value to total debt ratio of at least 1.50 to 1.00.
The credit agreement, as amended, contains customary events of default, including payment defaults, covenant defaults, certain events of bankruptcy and insolvency, defaults in the payment of other material debt, judgment defaults, breaches of representations and warranties, loss of material permits and licenses and a change in control. The credit agreement requires any wholly-owned subsidiaries to guarantee the obligations under the credit agreement.
After an event of default, the outstanding debt bears interest at the default rate under the terms of the credit agreement. The default rate is (i) with respect to principal, 2% over the otherwise applicable rate and (ii) with respect to interest, fees and other amounts, the Base Rate (as defined in the credit facility), plus the Applicable Margin (as defined in the credit agreement), plus 2%. Any default interest is payable on demand. Failure to pay the default interest when the administrative agent demands would be another default. The lenders' remedies for defaults under the credit agreement are to terminate further borrowings, accelerate the repayment of indebtedness and/or ultimately foreclose on the collateral property.
Effective August 4, 2008, we and the administrative agent and lender entered into the second amendment to the credit agreement (the "second amendment"). The second amendment provided, among other things, for (i) an increase in the total quarterly senior debt to annualized EBITDA ratio from 2.0 to 1.0, to 3.0 to 1.0, (ii) an increase in interest at each utilization level for LIBOR borrowings, (iii) the amendment of the utilization calculation to be determined as the greater of (x) the percentage of credit exposure over the borrowing base or (y) the percentage of credit exposure over three times EBITDA minus permitted subordinated debt, and (iv) the payment of an amendment fee.
Effective December 31, 2008, we and the administrative agent and lender entered into the third amendment to the credit agreement (the "third amendment"). In addition to waiving compliance with the current ratio covenant as of December 31, 2008, the third amendment, among other things, required that immediately prior to any additional borrowings under the credit agreement, our ratio of current assets to current liabilities be not less than 1.00 to 1.00. As a result of this new condition to additional borrowings, we are currently unable to borrow additional amounts under the credit agreement. The third amendment also increased the interest rate payable under the credit agreement to either (i) the greater of the one month LIBOR plus 1.00% or a domestic bank rate, plus in either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) a sliding scale from the one, two, three or six month LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization, and provided for the payment of an amendment fee.
On April 14, 2009, we and the administrative agent entered into the fourth amendment to the credit agreement which reduced the borrowing base as described above and waived compliance with the current ratio financial covenant as of December 31, 2008 and March 31, 2009 and with the restrictive
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covenants related to accounts payable, permitted liens and permitted debt until the current ratio financial covenant and next borrowing base redetermination, subject to certain financial caps. On August 19, 2009, the lenders waived compliance with the current ratio financial covenant under the Credit Agreement for the period ending August 26, 2009 and the quarter ending June 30, 2009.
On August 26, 2009, we entered into a fifth amendment to the credit agreement which provided a waiver of the current ratio covenant through October 26, 2009 and for the quarter ending June 30, 2009. The fifth amendment to the credit agreement also extended restrictive covenants related to accounts payable, permitted liens and permitted debt, until October 26, 2009, subject to certain financial caps.
On October 20, 2009, we and the Lenders executed the sixth amendment to the credit agreement. This amendment established the Borrowing Base for the following amounts in the following applicable periods:
|
December 1, 2009 through December 31, 2009 |
$ | 6,300,000 | ||
|
January 1, 2010 through January 31, 2010 |
$ | 6,100,000 | ||
|
February 1, 2010 through February 28, 2010 |
$ | 5,900,000 | ||
|
March 1, 2010 through March 31, 2010 |
$ | 5,700,000 | ||
|
April 1, 2010 through April 30, 2010 |
$ | 5,500,000 |
Each Calendar month thereafter commencing May 1, 2010; the Borrowing Base for the preceding calendar month reduced by $200,000.
On October 26, 2009, the lenders provided a waiver effectively extending the terms of the fifth amendment to the credit agreement through November 16, 2009. On November 16, 2009, the lenders provided an additional waiver effectively extending the terms of the fifth amendment to the credit agreement through November 23, 2009.
On November 23, 2009, the lenders provided an additional waiver extending the terms of the fifth amendment to the credit agreement through December 1, 2009 and for the quarter ended December 31, 2009.
On December 1, 2009 the lenders provided an additional waiver extending the terms of the fifth amendment to the credit agreement through January 5, 2010.
On January 5, 2010 the lenders provided an additional waiver extending the terms of the fifth amendment to the credit agreement through January 12, 2010.
On January 13, 2010, we entered into a seventh amendment and waiver to credit agreement (" waiver agreement ") with the lenders party thereto. The waiver agreement provided that the lenders would waive (i) our compliance with certain restrictions based on the current ratio in the credit agreement, (ii) certain requirements pertaining to the aging of certain accounts payable, and (iii) certain restrictions regarding the amount of liens we have. Default remedies available to the lenders under the credit agreement include acceleration of all principal and interest amounts due under the credit agreement. The waiver agreement extends the waiver period for these items until the earlier of June 15, 2010 and the date of any default arising out of a breach or non-compliance with the credit agreement not expressly waived in the waiver agreement or a breach of the waiver agreement.
In addition, the waiver agreement amends the definition of "Final Maturity Date" under the credit agreement to the earlier of (i) June 15, 2010 or (ii) the date that is thirty days following the earlier of (A) the date the merger (please see Note 19 in the notes to the financial statements) is withdrawn or terminated in whole or in part or (B) the date that the lenders have been advised that the merger will not proceed.
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Office Building Loan. On November 15, 2005, we entered into a mortgage loan secured by our office building in Sheridan, Wyoming in the aggregate principal amount of $829,000. The promissory note provides for monthly payments of principal and interest in the initial amount of $6,400, and unpaid principal that bore interest at 6.875% until November 15, 2008, currently bears interest at a variable base rate plus 0.5% and will bear interest at 18% upon a default. The variable base rate is based on the lender's base rate. The maturity date of this mortgage is November 15, 2015, at which time a principal and interest payment of $520,800 will become due. As of December 31, 2009, we had $733,000 outstanding in principal on this mortgage. On November 15, 2008, the interest rate on our mortgage loan changed from a fixed rate of 6.875% to a variable rate. As of December 31, 2008, the variable rate was 4.75% which decreased to a variable rate of 4.0% at December 31, 2009.
Capital Expenditure Budget. The continued credit crisis and related turmoil in the global financial system have had an adverse impact on our business and financial condition. In addition, the prices of oil and natural gas declined significantly in 2008 and remained low in 2009. Therefore, total capital expenditures were limited to $4.2 million in 2009. As a result of low CIG index prices, the economic climate and our limited capital resources, we expect to continue operating during 2010 with a reduced capital expenditure plan. Under our plan, we will generally make expenditures only as necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. Our capital expenditure budget for 2010 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources.
Cash Flow from Operating Activities
Net cash used in operating activities was approximately $1.4 million for the year ended December 31, 2009, compared to net cash provided by operating activities of $7.6 million for the year ended December 31, 2008 and net cash used in operating activities of $16.7 million for the year ended December 31, 2007. The change in 2009 was primarily due to a decrease in accounts payable, an increase in accrued liabilities, and a decrease in revenue distribution payables.
Cash Flow from Investing Activities
Net cash provided by investing activities was approximately $6.6 million for the year ended December 31, 2009 compared to net cash used in investing activities of approximately $26.9 million and $9.4 million for the years ended December 31, 2008 and 2007, respectively. The change in net cash provided by investing activities in the year ended December 31, 2009 was primarily due to a sale of certain oil and gas properties and a realized gain on derivatives coupled with reduced capital expenditures as compared to the year ended December 31, 2008. Net cash used in investing activities increased in 2008 by $17.4 million from 2007 due to increased investment in the acquisition and development of undeveloped leaseholds along with the related infrastructure.
Cash Flow from Financing Activities
Net cash used in financing activities was approximately $5.4 million for the year ended December 31, 2009 as compared to net cash provided by financing activities of $11.5 million and $29.5 million for the years ended December 31, 2008 and 2007, respectively. The change was primarily due to a reduction in the balance owed on the line of credit for the year ended December 31, 2009 compared to additional borrowings for the year ended December 31, 2008. The change in 2008 from 2007 was primarily due to our borrowings of $11.5 million under our credit facility in 2008 and net proceeds of approximately $30.3 million from our May 2007 initial public offering.
In May 2007, we completed an initial public offering of 3,750,000 shares of our common stock at a price of $9.00 per share, or $8.37 per share net of underwriters' discounts and commissions. Out of the
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approximately $30.3 million of net proceeds (after underwriters' discounts and commissions and offering expenses) we received in our initial public offering, we used $7.0 million to pay down all of the outstanding indebtedness under our credit facility. We used the remainder of the net proceeds for capital expenditures, infrastructure development and general corporate purposes.
There have been no issuances of shares of common stock since our initial public offering except to employees, executive officers and directors pursuant to our incentive stock plan.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet financing arrangements or special purpose entities as of December 31, 2009. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements.
Contractual Obligations
Please see Notes 1, 5 and 9 in the notes to the audited financial statements appearing elsewhere in this annual report for information regarding our credit facility and other indebtedness.
The following table summarizes by period our contractual obligations as of December 31, 2009:
|
|
Total | 2010 | 2011–2012 | 2013–2014 | Thereafter | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
(In Thousands)
|
|||||||||||||||
|
Notes payable in connection with the mortgage |
$ | 733 | $ | 33 | $ | 71 | $ | 77 | $ | 552 | ||||||
|
Capital lease |
58 | 15 | 36 | 7 | — | |||||||||||
|
Asset retirement obligations |
2,937 | 721 | 532 | 537 | 1,147 | |||||||||||
|
Production and property taxes |
3,342 | 2,957 | 385 | — | — | |||||||||||
|
Total |
$ | 7,070 | $ | 3,726 | $ | 1,024 | $ | 621 | $ | 1,699 | ||||||
At December 31, 2009, the commodity derivatives liability was valued at $1,375,000, which represents a current payable attributable to 2009.
65
ITEM 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in natural gas prices or interest rates. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposure. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major commodity price risk exposure is in the pricing applicable to our natural gas production. The prices we receive for our production depend on many factors beyond our control. We seek to reduce our exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. Our fixed-price contracts are comprised of energy swaps and collars. Fixed price contracts allow us to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided by the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling prices and floors provided in those contracts. With regard to hedging arrangements, our credit facility provides that acceptable commodity hedging arrangements cannot cover greater than 80 to 85%, depending on the measurement date, of our monthly production from our hydrocarbon properties that are used in the borrowing base determination, and that the fixed or floor price of our hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.
The following table summarizes the estimated volumes, fixed prices, fixed price sales and fair value attributable to the fixed price contracts as of December 31, 2009. At December 31, 2009, we had hedged volumes through December 2010. Please see Note 6 in the notes to the audited financial statements appearing elsewhere in this annual report for further information regarding our derivatives.
|
|
Year Ending December 31,
2010 |
|||
|---|---|---|---|---|
|
|
(Unaudited)
|
|||
|
Natural Gas Swaps: |
||||
|
Contract volumes (MMBtu) |
2,007,500 | |||
|
Weighted-average fixed price sales per MMBtu(1) |
$ | 4.79 | ||
|
Fair value, net (thousands)(2) |
$ | (1,375 | ) | |
|
Total Natural Gas Contracts: |
||||
|
Contract volumes (MMBtu) |
2,007,500 | |||
|
Fixed-price sales |
$ | 4.79 | ||
|
Fair value, net (thousands)(2) |
$ | (1,375 | ) | |
66
Interest Rate Risk
As of December 31, 2009 and March 30, 2010, we had $6.1 million and $5.5 million, respectively, in outstanding indebtedness under our credit facility. Borrowings under the credit facility bear interest either: (i) at the greater of the one month LIBOR plus 1.00% or a domestic bank rate, plus in either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) on a sliding scale from one, two, three, or six month LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization. The weighted average interest rate for borrowings under our credit facility was 5.0% for the year ended December 31, 2009. In light of the current economic climate, we expect that interest rates on alternative financing options to range from 8% to 12%. The availability of alternative financing arrangements and the interest rates thereof would depend on the type of financing and our ability to restructure our current indebtness outstanding under our credit facility. Due to covenant restrictions in our credit facility, we are currently unable to borrow additional amounts.
A hypothetical increase of 1% in either the domestic bank rate or the LIBOR interest rates would increase gross interest expense approximately $61,000 per year based on our outstanding indebtness at December 31, 2009.
67
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board
of Directors and Stockholders
Pinnacle Gas Resources, Inc.
Sheridan, Wyoming
We have audited the accompanying balance sheets of Pinnacle Gas Resources, Inc. (the "Company") as of December 31, 2009 and 2008, and the related statements of operations, changes in stockholders' equity and cash flows for each of the years in the three year period ended December 31, 2009. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pinnacle Gas Resources, Inc. as of December 31, 2009 and 2008 and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, as of December 31, 2009, the Company has changed its method of determining quantities of oil and gas reserves which impacted the amount recorded for depreciation, depletion and amortization for oil and gas properties.
| /s/ Ehrhardt Keefe Steiner & Hottman PC | ||
|
Denver, Colorado March 31, 2010 |
|
|
68
PINNACLE GAS RESOURCES, INC.
Balance Sheets
|
|
December 31, | ||||||||
|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | |||||||
|
|
(In thousands, except share and per share data)
|
||||||||
|
ASSETS |
|||||||||
|
Current assets |
|||||||||
|
Cash and cash equivalents |
$ | 175 | $ | 346 | |||||
|
Receivables |
|||||||||
|
Accrued gas sales |
1,240 | 2,091 | |||||||
|
Joint interest receivables, net of $100 allowance for doubtful accounts |
1,207 | 4,824 | |||||||
|
Derivative instruments |
— | 4,345 | |||||||
|
Inventory of material held for exploration and development |
229 | 83 | |||||||
|
Restricted certificates of deposits |
142 | — | |||||||
|
Prepaid expenses |
134 | 196 | |||||||
|
Total current assets |
3,127 | 11,885 | |||||||
|
Property and equipment, at cost, net of accumulated depreciation |
1,055 | 1,798 | |||||||
|
Oil and gas properties, using full cost accounting, net of accumulated depletion and impairment |
|||||||||
|
Proved |
9,477 | 34,522 | |||||||
|
Unproved |
48,700 | 86,827 | |||||||
|
Inventory of material held for exploration and development |
223 | 384 | |||||||
|
Deposits |
76 | 199 | |||||||
|
Restricted certificates of deposit |
1,842 | 2,725 | |||||||
|
Total assets |
$ | 64,500 | $ | 138,340 | |||||
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
|||||||||
|
Current liabilities |
|||||||||
|
Long term debt—current portion |
6,148 | 11,530 | |||||||
|
Derivative instruments, current |
1,375 | — | |||||||
|
Trade accounts payable |
9,058 | 10,112 | |||||||
|
Revenue distribution payable |
3,328 | 4,625 | |||||||
|
Drilling prepayments from joint interest owners |
63 | — | |||||||
|
Asset retirement obligations, current |
721 | 341 | |||||||
|
Accrued liabilities |
3,090 | 1,539 | |||||||
|
Total current liabilities |
23,783 | 28,147 | |||||||
|
Asset retirement obligations, non-current |
2,216 | 3,025 | |||||||
|
Production taxes, non-current |
385 | 1,156 | |||||||
|
Long term debt—net of current portion |
743 | 733 | |||||||
|
Total liabilities |
27,127 | 33,061 | |||||||
|
Commitments and contingencies |
|||||||||
|
Stockholders' equity |
|||||||||
|
Common stock, $0.01 par value; 100,000,000 authorized and 30,108,023 and 29,193,573 shares issued and outstanding at December 31, 2009 and 2008, respectively |
289 | 289 | |||||||
|
Additional paid-in capital |
151,725 | 150,879 | |||||||
|
Accumulated deficit |
(114,641 | ) | (45,889 | ) | |||||
|
Total stockholders' equity |
37,373 | 105,279 | |||||||
|
Total liabilities and stockholders' equity |
$ | 64,500 | $ | 138,340 | |||||
See Notes to Financial Statements
69
PINNACLE GAS RESOURCES, INC.
Statements of Operations
|
|
For the Years Ended December 31, | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||||
|
|
(In thousands, except share and per share data)
|
|||||||||||
|
Revenues |
||||||||||||
|
Gas sales |
$ | 8,328 | $ | 22,441 | $ | 13,141 | ||||||
|
Realized gain on derivatives |
6,642 | 1,973 | 4,511 | |||||||||
|
Total revenues |
14,970 | 24,414 | 17,652 | |||||||||
|
Cost of revenues and expenses |
||||||||||||
|
Lease operating expenses |
3,847 | 6,450 | 4,721 | |||||||||
|
Production taxes |
836 | 1,941 | 1,397 | |||||||||
|
Marketing and transportation |
3,658 | 4,694 | 3,464 | |||||||||
|
General and administrative, net |
3,310 | 6,674 | 5,179 | |||||||||
|
Depreciation, depletion, amortization and accretion |
5,617 | 9,322 | 6,516 | |||||||||
|
Impairment of oil and gas properties |
60,927 | 21,521 | 18,225 | |||||||||
|
Total cost of revenues and expenses |
78,195 | 50,602 | 39,502 | |||||||||
|
Operating loss |
(63,225 | ) | (26,188 | ) | (21,850 | ) | ||||||
|
Other income (expense) |
||||||||||||
|
Unrealized gain/(loss) on derivatives |
(5,720 | ) | 3,789 | (2,300 | ) | |||||||
|
Interest income |
56 | 162 | 677 | |||||||||
|
Other income |
408 | 626 | 379 | |||||||||
|
Interest expense |
(271 | ) | (125 | ) | (283 | ) | ||||||
|
Total other income (expense) |
(5,527 | ) | 4,452 | (1,527 | ) | |||||||
|
Net loss before income taxes |
(68,752 | ) | (21,736 | ) | (23,377 | ) | ||||||
|
Income taxes |
— | — | — | |||||||||
|
Net loss attributable to common stockholders |
$ | (68,752 | ) | $ | (21,736 | ) | $ | (23,377 | ) | |||
|
Basic and diluted net loss per share |
$ | (2.32 | ) | $ | (0.75 | ) | $ | (0.86 | ) | |||
|
Weighted average shares outstanding—basic and diluted |
29,579,388 | 29,096,411 | 27,281,680 | |||||||||
See Notes to Financial Statements
70
PINNACLE GAS RESOURCES, INC.
Statements of Cash Flows
(In thousands)
|
|
For the Years Ended December 31, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | ||||||||||
|
Cash flows from operating activities |
|||||||||||||
|
Net loss |
$ | (68,752 | ) | $ | (21,736 | ) | $ | (23,377 | ) | ||||
|
Adjustments to reconcile net loss to net cash (used in)/provided by operating activities |
|||||||||||||
|
Impairment of oil and gas properties |
60,927 | 21,521 | 18,225 | ||||||||||
|
Depreciation, depletion, amortization and accretion |
5,617 | 9,322 | 6,516 | ||||||||||
|
Gain on derivatives |
(922 | ) | (5,762 | ) | (2,211 | ) | |||||||
|
Stock-based compensation |
846 | 1,184 | 867 | ||||||||||
|
Changes in assets and liabilities |
|||||||||||||
|
Decrease in receivables |
1,268 | 2,187 | 2,499 | ||||||||||
|
Decrease (increase) in inventory of material for drilling and completion |
(146 | ) | 91 | 97 | |||||||||
|
Decrease (increase) in prepaid expenses |
62 | 1,126 | (928 | ) | |||||||||
|
(Decrease) increase in accounts payable and accrued liabilities |
1,066 | 1,634 | (17,344 | ) | |||||||||
|
Decrease in revenue distribution payable |
(1,297 | ) | (1,909 | ) | (767 | ) | |||||||
|
(Decrease) increase in drilling prepayments |
63 | (28 | ) | (261 | ) | ||||||||
|
Asset retirement obligations settled this period |
(137 | ) | (48 | ) | (1 | ) | |||||||
|
Net cash (used in)/provided by operating activities |
(1,405 | ) | 7,582 | (16,685 | ) | ||||||||
|
Cash flows from investing activities |
|||||||||||||
|
Capital expenditures—exploration and production |
(4,147 | ) | (27,217 | ) | (14,006 | ) | |||||||
|
Capital expenditures—property and equipment |
(100 | ) | (583 | ) | (910 | ) | |||||||
|
Purchase of restricted certificates of deposits |
— | (973 | ) | 43 | |||||||||
|
Decrease (increase) in deposits and restrictive certificates of deposit |
864 | (179 | ) | 500 | |||||||||
|
Decrease in inventory held for exploration and development |
161 | 121 | 439 | ||||||||||
|
Net realized gain on derivatives |
6,642 | 1,973 | 4,511 | ||||||||||
|
Proceeds from the sale of assets held for sale |
3,200 | — | — | ||||||||||
|
Net cash (used in)/provided by investing activities |
6,620 | (26,858 | ) | (9,423 | ) | ||||||||
|
Cash flows from financing activities |
|||||||||||||
|
Proceeds from the issuance of common stock |
— | — | 33,750 | ||||||||||
|
Issuance costs related to common stock |
— | (6 | ) | (4,232 | ) | ||||||||
|
Principal payments long-term debt |
(5,386 | ) | (23 | ) | (21 | ) | |||||||
|
Proceeds from long-term debt |
— | 11,500 | — | ||||||||||
|
Net cash (used in)/provided by financing activities |
(5,386 | ) | 11,471 | 29,497 | |||||||||
|
Net increase (decrease) in cash and cash equivalents |
(171 | ) | (7,805 | ) | 3,389 | ||||||||
|
Cash and cash equivalents at beginning of year |
346 | 8,151 | 4,762 | ||||||||||
|
Cash and cash equivalents at end of year |
$ | 175 | $ | 346 | $ | 8,151 | |||||||
|
Noncash investing and financing activities |
|||||||||||||
|
Capital expenditures included in trade accounts payable |
$ | 6,407 | $ | 7,732 | $ | 7,200 | |||||||
|
Asset retirement obligations included in oil and gas properties |
2 | 399 | 239 | ||||||||||
|
Supplemental cash flow information |
|||||||||||||
|
Cash payments for interest, net of amount capitalized |
$ | 271 | $ | 125 | $ | 115 | |||||||
See Notes to Financial Statements
71
Pinnacle Gas Resources, Inc.
Statements of Changes in Stockholders' Equity
|
|
Stockholders' Equity | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Common Stock |
|
|
|
||||||||||||
|
|
Additional
Paid-In Capital |
Accumulated
Deficit |
|
|||||||||||||
|
|
Shares | Amount | Total | |||||||||||||
|
Balance as of December 31, 2006 |
25,131,301 | $ | 251 | $ | 119,354 | $ | (776 | ) | $ | 118,829 | ||||||
|
Issuance of restricted shares |
155,500 |
$ |
— |
$ |
158 |
$ |
— |
$ |
158 |
|||||||
|
Forfeiture of restricted shares |
(17,050 | ) | — | — | — | — | ||||||||||
|
Additional offering costs |
3,750,000 | 38 | 29,480 | — | 29,518 | |||||||||||
|
Stock-based compensation |
— | — | 709 | — | 709 | |||||||||||
|
Net Loss |
— | — | — | (23,377 | ) | (23,377 | ) | |||||||||
|
Balance at December 31, 2007 |
29,019,751 | $ | 289 | $ | 149,701 | $ | (24,153 | ) | $ | 125,837 | ||||||
|
Issuance of restricted shares |
244,650 | $ | — | $ | 571 | $ | — | $ | 571 | |||||||
|
Forfeiture of restricted shares |
(70,828 | ) | — | — | — | — | ||||||||||
|
Additional offering costs |
(6 | ) | — | (6 | ) | |||||||||||
|
Stock-based compensation |
— | — | 613 | — | 613 | |||||||||||
|
Net Loss |
— | — | — | (21,736 | ) | (21,736 | ) | |||||||||
|
Balance at December 31, 2008 |
29,193,573 | $ | 289 | $ | 150,879 | $ | (45,889 | ) | $ | 105,279 | ||||||
|
Issuance of restricted shares |
920,014 | $ | — | $ | 548 | $ | — | $ | 548 | |||||||
|
Forfeiture of restricted shares |
(5,564 | ) | — | — | — | — | ||||||||||
|
Stock-based compensation |
— | — | 298 | — | 298 | |||||||||||
|
Net Loss |
— | — | — | (68,752 | ) | (68,752 | ) | |||||||||
|
Balance at December 31, 2009 |
30,108,023 | $ | 289 | $ | 151,725 | $ | (114,641 | ) | $ | 37,373 | ||||||
See Notes to Financial Statements
72
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements
Note 1—Summary of Significant Accounting Policies
Business and Basis of Presentation
Pinnacle Gas Resources, Inc. is an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. The Company primarily focuses its efforts on the development of coalbed methane, or CBM, properties located in the Rocky Mountain region, and it is a substantial holder of CBM acreage in the Powder River Basin. The Company has assembled a large, predominantly undeveloped CBM leasehold position, which it believes positions itself for significant long-term growth in production and proved reserves. In addition, the Company owns approximately 90% of the rights to develop conventional and unconventional oil and natural gas in zones below its existing CBM reserves. Substantially all of its undeveloped acreage as of December 31, 2009 was located in the northern end of the Powder River Basin in northeastern Wyoming and southern Montana.
As of December 31, 2009, the Company owned natural gas and oil leasehold interests in approximately 424,000 gross (308,000 net) acres, approximately 90% of which were undeveloped. At December 31, 2009, the Company had estimated net proved reserves of 15.0 Bcf, based on the first day of the month, twelve month average Colorado Interstate Gas, or CIG, index price of approximately $3.04 per Mcf. These net proved reserves were located on approximately 10% of its net acreage. Based on its drilling results to date, analysis of core samples and third-party results in adjacent areas, the Company believes that its remaining undeveloped CBM acreage has substantial commercial potential. None of its acreage or producing wells is associated with coal mining operations.
As of December 31, 2009, the Company owned interests in 571 gross (319 net) producing wells and operated 97% of these wells. During the year ended December 31, 2009, the Company drilled 1 gross (1 net) well and produced an average of 7.6 MMcf per day net to its interest. During 2008, the Company drilled 117 gross (82 net) wells and produced an average of 10.6 MMcf per day net to its interest.
The continued credit crisis and related turmoil in the global financial system have had an adverse impact on the Company and its financial condition. In addition, the prices of oil and natural gas declined significantly in 2008 and has remained low in 2009. Therefore, total capital expenditures were limited to $4.2 million in 2009. As a result of low CIG index prices, the economic climate and its limited capital resources, the Company expects to continue operating during 2010 with a reduced capital expenditure plan. Under its plan, the Company will generally make expenditures only as necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. The Company's capital expenditure budget for 2010 will be dependent upon CIG index prices, its cash flows and the availability of additional capital resources.
The Company's proportionate share of capital expenditures, production revenue and operating expenses from its oil and gas properties is included in the financial statements.
On January 13, 2010, the Company entered into a Seventh Amendment and Waiver to Credit Agreement (" Waiver Agreement ") with the lenders party thereto. The Waiver Agreement provided that the lenders would waive (i) the Company's compliance with certain restrictions based on the current ratio in the Credit Agreement, (ii) certain requirements of the Company pertaining to the aging of certain accounts payable, and (iii) certain restrictions regarding the mount of liens of the Company. Default remedies available to the lenders under the Credit Agreement include acceleration of all
73
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
principal and interest amounts due under the Credit Agreement. The Waiver Agreement extends the waiver period for these items until the earlier of June 15, 2010 and the date of any default arising out of a breach or non-compliance with the Credit Agreement not expressly waived in the Waiver Agreement or a breach of the Waiver Agreement.
In addition, the Waiver Agreement amends the definition of "Final Maturity Date" under the Credit Agreement to the earlier of (i) June 15, 2010 or (ii) the date that is thirty days following the earlier of (A) the date the merger (please see Note 19) is withdrawn or terminated in whole or in part or (B) the date that the lenders have been advised that the merger will not proceed.
The Company is actively marketing certain assets to raise additional capital and is also reviewing alternatives for raising additional capital through equity and debt financing, capital restructuring and possible mergers (please see Note 19). The Company sold its high pressure gas gathering system in the Cabin Creek project area in Wyoming, and its remaining interest in the Arvada project area in Wyoming in April 2009. The Company received approximately $3.2 million in net proceeds from these sales, and used part of such proceeds to repay a portion of its indebtedness outstanding under the credit facility and used the remainder for general operating purposes. The Company has also put hedges of its gas in place to secure certain operating cash flow levels during the remainder of 2010. From January through April 2010, the Company had 5,500 MMbtu per day hedged through fixed price swaps at a weighted average price of $4.19 per MMbtu. From May through December 2010, the Company has 5,500 MMbtu per day hedged through fixed price swaps at a weighted average price of $5.08 per MMbtu. The Company has also implemented various cost cutting measures, including reducing general and administrative costs through staff reductions, wage and benefit cuts and a hiring freeze. The Company has reduced lease operating expenses by renegotiating water disposal contracts, reducing service costs and temporarily shutting-in marginal wells. The Company continues to communicate with key vendors to manage its obligations and payables, including, but not limited to, the negotiation of minimum monthly payments, possible discounts and agreements for future payment terms. The Company has entered into agreements with various vendors to make minimum monthly payments ranging from $1,000 to $45,000 at interest rates between 2% and 12% for the remainder of 2010. Management believes that appropriate steps, including cost-cutting measures, are being taken to make operations sustainable in the future. Although the Company is pursuing various alternatives to provide additional liquidity, there is no assurance of the likelihood or timing of any of these transactions.
Use of Estimates
The preparation of the Company's financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates with regard to the Company's financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows, the ceiling test applied to capitalized oil and gas properties, the estimate of the timing and cost of the Company's future drilling activity, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative assets and liabilities, the
74
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
realizability of deferred tax assets, the estimates of expenses and timing of exercise of stock options, accrual of operating costs and capital expenditures and revenue.
Cash and Cash Equivalents
Cash in excess of daily requirements is generally invested in money market accounts and commercial paper with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the financial statements. The carrying amount of cash equivalents approximates fair value due to the short maturity and high credit quality of those investments. At times, the Company maintains deposits in financial institutions in excess of federally insured limits. Management monitors the soundness of the financial institutions and believes the Company's risk is negligible.
Accounts Receivable
The Company's revenue producing activities are conducted primarily in Wyoming. The Company grants credit to qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industry in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its customers and if necessary, records an allowance for doubtful accounts based upon historical experience and any specific customer collection issues identified. As of December 31, 2009 and 2008, the Company had an allowance of $100,000.
Inventory
The Company acquires inventory of oil and gas equipment, primarily tubulars, to take advantage of quantity pricing and to secure a readily available supply. Inventory is valued at the lower of average cost or market. Inventory is used in the development of gas properties, and to the extent it is estimated that it will be billed to other working interest owners during the next year, it is included in current assets. Otherwise, inventory is recorded in other non-current assets.
Property and Equipment
Property and equipment is comprised primarily of a building, computer hardware and software, vehicles and equipment and is recorded at cost. Renewals and betterments that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation and amortization is provided using the straight-line method over the estimated useful lives of the assets as follows:
|
Buildings |
30 years | |
|
Computer hardware and software |
3-5 years | |
|
Machinery, equipment and vehicles |
5 years | |
|
Office furniture and equipment |
3-5 years |
Long-Lived Assets
Long-lived assets to be held and used in the Company's business are reviewed for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be
75
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
recoverable. When the carrying amounts of long-lived assets exceed the fair value, which is generally based on discounted expected future cash flows, the Company records an impairment. No impairments, other than to oil and gas properties, were recorded during the years ended December 31, 2009, 2008 and 2007.
Oil and Gas Properties
The Company utilizes the full cost method of accounting for oil and gas producing activities. Under this method, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities are capitalized within a cost center. The Company's oil and gas properties are all located within the United States, which constitutes a single cost center. The Company capitalizes lease operating expenses associated with exploration and development of unevaluated oil and gas properties. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of gas properties and the gain significantly alters the relationship between capitalized costs and proved gas reserves of the cost center. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred.
Depreciation, depletion and amortization of oil and gas properties ("DD&A") are computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves and asset retirement obligations. The Company invests in unevaluated oil and gas properties for the purpose of exploration for proved reserves. The costs of such assets, including exploration costs on properties where a determination of whether proved oil and gas reserves will be established is still under evaluation, and any capitalized interest and lease operating expenses are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment of unproved properties is accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. The Company recorded an impairment of unevaluated properties of $36.7 million, $5.6 million and $0.7 million respectively, during the years ended December 31, 2009, 2008 and 2007. (See Note 4 for additional discussion of unevaluated properties). Substantially all other unproved property costs are expected to be developed and included in the amortization base over the next three to five years. Salvage value is taken into account in determining depletion rates and is based on the Company's estimate of the value of equipment and supplies at the time the well is abandoned. The estimated salvage value of equipment used in determining the depletion rate was $6.8 million, $7.3 million and $6.4 million as of December 31, 2009, 2008, and 2007 respectively.
The present value of estimated future net revenues was computed by applying current oil and gas prices for quarters prior to December 31, 2009 and the average first day of the month price during the twelve month period ended December 31, 2009 for the quarter ended December 31, 2009 to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be included in developing and producing the proved reserves assuming the continuation of existing
76
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
economic conditions. For the first three quarters of 2009, subsequent commodity price increases could be utilized to calculate the ceiling value. See Note 1 for a discussion of changes in the ceiling test as of December 31, 2009.
Under the full cost method of accounting rules, capitalized costs less accumulated depletion and related deferred income taxes may not exceed a "ceiling" value which is the sum of (1) the present value discounted at 10% of estimated future net revenue using current costs and prices, including the effects of derivative instruments designated as cash flow hedges but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, less any related income tax effects; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of costs or estimated fair value of unproved properties; less (4) the income tax effects related to differences in the book to tax basis of oil and gas properties. This is referred to as the "full cost ceiling limitation." If capitalized costs exceed the limit, the excess must be charged to expense. The expense may not be reversed in future periods. At the end of each quarter, the Company calculates the full cost ceiling limitation. During the first three quarters of 2009, the Company recorded an impairment of $57.8 million. In the fourth quarter of 2009, the full cost ceiling limitation exceeded the capitalized costs of oil and gas properties by approximately $3.1 million, based upon the first day of the month, twelve month average CIG index price of approximately $3.04 per Mcf. As such, the Company recorded a total impairment of $60.9 million for the year ended December 31, 2009. For the year ended December 31, 2008, the Company recorded an impairment of $21.5 million resulting from low commodity prices throughout the year, specifically in the fourth quarter of 2008. A decline in gas prices or an increase in operating costs or reductions in economically recoverable reserve quantities could result in the recognition of additional impairments of the Company's oil and gas properties in future periods.
Asset Retirement Obligations
The Company follows the FASB guidance related to asset retirement obligations. The guidance generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operations of a long-lived asset. The guidance requires the Company to recognize an estimated liability for costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset is recorded at the time a well is completed or acquired. The increased carrying value is depleted using the units-of-production method, and the discounted liability is increased through accretion over the remaining life of the respective oil and gas properties.
The estimated liability is based on historical gas industry experience in abandoning wells, including estimated economic lives, external estimates as to the cost to abandon the wells in the future and federal and state regulatory requirements. The Company's liability is discounted using the Company's best estimate of its credit-adjusted risk-free rate. The credit adjusted risk free rate is based on the Company's borrowing under its credit facility or, if borrowings are not available under the credit facility because of borrowing base or covenant limitations, the rate is based on the interest rate available from its banks for senior secured debt or mezzanine debt. Based on the Company's current inability to borrow under its credit facility, the Company's credit adjusted risk free rate at December 31, 2009 and December 31, 2008 was the prime rate plus 7%. Revisions to the liability could occur due to changes in
77
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
estimated abandonment costs, changes in well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells.
Changes in the carrying amount of the asset retirement obligations are as follows:
|
|
December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | |||||
|
|
(In thousands)
|
||||||
|
Beginning balance of asset retirement obligations |
$ | 3,366 | $ | 2,767 | |||
|
Additional obligations added during the period |
2 | 399 | |||||
|
Obligations settled during the period |
(137 | ) | (48 | ) | |||
|
Revisions in estimates |
(466 | ) | — | ||||
|
Accretion expense |
172 | 248 | |||||
|
Ending balance of asset retirement obligations |
$ | 2,937 | $ | 3,366 | |||
Capitalized Interest
The Company capitalizes interest costs to unproved oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest costs capitalized in 2009, 2008 and 2007 were $441,000, $199,000 and $0, respectively.
Restricted Assets
Certificates of deposit. The Company holds a certificate of deposit ("CD"), which expires in July 2010, totaling $160,000. The CD is collateral for bonding required by the State of Wyoming, the State of Montana and the Federal Bureau of Land Management. Because the Company intends to renew the CD in order to maintain its bonding requirements, the Company has included the CD in other non-current assets as of December 31, 2009. The issuer of the bonds has commenced litigation against the Company to increase their collateral position. See the litigation discussion in Note 15. Additionally, the Company holds two CDs for $604,000 and $964,000 which were issued in February 2006 and expire in February 2011 and May 2010, respectively. These CDs collateralize letters of credit in favor of Powder River Energy Corporation, a local rural electric association, in order to secure power lines to the Kirby, Deer Creek and Cabin Creek areas. The Company has included these amounts in non-current assets as of December 31, 2009 because the Company also intends to renew the CDs in order to maintain power supply on a long-term basis. In April 2007, the Company issued a $1,000,000 letter of credit ("LOC"), which is collateralized by a CD that expires in April 2010 in favor of Bitter Creek Pipelines, LLC to secure the construction of a high pressure pipeline and related compression facilities to the Company's Deer Creek and Kirby areas. Bitter Creek Pipelines, LLC has drawn approximately $858,000 on this LOC for compression services provided to the Company in the third and fourth quarters of 2009. The remaining balance of this LOC is approximately $142,000 and the Company has included this amount in current assets as of December 31, 2009. In January of 2010, Bitter Creek Pipelines, LLC drew the remaining balance of the CD collateralizing this LOC.
Surety Bonds. From June 2009 through December 2009, the Company posted idle well surety for approximately $64,000 to the Wyoming Oil and Gas Conservation Commission. The Commission has
78
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
requested the Company make 18 monthly installments of $12,777 for surety on wells that will need to be plugged by the Company. The surety amount may be adjusted downward by the Commission if the Company successfully plugs the proposed wells in question. In addition, the Company has included a $50,000 payment for bonding requirements in the Company's Kirby Montana area.
Deposits. The Company has included approximately $76,000 related to royalty payments in deposits. These amounts are included in Deposits in the accompanying balance sheet at December 31, 2009.
Gas Sales
The Company uses the sales method for recording natural gas sales. Sales of gas applicable to its interest in producing natural gas and oil leases are recorded as revenues when the gas is metered and title transferred pursuant to the gas sales contracts covering its interest in gas reserves. During such times as the Company's sales of gas exceed its pro rata ownership in a well, such sales are recorded as revenues unless total sales from the well have exceeded the Company's share of estimated total gas reserves underlying the property at which time such excess is recorded as a gas imbalance liability. At December 31, 2009 and December 31, 2008, there was no such liability recorded.
General and Administrative Expenses
General and administrative expenses are reported net of amounts allocated and billed to working interest owners of gas properties operated by the Company.
Transportation Costs
The Company accounts for transportation costs under authoritative guidance prescribed by the FASB related to the accounting for shipping and handling fees and costs, whereby amounts paid for transportation are classified as operating expenses.
Per Share Information
Basic earnings (loss) per share is computed by dividing net income (loss) from continuing operations attributable to common stock by the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share is computed by adjusting the average number of shares of common stock outstanding for the dilutive effect, if any, of common stock equivalents such as stock options and warrants. Diluted net loss per share was the same as basic loss per share for the years ended December 31, 2009, 2008 and 2007 because potential common stock equivalents were anti-dilutive.
Certain options to purchase shares of Pinnacle's common stock were excluded from the dilution calculations because the shares were antidilutive. During the years ended December 31, 2009, 2008 and 2007, shares that were excluded from the calculation because they were antidilutive were 842,280, 676,250 and 871,000, respectively.
79
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
A summary of the net loss per share calculation is shown below (in thousands, except per share amounts):
|
|
For the Twelve Months Ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
Net loss |
$ | (68,752 | ) | $ | (21,736 | ) | $ | (21,763 | ) | |
|
Common shares outstanding: |
||||||||||
|
Weighted average common shares outstanding at beginning of period |
29,096 | 27,282 | 19,783 | |||||||
|
Weighted average common shares issued |
483 | 1,814 | 7,499 | |||||||
|
Weighted average common shares outstanding—basic |
29,579 | 29,096 | 27,282 | |||||||
|
Weighted average common shares outstanding—diluted |
29,579 | 29,096 | 27,282 | |||||||
|
Net loss per share—basic |
$ | (2.32 | ) | $ | (0.75 | ) | $ | (0.86 | ) | |
|
Net loss per share—diluted |
$ | (2.32 | ) | $ | (0.75 | ) | $ | (0.86 | ) | |
Income Taxes
The Company uses the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities are recognized for the expected future tax consequences of temporary differences between the financial statement and tax bases of assets and liabilities. If appropriate, deferred tax assets are reduced by a valuation allowance which reflects expectations of the extent to which such assets will be realized. As of December 31, 2009 and 2008, the Company recorded a full valuation allowance for its net deferred tax asset.
Derivatives
The Company uses derivative instruments to manage its exposure to fluctuating natural gas prices through the use of natural gas swap and option contracts. The Company accounts for derivative instruments or hedging activities under authoritive guidance prescribed by the FASB that requires it to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. (Please see Note 6—Derivatives).
The Company periodically hedges a portion of its oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to the Company's cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. Management has decided not to use hedge accounting for these agreements. Therefore, in accordance with certain accounting provisions, the changes in fair market value are recognized in earnings.
On January 1, 2009, the Company adopted authoritative guidance related to derivatives and hedging and has included the required enhanced quantitative and qualitative disclosure about objectives and strategies for using derivatives, quantitative disclosures about fair value and amounts of gains and
80
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
loses from derivative instruments, and disclosures about counter party credit risk and collateral requirements. See Note 6 for further discussion.
Stock-Based Compensation
Effective January 1, 2006, the Company adopted the accounting guidance which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards.
Under this guidance, compensation expense for all share-based payments granted subsequent to January 1, 2006, based on the estimated grant date fair value, has been recorded for the years ended December 31, 2009, 2008 and 2007. The Company records compensation expense related to non-employees under this provision and recognizes compensation expense over the vesting periods of such awards.
The Company has computed the fair value of options and SARs granted using the Black-Scholes option pricing model. In order to calculate the fair value of the options and SARs, certain assumptions are made regarding components of the model, including risk-free interest rate, volatility, expected dividend yield, and expected option life. Changes to the assumptions could cause significant adjustments to valuation. The Company estimated the volatility rate of its common stock at the date of the grant based on the historical volatility. The Company factored in expected retention rates combined with vesting periods to determine the average expected life. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of the grant. No options or SARs were granted during the year ended December 31, 2008. Accordingly, the Company has computed the fair value of all options and SARs granted during the years ended December 31, 2009, 2008 and 2007 using the Black-Scholes option pricing model and the following weighted average assumptions:
|
|
Year Ended December 31, | ||||||||
|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | ||||||
|
Expected Volatility |
169% | N/A | 35% | ||||||
|
Dividend Yield |
— | N/A | — | ||||||
|
Risk Free Interest Rate |
2.55% | N/A | 4.79% to 4.80% | ||||||
|
Weighted Average expected life (in years) |
5 | — | 5 | ||||||
New Accounting Pronouncements
In September 2006, the FASB issued accounting guidance related to fair value measurements and related disclosures. This new guidance defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The Company adopted this guidance on January 1, 2008, as required for its financial assets and financial liabilities. However, the FASB deferred the effective date of this guidance for one year as it relates to fair value measurement requirements for nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating the Company's estimate of inputs used by industry participants when valuing similar liabilities. Accordingly, the fair value is based on
81
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
unobservable pricing inputs and therefore, is considered a level 3 value input in the fair value hierarchy.
In December 2007, the FASB issued new guidance related to business combinations, which requires the acquiring entity in a business combination to recognize and measure all assets and liabilities assumed in the transaction and any non-controlling interest in the acquirer at fair value as of the acquisition date. Guidance was also established for the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting treatment pre-acquisition gain and loss contingencies, the treatment of acquisition related transaction costs, and the recognition of changes in the acquirer's income tax valuation allowance and deferred taxes. This guidance is effective for fiscal years beginning after December 15, 2008 and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. Early adoption is not permitted. The impact of the adoption of this guidance on the Company's financial statements will largely be dependent on the size and nature of the business combinations completed after the adoption of this statement.
In October 2008, the FASB issued accounting guidance relating to determining the fair value of a financial asset when the market for that asset is not active. The Company has considered this guidance provided in its determination of estimated fair values as of December 31, 2009.
In April 2009, the FASB issued accounting guidance relating to determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly, which provides additional guidance for estimating fair value. The Company has considered this guidance provided in its determination of estimated fair values as of December 31, 2009.
In June 2009, the Financial Accounting Standards Board ("FASB") issued "FASB Accounting Standards Codification™ ("Codification"), as the single source of authoritative US GAAP" for all non-governmental entities, with the exception of the SEC and its staff. The Codification, which became effective July 1, 2009, changes the referencing and organization of accounting guidance and is effective for interim and annual periods ending after September 15, 2009. The Company adopted the Codification on July 1, 2009 which provides for changes in references to technical accounting literature in the accompanying financial statements, but did not have a material impact on the Company's financial position, results of operations or cash flows.
In June 2009, the FASB issued new accounting guidance related to the accounting and disclosures of subsequent events. This guidance incorporates the subsequent events guidance contained in the auditing standards literature into authoritative accounting literature.
In December 2008, the Securities and Exchange Commission ("SEC") revised its requirements for oil and gas reserves estimation and disclosures and related definitions to align them with current practices and changes in technology. In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03 "Oil and Gas Reserve Estimation and Disclosure," which aligns the current oil and gas reserve estimation and disclosure requirements with those of the SEC. As discussed earlier, the Company follows the full-cost method of accounting for which the SEC provides guidance. Among other things, the SEC and FASB amendments replace the single-day, year-end pricing assumption with a twelve-month average pricing assumption, revise certain definitions and allow the use of certain technologies to establish reserves.
82
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1—Summary of Significant Accounting Policies (Continued)
As of December 31, 2009, the Company changed its method of determining the quantities of oil and gas reserves which impacted the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new rules, the Company prepared its oil and gas reserve estimates as of December 31, 2009 using the average, first-day-of-the- month price during the 12-month period ending December 31, 2009. In prior years, the Company used the year-end price. The Company calculates depreciation, depletion and amortization on a quarterly basis using estimated reserves as of the end of each quarter. As a result, the new rules impacted the amount of depreciation, depletion and amortization recorded for oil and gas properties and the ceiling test calculation for the quarter ended December 31, 2009. In addition, under the new guidance, subsequent price increases cannot be considered in the ceiling test calculation.
The adoption of the new rules is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or financial statements. The Company does not believe that it is practicable to estimate the effect of applying the new rules on net loss or the amounts recorded for depreciation, depletion and amortization and ceiling impairment for the year ended December 31, 2009.
In January 2010 the FASB issued new accounting guidance related to fair value measurements that requires additional disclosures surrounding transfers in and out of Levels 1 and 2, inputs and valuation techniques used to value Level 2 and 3 measurements, and push down of previously prescribed fair value disclosures to each class of asset and liability for Levels 1, 2, and 3. This new authoritative guidance is effective for interim and annual reporting periods beginning after December 15, 2009. The Company will apply the new authoritative guidance in the Company's March 31, 2010, Quarterly Report on Form 10-Q. The guidance also requires that purchases, sales, issuances, and settlements for Level 3 measurements be disclosed. This portion of the new authoritative guidance is effective for interim and annual reporting periods beginning after December 15, 2010. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.
Note 2—Property and Equipment
Property and equipment consists of the following:
|
|
December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | |||||
|
|
(In thousands)
|
||||||
|
Building |
$ | 1,420 | $ | 1,420 | |||
|
Computer hardware and software |
1,013 | 1,013 | |||||
|
Machinery, equipment and vehicles |
1,692 | 1,686 | |||||
|
Office furniture and equipment |
212 | 212 | |||||
|
|
4,337 | 4,331 | |||||
|
Less accumulated depreciation and amortization |
(3,282 | ) | (2,533 | ) | |||
|
Total |
$ | 1,055 | $ | 1,798 | |||
Depreciation and amortization expense related to property and equipment for the years ended December 31, 2009, 2008 and 2007, was $842,000, $1,012,000, and $792,000 respectively.
83
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 3—Acquisitions and Divestitures
2007 Transactions
There were no significant acquisitions or divestitures of property in 2007.
2008 Transactions
There were no significant acquisitions or divestitures of property in 2008.
2009 Transactions
The Company sold its high pressure gas gathering system in the Cabin Creek project area in Wyoming, and its remaining interest in the Arvada project area in Wyoming in April 2009. The Company received approximately $3.2 million in net proceeds from these sales, and used part of such proceeds to repay a portion of its indebtedness outstanding under the credit facility and used the remainder for general operating purposes.
Note 4—Unevaluated Properties
The Company is currently participating in coalbed methane gas exploration and development activities on acreage in Montana and Wyoming. At December 31, 2009, a determination could not be made about the extent of additional gas reserves that should have been classified as proved reserves as a result of the exploration activities to date. Consequently, the associated property costs and exploration costs have been excluded in computing DD&A for the full cost pool. The Company will begin to calculate DD&A on these costs when the project is evaluated, which is currently estimated to be over the next one to five years. These costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. For the year ending December 31, 2009 impairments of $36.7 million were incurred on unevaluated properties.
Costs excluded from amortization relating to unproved properties at December 31, 2009 are as follows (in thousands):
|
Period Incurred
|
Acquisition
Costs |
Exploration
Costs |
Capitalized
Interest |
Total | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2003 |
$ | 12,915 | $ | — | $ | — | $ | 12,915 | |||||
|
2004 |
112 | — | — | 112 | |||||||||
|
2005 |
13,167 | 1,418 | 148 | 14,733 | |||||||||
|
2006 |
30,316 | 27,018 | — | 57,334 | |||||||||
|
2007 |
1,147 | 2,579 | — | 3,726 | |||||||||
|
2008(1) |
(3,378 | ) | 1,186 | 199 | (1,993 | ) | |||||||
|
2009(1) |
(40,429 | ) | 1,861 | 441 | (38,127 | ) | |||||||
|
|
$ | 13,850 | $ | 34,062 | $ | 788 | $ | 48,700 | |||||
84
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 4—Unevaluated Properties (Continued)
Suspended Wells Costs
The following table reflects the net changes in capitalized exploratory well costs during 2009 and 2008, and does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same period.
|
|
For the Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | |||||
|
|
(In thousands)
|
||||||
|
Beginning balance |
$ | 32,201 | $ | 31,015 | |||
|
Additions to capitalized exploratory well costs pending determination of proved reserves |
2,339 | 5,551 | |||||
|
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves |
(478 | ) | (4,365 | ) | |||
|
Ending balance |
$ | 34,062 | $ | 32,201 | |||
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized since the completion of drilling:
|
|
For the Years Ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
|
(In thousands)
|
|||||||||
|
Exploratory well costs capitalized for one year or less |
$ | 2,339 | $ | 5,551 | $ | 6,659 | ||||
|
Exploratory well costs capitalized for more than one year |
31,723 | 26,650 | 24,356 | |||||||
|
Ending balance at December 31, |
$ | 34,062 | $ | 32,201 | $ | 31,015 | ||||
|
Number of projects with exploratory well costs that have been capitalized more than a year |
3 | 3 | 3 | |||||||
Note 5—Accrued Liabilities
Accrued liabilities consist of the following:
|
|
December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | |||||
|
|
(In thousands)
|
||||||
|
Production taxes |
$ | 3,342 | $ | 2,573 | |||
|
Payroll and related taxes |
133 | 122 | |||||
|
|
3,475 | 2,695 | |||||
|
Less production taxes due after one year |
(385 | ) | (1,156 | ) | |||
|
Total |
$ | 3,090 | $ | 1,539 | |||
85
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 5—Accrued Liabilities (Continued)
Accrued liabilities consist of production taxes and payroll expenses that are attributable to the fiscal year end but are not payable until after fiscal year end.
Note 6—Derivatives
Hedging Contracts
As of December 31, 2009, 2008 and 2007, the Company had natural gas hedges in place as follows:
|
Product and Type of Hedging Contract
|
MMbtu Per
Day |
Fixed Price
Range CIG Index Price |
Time
Period |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
December 31, 2009 |
||||||||||
|
Natural Gas—Swap |
2,500 | $3.45–$3.45 | 01/10–04/10 | |||||||
|
Natural Gas—Swap |
2,000 | $4.48–$4.48 | 01/10–12/10 | |||||||
|
Natural Gas—Swap |
1,000 | $5.50–$5.50 | 01/10–12/10 | |||||||
|
Natural Gas—Swap |
2,500 | $5.40–$5.40 | 05/10–12/10 | |||||||
|
December 31, 2008 |
||||||||||
|
Natural Gas—Collar |
2,000 | $6.50–$7.50 | 01/09–12/09 | |||||||
|
Natural Gas—Swap |
2,500 | $7.17–$7.17 | 01/09–12/09 | |||||||
|
December 31, 2007 |
||||||||||
|
Natural Gas—Collar |
3,000 | $6.50–$8.20 | 01/08–12/08 | |||||||
The Company has elected not to designate these derivatives as cash flow hedges under authoritative guidance prescribed by the FASB. These derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying statements of operations. The aggregate fair values of these contracts were estimated to be a liability totaling $1,375,000 and an asset of $4,345,000 at December 31, 2009 and 2008, respectively. The Company realized hedging gains in 2009, 2008 and 2007 of $6,642,000, $1,973,000 and $4,511,000, respectively which amounts are included in realized gains on derivatives in the statement of operations and are included in the cash flows from investing activities in the statements of cash flows. As a result of the change in the fair value of the commodity derivatives, the Company had an unrealized loss of $5,720,000 for the year ended December 31, 2009, an unrealized gain of $3,789,000 for the year ended December 31, 2008, and an unrealized loss of $2,300,000 for the year ended December 31, 2007. Unrealized and realized gains and losses are included in unrealized gains/losses on derivatives in the statement of operations.
86
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 6—Derivatives (Continued)
Due to the volatility of natural gas prices, the estimated fair value of the Company's commodity derivative instruments are subject to large fluctuations from period to period.
|
|
Location on
Consolidated Balance Sheets |
Fair Value at
December 31, 2009 |
Fair Value at
December 31, 2008 |
||||||
|---|---|---|---|---|---|---|---|---|---|
|
|
|
(In thousands)
|
(In thousands)
|
||||||
|
Derivative assets: |
|||||||||
|
Natural gas, commodity |
Current assets | $ | — | $ | 4,345 | ||||
|
Natural gas, commodity |
Noncurrent assets | $ | — | $ | — | ||||
|
Total derivative assets |
$ | — | $ | 4,345 | |||||
|
Derivative liabilities: |
|||||||||
|
Natural gas, commodity |
Current liabilities | $ | 1,375 | $ | — | ||||
|
Natural gas, commodity |
Noncurrent liabilities | $ | — | $ | — | ||||
|
Total derivative liabilities |
$ | 1,375 | $ | — | |||||
The Company is exposed to collateral requirements with the counterparty based on the fair value of the derivative contracts. The Company is currently not required to post collateral or cash on property with the counterparty.
The Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.
Note 7—Revenue Distributions Payable
Revenue distributions payable consist of the following:
|
|
December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | |||||
|
|
(In thousands)
|
||||||
|
Revenue payable on current production |
$ | 592 | $ | 924 | |||
|
Revenues payable in suspense |
2,736 | 3,701 | |||||
|
Total revenues payable |
$ | 3,328 | $ | 4,625 | |||
The Company operates and disburses revenue to other working interest owners and royalty owners. Proceeds from gas sales are distributed and paid approximately 45 days after the end of the respective sales month. Revenue held in suspense is due primarily to the issuance of title opinions for wells in which the Company holds funds to distribute. Once a title opinion is received, revenue held in suspense is placed in line for payment under the normal payment cycle indicated above.
Note 8—Line-of-Credit
Effective February 12, 2007, the Company entered into a credit facility which permits borrowings up to the borrowing base as designated by the administrative agent. As of December 31, 2009 and December 31, 2008, it had $6.1 million and $11.5 million, respectively, of debt outstanding under the
87
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 8—Line-of-Credit (Continued)
facility. As described below, the Company is currently unable to borrow additional amounts under the credit facility due to covenant limitations.
As of December 31, 2008, the borrowing base under the credit facility was approximately $13.2 million. The borrowing base was subject to automatic reductions for approximately $666,667 per month until it reached $10.5 million on April 1, 2009. As of April 14, 2009, the borrowing base was further reduced to $9.0 million, subject to automatic reductions of $500,000 per month until it reached $6.5 million on October 1, 2009. As of October 20, 2009, the borrowing base was subject to automatic reductions of $200,000 per month until it reaches maturity or until a redetermination is received.
The borrowing base is determined on a semi-annual basis and at such other additional times, up to twice yearly, as may be requested by either the Company or the administrative agent and is determined by the administrative agent in accordance with customary practices and standards for loans of a similar nature, although such determination is at the administrative agent's discretion as the credit agreement does not provide a specific borrowing base formula.
Borrowings under this credit facility may be used solely to acquire, explore or develop oil and gas properties and for general corporate purposes. The credit facility matures June 15, 2010.
The Company's obligations under the credit facility are secured by liens on (i) no less than 90% of the net present value of the oil and gas to be produced from its oil and gas properties that are included in the borrowing base determination, calculated using a discount rate of 10% per annum and reserve estimates, prices and production rates and costs, (ii) options to lease, seismic options, permits, and records related to such properties, and (iii) seismic data.
Borrowings under the Company's credit facility, as amended, bear interest either: (i) at the greater of the one month London Interbank Offered Rate, or LIBOR, plus 1.00% or a domestic bank rate, plus in either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) on a sliding scale from the one, two, three or six month LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization. The weighted average interest rate as of September 30, 2009 was 5.0%. The credit agreement provides for various fees, including a quarterly commitment fee of 0.5% per annum and engineering fees to the administrative agent in connection with a borrowing base determination. In addition, the credit facility provided for an up front fee of $27,000, which was paid on the closing date of the credit facility, and an additional arrangement fee of 1% based on utilization. Borrowings under this credit facility may be prepaid without premium or penalty, except on Eurodollar advances.
The credit agreement contains covenants that, among other things, restrict the Company's ability, subject to certain exceptions, to do the following:
88
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 8—Line-of-Credit (Continued)
With regard to hedging arrangements, the Company's credit agreement provides that acceptable commodity hedging arrangements cannot cover greater than 80 to 85%, depending on the measurement date, of it's monthly production from its hydrocarbon properties that are used in the borrowing base determination, and that the fixed or floor price of its hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.
The credit agreement, as amended, also requires that the Company satisfy certain affirmative covenants, meet certain financial tests, maintain certain financial ratios and make certain customary indemnifications to lenders and the administrative agent. The financial covenants include requirements to maintain: (i) a ratio of EBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) a ratio of current assets to current liabilities of not less than 1.00 to 1.00, (iii) a total debt to annualized EBITDA ratio of not more than 3.0 to 1.0, (iv) a quarterly total senior debt to annualized EBITDA ratio equal to or less than 3.0 to 1.0, and (v) a total proved PV-10 value to total debt ratio of at least 1.50 to 1.00.
The credit agreement, as amended, contains customary events of default, including payment defaults, covenant defaults, certain events of bankruptcy and insolvency, defaults in the payment of other material debt, judgment defaults, breaches of representations and warranties, loss of material permits and licenses and a change in control. The credit agreement requires any wholly-owned subsidiaries to guarantee the obligations under the credit agreement.
After an event of default, the outstanding debt bears interest at the default rate under the terms of the credit agreement. The default rate is (i) with respect to principal, 2% over the otherwise applicable rate and (ii) with respect to interest, fees and other amounts, the Base Rate (as defined in the credit facility), plus the Applicable Margin (as defined in the credit agreement), plus 2%. Any default interest is payable on demand. Failure to pay the default interest when the administrative agent demands, would be another default. The lenders' remedies for defaults under the credit agreement are to terminate further borrowings, accelerate the repayment of indebtedness and/or ultimately foreclose on the collateral property.
Effective August 4, 2008, the Company and the administrative agent and lender entered into the second amendment to the credit agreement (the "second amendment"). The second amendment provided, among other things, for (i) an increase in the total quarterly senior debt to annualized EBITDA ratio from 2.0 to 1.0, to 3.0 to 1.0, (ii) an increase in interest at each utilization level for LIBOR borrowings, (iii) the amendment of the utilization calculation to be determined as the greater of (x) the percentage of credit exposure over the borrowing base or (y) the percentage of credit exposure over three times EBITDA minus permitted subordinated debt, and (iv) the payment of an amendment fee.
Effective September 30, 2008, the Company and the administrative agent and lender entered into the third amendment to the credit agreement (the "third amendment"). In addition to waiving compliance with the current ratio covenant as of September 30, 2008, the third amendment, among other things, required that immediately prior to any additional borrowings under the credit agreement, the ratio of current assets to current liabilities be not less than 1.00 to 1.00. As a result of this new
89
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 8—Line-of-Credit (Continued)
condition to additional borrowings, the Company is currently unable to borrow additional amounts under the credit agreement. The third amendment also increased the interest rate payable under the credit agreement to either (i) the greater of the one month LIBOR plus 1.00% or a domestic bank rate, plus in either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) a sliding scale from the one, two, three or six month LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization, and provided for the payment of an amendment fee.
On April 14, 2009, the Company and the administrative agent entered into the fourth amendment to the credit agreement which reduced the borrowing base as described above and waived compliance with the current ratio financial covenant as of December 31, 2008 and March 31, 2009 and with the restrictive covenants related to accounts payable, permitted liens and permitted debt until the current ratio financial covenant and next borrowing base redetermination, subject to certain financial caps. On August 19, 2009, the lenders waived compliance with the current ratio financial covenant under the Credit Agreement for the period ending August 26, 2009 and the quarter ending June 30, 2009.
On August 26, 2009, the Company entered into a fifth amendment to the credit agreement which provided a waiver of the current ratio covenant through October 26, 2009 and for the quarter ending June 30, 2009. The fifth amendment to the credit agreement also extended restrictive covenants related to accounts payable, permitted liens and permitted debt, until October 26, 2009, subject to certain financial caps.
On October 20, 2009, the Company and the Lenders executed the sixth amendment to the credit agreement. This amendment established the borrowing base for the following amounts in the following applicable periods:
|
December 1, 2009 through December 31, 2009 |
$ | 6,300,000 | ||
|
January 1, 2010 through January 31, 2010 |
$ | 6,100,000 | ||
|
February 1, 2010 through February 28, 2010 |
$ | 5,900,000 | ||
|
March 1, 2010 through March 31, 2010 |
$ | 5,700,000 | ||
|
April 1, 2010 through April 30, 2010 |
$ | 5,500,000 |
Each Calendar month thereafter commencing May 1, 2010; the borrowing base for the preceding calendar month reduced by $200,000.
On October 26, 2009, the lenders provided a waiver effectively extending the terms of the fifth amendment to the credit agreement through November 16, 2009. On November 16, 2009, the lenders provided an additional waiver effectively extending the terms of the fifth amendment to the credit agreement through November 23, 2009.
On November 23, 2009, the lenders provided an additional waiver extending the terms of the fifth amendment to the credit agreement through December 1, 2009 and for the quarter ended September 30, 2009.
On January 13, 2010, the Company entered into a seventh amendment and waiver to credit agreement (" waiver agreement ") with the lenders party thereto. The waiver agreement provided that the lenders would waive (i) the Company's compliance with certain restrictions based on the current ratio in the credit agreement, (ii) certain requirements of the Company pertaining to the aging of certain accounts payable, and (iii) certain restrictions regarding the amount of liens of the Company. Default remedies available to the lenders under the credit agreement include acceleration of all principal and
90
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 8—Line-of-Credit (Continued)
interest amounts due under the credit agreement. The waiver agreement extends the waiver period for these items until the earlier of June 15, 2010 and the date of any default arising out of a breach or non-compliance with the credit agreement not expressly waived in the waiver agreement or a breach of the waiver agreement.
In addition, the waiver agreement amends the definition of "Final Maturity Date" under the credit agreement to the earlier of (i) June 15, 2010 or (ii) the date that is thirty days following the earlier of (A) the date the merger (please see Note 19) is withdrawn or terminated in whole or in part or (B) the date that the lenders have been advised that the merger will not proceed.
The Company is actively marketing certain assets to raise additional capital and it is also reviewing alternatives for raising additional capital through equity and debt financing, capital restructuring and possible mergers (please see Note 19). The Company sold its high pressure gas gathering system in its Cabin Creek project area in Wyoming and the Company's remaining interest in the Arvada project area in Wyoming in April 2009. The Company's management believes that appropriate steps, including cost-cutting measures, are being taken to make operations sustainable in the future. Although the Company is pursuing various alternatives to provide additional liquidity, there is no assurance of the likelihood or timing of any of these transactions.
Note 9—Other Long-Term Debt Obligations
Long-term debt and capital lease obligations consist of the following:
|
|
December 31, | ||||||
|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | |||||
|
|
(In thousands)
|
||||||
|
Note payable to a bank with interest at 6.875% until December 15, 2008 when it goes to Wells Fargo prime plus 1 / 2 %. On November 15, 2008 the rate changed from a fixed rate of 6.875% to a variable rate. As of December 31, 2009 this variable rate was 4.00%. The note is due in monthly installments through November 15, 2015 when unpaid principal and interest are due. The note is collateralized by the building |
$ | 733 | $ | 763 | |||
|
Less current portion |
(33 | ) | (30 | ) | |||
|
Capital lease |
58 | — | |||||
|
Less current portion |
(15 | ) | — | ||||
|
Total |
$ | 743 | $ | 733 | |||
91
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 9—Other Long-Term Debt Obligations (Continued)
The following are future minimum obligations for long-term debt as of December 31, 2009 (in thousands):
|
Years Ending December 31: |
||||
|
2010 |
$ | 48 | ||
|
2011 |
52 | |||
|
2012 |
55 | |||
|
2013 |
45 | |||
|
2014 |
39 | |||
|
Thereafter |
552 | |||
|
Total |
$ | 791 | ||
Note 10—Fair Value Measurements
Effective January 1, 2008, the Company adopted the authoritative guidance that applies to all financial assets and liabilities required to be measured and reported on a fair value basis. Beginning January 1, 2009, the Company also applied the guidance to non-financial assets and liabilities measured at fair value on a nonrecurring basis, including proved oil and gas properties and other long-lived assets and asset retirement obligations initially measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The financial and nonfinancial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
92
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 10—Fair Value Measurements (Continued)
The following is a listing of the Company's assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2009 (in thousands):
|
|
Level 1 | Level 2 | Level 3 | Total | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Liabilities |
||||||||||||||
|
Oil and gas derivative instruments |
$ | — | $ | 1,375 | $ | — | $ | 1,375 | ||||||
|
Total |
$ | — | $ | 1,375 | $ | — | $ | 1,375 | ||||||
As of December 31, 2009, the Company's derivative financial instruments are comprised of four natural gas swap agreements. The fair values of the swap agreements are determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivatives and are therefore considered Level 2 in the fair value hierarchy.
The Company's estimate of the fair value of derivative financial instruments includes consideration of the counterparty's credit worthiness, the Company's credit worthiness, and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant's view.
Note 11—Income Taxes
The provision for income taxes consists of the following:
|
|
December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
|
(In thousands)
|
|||||||||
|
Current income tax expense |
$ | — | $ | — | $ | — | ||||
|
Deferred income tax expense (benefit) |
23,271 | 8,963 | 7,765 | |||||||
|
Change in valuation allowance |
(23,271 | ) | (8,963 | ) | (7,765 | ) | ||||
|
Total income tax benefit |
$ | — | $ | — | $ | — | ||||
The effective income tax rate varies from the statutory federal income tax rate as follows:
|
|
December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
Federal income tax rate |
(34 | )% | (34 | )% | (34 | )% | ||||
|
Change in valuation allowance and other |
34 | 34 | 34 | |||||||
|
Effective tax rate |
— | % | — | % | — | % | ||||
93
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 11—Income Taxes (Continued)
The significant temporary differences and carry-forwards and their related deferred tax asset (liability) and deferred tax asset valuation allowance balances are as follows:
|
|
December 31, | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||||
|
|
(In thousands)
|
|||||||||||
|
Deferred tax assets |
||||||||||||
|
Net operating loss carry-forward |
$ | 18,622 | $ | 13,862 | $ | 10,996 | ||||||
|
Oil and gas properties |
19,879 | 3,542 | — | |||||||||
|
Property and equipment |
333 | 284 | — | |||||||||
|
Percentage depletion |
566 | 463 | — | |||||||||
|
Unrealized loss on hedges |
468 | — | — | |||||||||
|
Other |
380 | 302 | 141 | |||||||||
|
Gross deferred tax assets |
40,248 | 18,454 | 11,137 | |||||||||
|
Deferred tax liabilities |
||||||||||||
|
Oil and gas properties |
— | — | 2,893 | |||||||||
|
Property and equipment |
— | — | 41 | |||||||||
|
Impairments and abandonments |
— | — | — | |||||||||
|
Unrealized gain on hedges |
— | 1,477 | 189 | |||||||||
|
Gross deferred tax liabilities |
— | 1,477 | 3,123 | |||||||||
|
Net deferred tax asset |
40,248 | 16,977 | 8,014 | |||||||||
|
Less valuation allowance |
(40,248 | ) | (16,977 | ) | (8,014 | ) | ||||||
|
Deferred tax asset |
$ | — | $ | — | $ | — | ||||||
For income tax purposes at December 31, 2009, the Company has net operating loss carry-forwards of approximately $54,770,000 which expire in 2029. The Company has provided for a valuation allowance of $40,248,000 due to the uncertainty of realizing the tax benefits from its net deferred tax asset.
On January 1, 2007, the Company adopted accounting provisions that prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This provision requires that the Company recognize in its financial statements only those tax positions that are "more-likely-than-not" of being sustained as of the adoption date, based on the technical merits of the position. As a result of the implementation of this provision, the Company performed a comprehensive review of its material tax positions in accordance with recognition and measurement standards established by this provision.
As a result of this review, the Company did not identify any material deferred tax assets that required adjustment. As of January 1, 2007, the date of adoption of this provision, and as of December 31, 2009 and 2008, the Company had not recorded any material uncertain tax benefits.
The Company's policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2009, the Company has not recognized any interest or penalties in its statement of operations or statement of financial position.
The Company is subject to the following material taxing jurisdictions: U.S. federal. The Company also has material operations in the state of Wyoming; however, Wyoming does not impose a corporate
94
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 11—Income Taxes (Continued)
income tax. The Company also has material operations in the state of Montana and is subject to a corporate income tax on income generated in that jurisdiction. The tax years that remain open to examination by the U.S. Internal Revenue Service are years 2005 through 2009. Due to the Company's net operating loss carry forwards, the Internal Revenue Service may also adjust the amount of loss realizable under examination back to 2003.
Note 12—Stock Option Plans
Options Under Employee Option Plans
The Company has adopted stock option plans containing both incentive and non-statutory stock options. All options allow for the purchase of common stock at prices not less than the fair market value of such stock at the date of grant. If the option holder owns more than 10% of the total combined voting power of all classes of the Company's stock, the exercise price cannot be less than 110% of the fair market value of such stock at the date of grant.
Options granted under the plans become vested as directed by the Company's Board of Directors and generally expire seven or ten years after the date of grant, unless the option holder owns more than 10% of the total combined voting power of all classes of the Company's stock, in which case the non-statutory stock options must be exercised within five years of the date of grant. The Company granted 0, 0 and 120,000 options to employees under the plans during the years ended December 31, 2009, 2008 and 2007, respectively. At December 31, 2009, there were 603,728 shares available for grant under the plans.
The options granted all vest as follows:
|
Year 1 |
20 | % | ||
|
Year 2 |
30 | |||
|
Year 3 |
50 | |||
|
|
100 | % | ||
At December 31, 2009, the Company had unvested options to purchase 12,500 shares. During the year ended December 31, 2009, the Company did not grant employee options and recognized compensation expense of approximately $283,000 for options granted in prior years. The Company will recognize compensation expense relating to non-vested options granted after January 1, 2006 of approximately $25,000 over the next year.
95
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 12—Stock Option Plans (Continued)
The following table summarizes stock option activity for the years ended December 31, 2009, 2008 and 2007:
|
|
Number of Shares | Weighted Average Exercise Price per Share | Weighted Average Remaining Contractual Life | Aggregate Intrinsic Value | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Outstanding, December 31, 2006 |
1,035,000 | $ | 6.68 | ||||||||||
|
Granted |
120,000 | 10.03 | |||||||||||
|
Canceled or forfeited |
(284,000 | ) | 8.47 | ||||||||||
|
Outstanding, December 31, 2007 |
871,000 | $ | 6.56 | ||||||||||
|
Canceled or forfeited |
(194,750 | ) | $ | 8.74 | $ | — | |||||||
|
Outstanding, December 31, 2008 |
676,250 | $ | 5.93 | 3.40 | $ | — | |||||||
|
Canceled or forfeited |
(36,250 | ) | $ | — | |||||||||
|
Outstanding, December 31, 2009 |
640,000 | $ | 5.81 | 2.33 | $ | — | |||||||
|
Exercisable at December 31, 2009 |
627,500 | $ | 5.76 | 2.29 | $ | — | |||||||
The following table summarizes information about stock options outstanding at December 31, 2009:
|
|
Options Outstanding |
|
|
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Options Exercisable | ||||||||||||
|
|
|
Weighted Average Remaining Contractual Life |
|
||||||||||
|
Exercise Prices
|
Number of Shares Outstanding | Number Exercisable | Weighted Average Exercise Price |
Fair Value
Determination |
|||||||||
|
$4.00 |
137,500 | 0.8 years | 137,500 | $ | 4.00 | Black-Scholes (minimum value) | |||||||
|
$4.80 |
265,500 | 2.2 years | 265,000 | $ | 4.80 | Black-Scholes (minimum value) | |||||||
|
$5.20 |
112,500 | 3.0 years | 112,500 | $ | 5.20 | Black-Scholes | |||||||
|
$8.40 |
25,000 | 4.4 years | 12,500 | $ | 8.40 | Black-Scholes | |||||||
|
$11.00 |
100,000 | 3.5 years | 100,000 | $ | 11.00 | Black-Scholes | |||||||
|
|
640,000 | 627,500 | |||||||||||
Stock Appreciation Rights under Stock Incentive Plan
The Company has adopted a stock incentive plan authorizing the grant of Stock Appreciation Rights ("SARs"). A SAR confers on the participant a right to receive, upon exercise, the excess of the fair market value of a share of Common Stock on the date of the exercise over $1.00. Such excess shall be paid in cash or common stock or a combination thereof to the participant. On June 1, 2009, 202,280 SARs were granted to certain employees with a seven year contractual life and are currently outstanding as of December 31, 2009.
The SARs granted in June 2009 vest in general as follows:
|
Year 1 |
33.33 | % | ||
|
Year 2 |
33.33 | % | ||
|
Year 3 |
33.34 | % |
96
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 12—Stock Option Plans (Continued)
For the year ended December 31, 2009, the Company recognized compensation expense of approximately $15,000.
As of December 31, 2009, the Company had approximately $61,000 of unrecognized compensation expense related to non-vested SAR awards.
Restricted Stock
The Company has an incentive program whereby grants of restricted stock have been awarded to members of the Board of Directors and certain employees. Restrictions and vesting periods for the awards are determined at the discretion of the Board of Directors and are set forth in the award agreements.
On June 1, 2009, the Company issued 202,280 shares of restricted stock to certain employees. These shares will vest 33.34%, 33.33% and 33.33% on the first, second and third anniversary of the grant date. On June 1, 2009, the Company issued 331,822 shares of restricted stock to non employee directors which vested on June 30, 2009. The Company issued 189,586 shares of restricted stock to non employee directors which vested on September 30, 2009. The Company also issued 196,326 on December 1, 2009 which vested on December 31, 2009. The Company recognized an expense of approximately $548,000, $571,000, and $356,000 for the years ended December 31, 2009, 2008, and 2007 respectively, based on the fair value of the vested shares during the period.
A summary of the status and activity of the restricted stock for the years ended December 31, 2009 and 2008 is presented below.
|
|
Shares |
Weighted-Average
Grant-Date Fair Value |
|||||
|---|---|---|---|---|---|---|---|
|
Non-vested at December 31, 2006 |
27,270 | $ | 11.00 | ||||
|
Granted |
155,500 | 8.41 | |||||
|
Forfeited |
(17,050 | ) | 9.67 | ||||
|
Vested |
(9,090 | ) | 11.00 | ||||
|
Non-vested at December 31, 2007 |
156,630 | $ | 8.57 | ||||
|
Granted |
244,650 | 2.79 | |||||
|
Forfeited |
(70,828 | ) | 6.41 | ||||
|
Vested |
(126,875 | ) | 4.71 | ||||
|
Non-vested at December 31, 2008 |
203,577 | $ | 4.78 | ||||
|
Granted |
920,014 | 0.37 | |||||
|
Forfeited |
(5,564 | ) | 6.05 | ||||
|
Vested |
(775,034 | ) | 0.69 | ||||
|
Non-vested at December 31, 2009 |
342,993 | $ | 2.18 | ||||
As of December 31, 2009, the Company had $0.5 million of unrecognized share-based compensation expense related to non-vested stock awards, which is expected to be amortized over the remaining period of 3 years.
97
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 13—Redeemable Preferred Stock
Series A Redeemable Preferred Stock
The Company is authorized by the certificate of incorporation to issue up to 25,000,000 shares of preferred stock in one or more series, having rights senior to the shares of common stock. As of December 31, 2009 and 2008 there were no shares of preferred stock issued and outstanding. All of the issued and outstanding shares of the Company's Series A Redeemable Preferred Stock Shares ("Preferred Stock") with a par value of $0.01 were redeemed with proceeds from the Company's April 2006 private placement. Shares of the Preferred Stock had a liquidation value of $100 per share and had preference to shares of the Company's common stock. Through the period ending on the seventh anniversary of the issue date at which time the dividends would have accrued at 12.5%, the Preferred Stock would have accrued dividends at the rate of 10.5% per annum compounded quarterly. The Preferred Stock had no stated maturity date. Holders of Preferred Stock had the right to vote on all matters voted on by holders of common stock. During the years ended December 31, 2009, 2008 and 2007, the Company issued no shares of Preferred Stock.
Note 14— Stockholders' Equity
Common Stock
As of December 31, 2009, there were 30,108,023 shares of common stock issued and outstanding. The Company is authorized to issue 100,000,000 shares of common stock, par value $0.01.
At formation, the Company issued an aggregate of 3,750,000 shares of common stock, par value $0.01 per share, in equal portions to a subsidiary of Carrizo and to Rocky Mountain Gas Inc., a former subsidiary of U.S. Energy, in exchange for the contribution of interests in approximately 81,000 gross (40,000 net) acres, including proved producing properties and undeveloped leaseholds, valued at $15.0 million. The 1,875,000 shares held by Rocky Mountain Gas were transferred to its affiliates, U.S. Energy and Crested Corp., in May 2005. The Company issued an additional 1,250,000 shares of common stock at formation to CSFB in exchange for a cash contribution of $5.0 million minus offering costs of $113,000. On November 18, 2005, the Company issued an additional 750,000 shares of common stock to CSFB in connection with the exercise of Series B warrants. On November 30, 2005, Gary W. Uhland, the Company's former President, exercised options to acquire 50,000 shares of its common stock and the Company received $167,000.
In April 2006, the Company completed a private placement, exempt from registration under the Securities Act, of 12,835,230 shares of common stock to qualified institutional buyers, non-U.S. persons and accredited investors at a price of $11.00 per share (gross proceeds of $141.2 million), or $10.23 per share net of the initial purchaser's discount and placement fee. The gross proceeds were used to pay $11.3 million in placement fees and offering costs, $53.6 million for the redemption of all outstanding shares of Series A Redeemable Preferred Stock and all unpaid accrued dividends, $27.0 million for the acquisition of undeveloped assets in the Green River Basin, $16.3 million for the repurchase of 1,593,783 shares of common stock from CSFB and the Company's former President, and $33.0 million for future capital expenditures and general corporate purposes.
In May 2007, the Company completed an initial public offering of an aggregate of 3,750,000 shares of common stock at a price per share of $9.00, or $8.37 net of underwriters' discounts and commissions. In June 2007, the underwriters partially exercised their over-allotment option to purchase 258,614 shares of the Company's common stock from certain selling stockholders. The Company received proceeds of approximately $29.5 million from its initial public offering, net of underwriters'
98
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 14— Stockholders' Equity (Continued)
discount and commissions and additional out of pocket offering costs of approximately $1.9 million. The proceeds were used to pay down the $7.0 million outstanding under the credit agreement and for capital expenditures, infrastructure development and general corporate purposes.
Note 15—Commitments and Contingencies
Operating Lease
Upon purchase of the building in August 2005, Pinnacle was assigned the lease agreements for existing tenants in the building. The leases expire from January 2010 to January 2013. Future minimum lease income under noncancelable operating leases is as follows:
|
Year Ending December 31,
|
|
|||
|---|---|---|---|---|
|
2010 |
$ | 105,000 | ||
|
2011 |
60,000 | |||
|
2012 |
44,000 | |||
|
2013 |
44,000 | |||
|
Total minimum lease payments |
$ | 253,000 | ||
Gas Gathering Contracts
The Company has entered into gas gathering and compression agreements with service providers in order to compress and transport its gas to the point of sale. Compression agreements and gathering agreements are based on a fee per Mcf either compressed or gathered. The Company accounts for these fees as a marketing and transportation expense. The Company does not pay or charge marketing fees associated with the movement and sale of natural gas.
Employment Agreements
The Company entered into new employment agreements with the Chief Executive Officer (Mr. Schoonmaker) and Chief Financial Officer (Mr. Barnes) on July 20, 2007, effective January 1, 2007. The initial term of these agreements is one year and the agreements will automatically renew for additional one-year terms unless either party gives 60 days prior written notice. Under Mr. Schoonmaker's employment agreement, he is entitled to an initial base salary of $250,000, subject to annual adjustment, and an annual bonus of up to 1.0 times his then current base salary, payable in cash or in stock. Under Mr. Barnes' employment agreement, he is entitled to an initial base salary of $200,000, subject to annual adjustment, and an annual bonus of up to 0.75 times his then current base salary, payable in cash or in stock.
If either executive's employment is terminated by the Company without cause or by either executive for good reason, the executive will be entitled to severance benefits which will include a lump sum payment equal to the sum of (i) 1.0 times his annual base salary plus (ii) 18.0 times the monthly health savings account contribution last made by the Company for his benefit, and the payment of a pro-rated bonus. Additionally, if either executive's employment is terminated by the Company without cause or by either executive for good reason or due to retirement, in each case within one year following a change of control of the Company, the executive will be entitled to severance benefits which will include a lump sum payment equal to 1.5 times his annual base salary and the payment of a pro-rated bonus. In each case, any and all stock options, restricted stock awards and other equity
99
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 15—Commitments and Contingencies (Continued)
compensation awards held by the executive will immediately vest and become exercisable. In the event that either executive's employment is terminated within six months preceding or following a change of control due to a non-renewal of his employment agreement by the Company, the executive will be entitled to the same change of control severance benefit described above.
Litigation
From time to time, the Company is subject to legal proceedings and claims that arise in the ordinary course of its business. In addition, like other natural gas and oil producers and marketers, the Company's operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As a result, it is extremely difficult to reasonably quantify future environmental and regulatory related expenditures.
The following represent legal actions in which the Company is involved. No assurance can be given that these legal actions will be resolved in the Company's favor. However, the Company's management believes, based on its experiences to date, that these matters will not have a material adverse impact on the Company's business, financial position or results of operations.
The Company, together with the State of Montana, the Montana Department of Environmental Quality, the Montana Board of Oil and Gas Conservation and the Department of Natural Resources, were named as defendants in a lawsuit (Civil Cause No. DV-05-27) filed on May 19, 2005 in the Montana 22nd Judicial District Court, Bighorn County by Diamond Cross Properties, LLC relating to the Coal Creek POD. The plaintiff is a surface owner with properties located in Big Horn County and Rosebud County, Montana where the Company has a lease for approximately 10,300 acres, serves as operator and owns a working interest in the minerals under lease. The plaintiff sought to permanently enjoin the State of Montana and its administrative bodies from issuing licenses or permits, or authorizing the removal of ground water from under the plaintiff's ranch. In addition, the plaintiff further sought to preliminarily and permanently enjoin the Company on the basis that the Company's operations lacked adequate safeguards required under the Montana state constitution. On August 25, 2005, the district judge issued an order denying without prejudice the application for temporary restraining order and preliminary injunction requested by the plaintiff. The case was appealed by the plaintiff to the Montana Supreme Court. On November 16, 2005, the Montana Supreme Court issued an order that denied enjoining the Coal Creek POD, and subsequently, the Montana Supreme Court remanded the case back to the district court for a decision on the merits.
The Company, together with the defendants above, were also named as defendants in a related lawsuit (Civil Cause No. DV-05-70) filed on September 21, 2005 in the Montana 22nd Judicial District Court, Bighorn County by Diamond Cross Properties, LLC relating to the Dietz POD. The plaintiff sought similar relief as in the Coal Creek POD suit. The two cases were combined.
On July 14, 2008, the district court issued a summary judgment order in the combined case, and the order was subsequently entered as a judgment on August 15, 2008. As a result, the Company has continued its operations in the two project areas. To date, there has been no appeal by the plaintiff.
In April and September 2005, the U.S. Bureau of Land Management in Miles City, Montana issued suspensions of operations for the majority of our federal leases in Montana. The suspensions were issued based upon a court order issued on April 5, 2005 by the U.S. District Court of Montana that required the BLM to complete a Supplemental Environmental Impact Statement (SEIS) to address
100
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 15—Commitments and Contingencies (Continued)
phased development of coal bed natural gas. The U.S. Ninth Circuit Court of Appeals also issued an order on May 31, 2005 which enjoined the BLM from approving coal bed natural gas production projects in the Powder River Basin of Montana. Both of these actions placed limitations on lease development until completion of the SEIS.
The 2005 injunction was lifted by the Ninth Circuit Court of Appeals on October 29, 2007. The record of decision (ROD) for the SEIS was signed by the BLM on December 30, 2008 and went into effect on January 14, 2009. The Suspension of Operations and Production for the suspended leases was terminated effective February 1, 2009. The Company has received letters from the BLM with amended lease terms of the affected leases. Leases that were suspended have been placed back into an active lease status with the primary term increasing for approximately three to five years based on the time period the leases were in suspension.
On July 6, 2009, we filed suit (Cause No. DV09-35) against Big Sky Energy LLC and Quaneco L.L.C., in the Twenty-Second Judicial District Court, Big Horn County, Montana alleging claims for breach of contract, breach of implied covenant of good faith and fair dealing, tortious interference with business, tortious interference with contractual relations and slander of title. We are amending the complaint to add a foreclosure action against Big Sky Energy LLC's and Quaneco L.L.C.'s collective interest in the developed properties in Montana for non payment of invoices in the amount of $298,689.
We had previously filed suit (Cause DV-07-02) against Quaneco L.L.C. in the Twenty-Second Judicial District Court, Big Horn County, Montana for breach of contract and foreclosure of liens to collect $3,717,046 for joint interest bills that remained unpaid for over two years through September 19, 2007. A Settlement Agreement and Release of All Claims including payment of the $ 3,717,046 to us by Quaneco L.L.C. was reached on October 19, 2007.
We will continue to vigorously pursue payment of the amounts owed including interest and attorney's fees along with foreclosure proceedings and any other rights and remedies available to us pursuant to the Joint Operating Agreement dated June 23, 2003, as amended.
The Company was named as a defendant in litigation brought by RLI Insurance Company (Civil Cause No. 09-CV-157-J) filed in United States District Court for the District of Wyoming on July 6, 2009. The complaint alleges that the Company failed to provide $1,439,360 in additional collateral requested by plaintiff to secure certain bonds issued by plaintiff on behalf of the Company. Plaintiff seeks the additional bond collateral plus attorney's fees and costs. On March 18, 2010, Pinnacle Gas Resources, Inc. and RLI Insurance Company entered into a Tolling Agreement. The agreement stipulates that the parties agree to drop all claims and counter claims in the litigation captioned RLI Insurance Company v. Pinnacle Gas Resources, Inc., Case No. 09-CV-157-J (D. Wyo.), without prejudice. The agreement further stipulates that each party will extend the period within which either party may institute a claim, counterclaim, action or proceeding up to and including June 16, 2010. The agreement also obligates The Company to continue to solicit market quotes for the purpose of replacing all bonds or bonding relationships which exist between the Company and RLI Insurance Company.
We are aware of two purported class action lawsuits related to the Merger and Merger Agreement (please see Note 19) filed against some or all of the following: Thomas McGonagle, Peter Schoonmaker, Robert Cabes, Jeffery Gunst, Sylvester Johnson, F. Gardner Parker, Susan Schnabel, Pinnacle Gas Resources, Inc., DLJ Merchant Banking Partners III, L.P., Powder Holdings, LLC and
101
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 15—Commitments and Contingencies (Continued)
Powder Acquisition Co. The lawsuits and dates of filing are as follows: Pennsylvania Avenue Fund, et al. v. Thomas McGonagle, et al. , No. 5313-CC (filed March 5, 2010); and Harry Gordon, et al. v. Pinnacle Gas Resources, Inc., et al., No. 5325-CC (filed March 10, 2010). On March 24, 2010, the Delaware Court of Chancery entered an order consolidating the two actions under the caption in re Pinnacle Gas shareholder litigation C.A. No.—5313-CC (Del Ch.) and appointing co-lead counsel.
The Complaints are substantially similar and allege, among other things, that the Merger would be the product of a flawed process and that the consideration to be paid to our stockholders in the Merger would be unfair and inadequate. The Complaints further allege, among other things, that our officers and directors breached their fiduciary duties by, among other things, taking actions designed to deter higher offers from other potential acquirers and failing to maximize the value of Pinnacle to its stockholders. In addition, the lawsuits allege that DLJ, as a controlling stockholder of Pinnacle, violated fiduciary duties to Pinnacle stock holders. These lawsuits seek, among other relief, injunctive relief from joining the transaction and costs of the action, including reasonable attorney's fees. We believe that these lawsuits are without merit and intend to vigorously defend against them.
Regulations
The Company's oil and gas operations are subject to various federal, state and local laws and regulations. The Company could incur significant expense to comply with the new or existing laws and non-compliance could have a material adverse effect on the Company's operations.
Environmental
The Company produces significant amounts of water from its wells. If future wells produce water of a lesser quality than allowed under state laws or if water is produced at rates greater than the Company can dispose of, the Company could incur additional costs to dispose of the water.
Note 16—Major Customers
The following is a table summarizing the percentage of sales made to each purchaser that accounted for over 10% of the Company's gas sales for the years ended December 31, 2009, 2008 and 2007. The loss of any of these customers could have a material adverse effect on the Company's operations.
|
|
December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
Enserco |
45 | % | 46 | % | 58 | % | ||||
|
United Energy Trading |
55 | % | 54 | % | 36 | % | ||||
|
Cantera |
— | — | 5 | % | ||||||
|
Other |
— | — | 1 | % | ||||||
|
|
100 | % | 100 | % | 100 | % | ||||
Note 17—Fair Value of Financial Instruments
The carrying values of the Company's cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, and revenue distributions payable represent the fair value due to the short-term nature of the accounts. Total long-term debt at December 31, 2009 and 2008, with a carrying value of approximately $743,000 and $763,000, respectively, is estimated to approximate fair value as the terms are comparable to current market terms.
102
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 18—Quarterly Financial Data (Unaudited)
The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2009 and 2008 (in thousands, except per share data):
|
|
Three Months Ended | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
March 31,
2009 |
June 30,
2009 |
September 30,
2009 |
December 31,
2009 |
|||||||||
|
Year ended December 31, 2009: |
|||||||||||||
|
Revenues |
$ | 4,222 | $ | 3,659 | $ | 3,725 | $ | 3,364 | |||||
|
Cost of revenue and expenses |
(22,392 | ) | (10,504 | ) | (39,656 | ) | (5,643 | ) | |||||
|
Net loss |
(17,510 | ) | (9,459 | ) | (38,962 | ) | (2,821 | ) | |||||
|
Basic loss per share |
(0.60 | ) | (0.32 | ) | (1.31 | ) | (0.09 | ) | |||||
|
Diluted net loss per share |
(0.60 | ) | (0.32 | ) | (1.31 | ) | (0.09 | ) | |||||
|
|
Three Months Ended | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
March 31,
2008 |
June 30,
2008 |
September 30,
2008 |
December 31,
2008 |
|||||||||
|
Year ended December 31, 2008: |
|||||||||||||
|
Revenues |
$ | 5,567 | $ | 6,898 | $ | 6,409 | $ | 5,404 | |||||
|
Cost of revenue and expenses |
(6,888 | ) | (8,919 | ) | (7,601 | ) | (27,193 | ) | |||||
|
Net income (loss) |
(5,648 | ) | (3,874 | ) | 8,939 | (21,154 | ) | ||||||
|
Basic net income (loss) per share |
(0.19 | ) | (0.13 | ) | 0.31 | (0.72 | ) | ||||||
|
Diluted net income (loss) per share |
(0.19 | ) | (0.13 | ) | 0.30 | (0.72 | ) | ||||||
Note 19—Subsequent Events
Credit Agreement
On January 13, 2010, the Company entered into a Seventh Amendment and Waiver to Credit Agreement (" Waiver Agreement ") with the lenders party thereto. The Waiver Agreement provided that the lenders would waive (i) the Company's compliance with certain restrictions based on the current ratio in the Credit Agreement, (ii) certain requirements of the Company pertaining to the aging of certain accounts payable, and (iii) certain restrictions regarding the amount of liens of the Company. Default remedies available to the lenders under the Credit Agreement include acceleration of all principal and interest amounts due under the Credit Agreement. The Waiver Agreement extends the waiver period for these items until the earlier of June 15, 2010 and the date of any default arising out of a breach or non-compliance with the Credit Agreement not expressly waived in the Waiver Agreement or a breach of the Waiver Agreement.
In addition, the Waiver Agreement amends the definition of "Final Maturity Date" under the Credit Agreement to the earlier of (i) June 15, 2010 or (ii) the date that is thirty days following the earlier of (A) the date the merger is withdrawn or terminated in whole or in part or (B) the date that the lenders have been advised that the merger will not proceed.
Merger Agreement
On February 23, 2010, Pinnacle Gas Resources, Inc. (the "Company") entered into an Agreement and Plan of Merger (the "Merger Agreement") with Powder Holdings, LLC, a Delaware limited
103
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 19—Subsequent Events (Continued)
liability company ("Powder"), and Powder Acquisition Co., a Delaware corporation and a direct, wholly owned subsidiary of Powder ("Merger Sub"). Powder is controlled by an investor group led by Scotia Waterous (USA) Inc. and includes certain members of the Company's management team.
The Merger Agreement provides that, upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Company, with the Company continuing as the surviving corporation (the "Merger").
Subject to the terms and conditions of the Merger Agreement, at the effective time and as a result of the Merger, each outstanding share of common stock, par value $.01 per share, of the Company (other than shares as to which appraisal rights are properly exercised under Delaware law and shares owned by the Company, Powder, Merger Sub or their respective subsidiaries) will be converted into the right to receive a cash amount of $0.34 per share (the "Merger Consideration"). In addition, at the effective time of the Merger, (a) each outstanding and unexercised stock option and stock appreciation right will be cancelled and the holder of such option or stock appreciation right will receive a single lump sum cash payment equal to the product of: (i) the excess, if any, of the Merger Consideration over the exercise price or base price, as applicable, per share subject to such option or right, multiplied by (ii) the total number of shares of common stock subject to such option or right and (b) each outstanding restricted stock award, whether or not then vested, will be cancelled and the holder of such restricted stock award will receive a single lump sum cash payment equal to the product of (i) the Merger Consideration, multiplied by (ii) the total number of shares of common stock subject to such award.
The obligations of the parties to consummate the Merger are subject to the satisfaction or waiver of certain closing conditions, including (a) approval of the Merger by the holders of not less than a majority of the Company's common stock, excluding common stock held by DLJ Merchant Banking Partners III, L.P. and affiliated investment funds (collectively, "DLJ") or the Company's chief executive officer or chief financial officer, which condition cannot be waived by the parties (the "Stockholder Approval"), and (b) the absence of any injunction, restraint or prohibition on the completion of the Merger. Each party's obligation to close the Merger is also subject to the accuracy of certain representations and warranties of, and compliance with certain covenants by, the parties to the Merger Agreement, in each case as set forth in the Merger Agreement. In addition, Powder and Merger Sub's obligations to complete the Merger are subject to certain additional conditions, including: (i) the absence of any material adverse effect on the Company; (ii) the Company obtaining a waiver from the lenders under its credit agreement, for a period of 60 days following the effective time of the Merger, of the change of control event resulting from the Merger; and (iii) DLJ contributing all of its shares of common stock of the Company to Powder in exchange for ownership interests therein in accordance with the terms of a contribution agreement among Powder, DLJ and Scotia Waterous (USA), Inc., in each case, as set forth in the Merger Agreement. The Company, Powder and Merger Sub have made customary representations and warranties in the Merger Agreement.
The Merger Agreement contains certain termination rights for both the Company and Powder, including in the event the Merger is not consummated by August 23, 2010 or Stockholder Approval has not been obtained on or before such date. The Merger Agreement further provides that, upon termination of the Merger Agreement under specified circumstances, the Company may be required to pay Powder a termination fee of $1,000,000 (which is reduced to $500,000 under certain circumstances)
104
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 19—Subsequent Events (Continued)
and reimbursement of Powder's out-of-pocket fees and expenses of up to $600,000 in connection with the Merger Agreement
Litigation
On March 18, 2010, Pinnacle Gas Resources, Inc. and RLI Insurance Company entered into a Tolling Agreement. The agreement stipulates that the parties agree to drop all claims and counter claims in the litigation captioned RLI Insurance Company v. Pinnacle Gas Resources, Inc., Case No. 09-CV-157-J (D. Wyo.), without prejudice. The agreement further stipulates that each party will extend the period within which either party may institute a claim, counterclaim, action or proceeding up to and including June 16, 2010. The agreement also obligates the Company to continue to solicit market quotes for the purpose of replacing all bonds or bonding relationships which exist between the Company and RLI Insurance Company.
On March 5, 2010, the Company along with its Board of Directors was named as defendant in a class action suit brought by Pennsylvania Avenue Funds and Tony Jasinski, individually and on behalf of the public shareholders of Pinnacle Gas Resources, Inc. (Civil Case No. 5313-CC) filed in the Court of Chancery of the State of Delaware. The complaint alleges that the defendants breached their fiduciary duties and will cause irreparable harm to plaintiffs by entering into the Agreement and Plan of Merger dated February 23, 2010 between Pinnacle Gas Resources, Inc. and Powder Holdings, LLC. The complaint seeks to enjoin Pinnacle from consummating the proposed merger and seeks unspecified compensation for damages and/or legal fees.
On March 10, 2010, the Company along with its Board of Directors was named as defendant in a class action suit brought individually by Harry Gordon and Kevin Appleby and on behalf of the public shareholders of Pinnacle Gas Resources, Inc. (Civil Case No. 5325-CC) filed in the Court of Chancery of the State of Delaware. The complaint alleges that the defendants breached their fiduciary duties and will cause irreparable harm to plaintiffs by entering into the Agreement and Plan of Merger dated February 23, 2010 between Pinnacle Gas Resources, Inc. and Powder Holdings, LLC. The complaint seeks to enjoin Pinnacle from consummating the proposed merger and seeks unspecified compensation for damages and/or legal fees. On March 24, 2010, the Delaware Court of Chancery entered an order consolidating the two actions under the caption in re Pinnacle Gas shareholder litigation C.A. No.—5313-CC (Del Ch.) and appointing co-lead counsel.
NASDAQ Delisting
On March 16, 2010, The NASDAQ Stock Market notified the Company of its failure to comply with Listing Rule 5450(a)(1). This rule subjects a company's stock to delisting on the NASDAQ exchange if its stock price closes below $1 over the previous 30 consecutive business days and then, after notification, fails to regain compliance within the subsequent 180 days. Accordingly, unless the Company appeals this determination, the trading of the Company's stock will be suspended at the opening of business on March 25, 2010. The Company filed an appeal, pursuant to NASDAQ listing rule series 5800 on March 22, 2010. If the NASDAQ Compliance Panel approves the Company's plan to regain compliance, the Panel could grant the Company an additional 180 days to regain compliance with Listing Rule 5450(a)(1).
105
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 20—Supplemental Oil and Gas Information
Estimated Proved Oil and Gas Reserves (Unaudited)
Proved oil and gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and gas that are ultimately recovered.
All of the Company's proved reserves are located in the United States. The following information about the Company's proved and proved developed oil and gas reserves was developed from reserve reports prepared by independent reserve engineers:
|
|
Natural Gas
(Mcf) |
|||
|---|---|---|---|---|
|
Proved reserves as of December 31, 2006 |
20,288,526 | |||
|
Purchases of reserves in place |
— | |||
|
Extension, discoveries and other additions |
7,673,024 | |||
|
Revisions of previous estimates(1) |
1,147,906 | |||
|
Production |
(3,388,792 | ) | ||
|
Proved reserves as of December 31, 2007 |
25,720,664 | |||
|
Purchases of reserves in place |
95,300 | |||
|
Extension, discoveries and other additions |
9,161,500 | |||
|
Revisions of previous estimates(1) |
(3,388,139 | ) | ||
|
Production |
(3,869,925 | ) | ||
|
Proved reserves as of December 31, 2008 |
27,719,400 | |||
|
Purchases of reserves in place |
— | |||
|
Sale of reserves in place |
(205,467 | ) | ||
|
Extension, discoveries and other additions |
4,002,315 | |||
|
Revisions of previous estimates(1) |
(13,787,824 | ) | ||
|
Production |
(2,774,615 | ) | ||
|
Proved reserves as of December 31, 2009 |
14,953,809 | |||
|
Proved developed reserves as of December 31, 2007 |
10,457,663 | |||
|
Proved developed reserves as of December 31, 2008 |
15,412,429 | |||
|
Proved developed reserves as of December 31, 2009 |
11,280,919 | |||
106
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 20—Supplemental Oil and Gas Information (Continued)
increase from December 31, 2006 of $4.46, based on the Rocky Mountain CIG Index, to the December 31, 2007 price of $6.04.
Aggregate Capitalized Costs
Aggregate capitalized costs relating to the Company's oil and gas producing activities, and related accumulated depreciation, depletion, amortization and ceiling write-down are as follows:
|
|
December 31, | |||||||
|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | ||||||
|
|
(In thousands)
|
|||||||
|
Proved oil and gas properties |
$ | 143,524 | $ | 103,038 | ||||
|
Unproved oil and gas properties |
48,700 | 86,827 | ||||||
|
Total |
192,224 | 189,865 | ||||||
|
Less accumulated depreciation, depletion, amortization and impairment |
(134,047 | ) | (68,516 | ) | ||||
|
Net capitalized costs |
$ | 58,177 | $ | 121,349 | ||||
Costs Incurred in Oil and Gas Producing Activities
Costs incurred in connection with the Company's oil and gas acquisition, exploration and development activities are as follows:
|
|
December 31, | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | ||||||||
|
|
(In thousands)
|
||||||||||
|
Property acquisition costs |
|||||||||||
|
Proved |
$ | 1,213 | $ | 2,197 | $ | 1,357 | |||||
|
Unproved |
(2,691 | ) | 2,206 | 1,146 | |||||||
|
Total property acquisition costs |
(1,478 | ) | 4,403 | 2,503 | |||||||
|
Exploration costs |
1,861 | 1,186 | 2,579 | ||||||||
|
Development costs |
2,439 | 22,154 | 16,124 | ||||||||
|
Asset retirement costs |
(464 | ) | 399 | 239 | |||||||
|
Total costs |
$ | 2,358 | $ | 28,142 | $ | 21,445 | |||||
107
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 20—Supplemental Oil and Gas Information (Continued)
Oil and Gas Operations
Aggregate results of operations in connection with the Company's gas producing activities are shown below:
|
|
December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
|
(In thousands)
|
|||||||||
|
Revenues |
$ | 8,328 | $ | 22,441 | $ | 13,141 | ||||
|
Production costs and taxes |
8,342 | 13,085 | 9,582 | |||||||
|
Impairment of oil and gas properties |
60,927 | 21,521 | 18,225 | |||||||
|
Depletion |
4,603 | 8,061 | 5,518 | |||||||
|
Accretion of asset retirement obligations |
172 | 248 | 208 | |||||||
|
Results of operations from producing activities (excluding corporate overhead and interest costs) |
$ | (65,716 | ) | $ | (20,474 | ) | $ | (20,392 | ) | |
|
Depletion per MCF equivalent |
$ | 1.61 | $ | 2.08 | $ | 1.63 | ||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
Future gas sales and production and development costs have been estimated using prices and costs in effect at the end of the period indicated, except in those instances where the sale of natural gas is covered by contracts, as required by certain accounting provisions or in the instance of pricing for the year ended December 31, 2009, where the first day of the month, twelve month average price is required. These provisions require that net cash flow amounts be discounted at 10%. This information does not represent the fair market value of the Company's proved oil and gas reserves.
|
|
December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
|
(In thousands)
|
|||||||||
|
Future cash inflows |
$ | 29,975 | $ | 105,385 | $ | 123,380 | ||||
|
Future production costs |
(15,821 | ) | (41,764 | ) | (42,388 | ) | ||||
|
Future development costs |
(2,537 | ) | (16,352 | ) | (15,952 | ) | ||||
|
Future income tax expense |
— | (669 | ) | (5,236 | ) | |||||
|
Future cash flows |
11,617 | 46,600 | 59,804 | |||||||
|
10% annual discount for estimated timing on cash flows |
(4,020 | ) | (14,435 | ) | (21,245 | ) | ||||
|
Standardized measure of discounted future cash flows |
$ | 7,597 | $ | 32,105 | $ | 38,559 | ||||
The following table presents the average year-end market gas price used to compute future cash inflows for each period:
|
|
December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
Weighted average gas price per Mcf |
$ | 3.035 | $ | 4.605 | $ | 6.040 | ||||
108
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 20—Supplemental Oil and Gas Information (Continued)
Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the Company's proved oil and gas reserves at December 31, 2009, 2008 and 2007 assuming continuation of existing economic conditions.
The following reconciles the change in the standardized measure of discounted future net cash flow:
|
|
December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
2009 | 2008 | 2007 | |||||||
|
|
(In thousands)
|
|||||||||
|
Beginning of period |
$ | 32,105 | $ | 38,559 | $ | 22,384 | ||||
|
Net change from purchases of minerals in place |
— | 100 | — | |||||||
|
Net change in sales and transfer prices, net of production costs |
(43,332 | ) | (16,775 | ) | 8,391 | |||||
|
Revision of previous quantity estimates |
(2,911 | ) | (7,928 | ) | 13,166 | |||||
|
Extensions, discoveries and other additions |
4,732 | 9,997 | — | |||||||
|
Sales of oil and gas, net of production costs |
82 | (9,355 | ) | (3,559 | ) | |||||
|
Development cost incurred, previously estimated |
— | (400 | ) | (3,021 | ) | |||||
|
Net change in income taxes |
669 | 4,566 | (2,286 | ) | ||||||
|
Changes in future development costs |
12,975 | 8,961 | 951 | |||||||
|
Accretion of discount |
3,277 | 4,380 | 2,533 | |||||||
|
End of period |
$ | 7,597 | $ | 32,105 | $ | 38,559 | ||||
Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to the Company's proved oil and gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company's proved gas reserves.
109
ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15 under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the Company carried out an evaluation under the supervision and with the participation of the Company's management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company's disclosure controls and procedures as of December 31, 2009. In designing and evaluating the Company's disclosure controls and procedures, the Company and its management recognize that there are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their desired control objectives. Additionally, in evaluating and implementing possible controls and procedures, the Company's management was required to apply its reasonable judgment. Based upon the required evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that as of December 31, 2009, the Company's disclosure controls and procedures were effective at the reasonable assurance level to ensure that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, and to ensure that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to its management, including the Company's Chief Executive Officer and Chief Financial Officer as appropriate, to allow timely decisions regarding required disclosure, within the time periods specified in the Securities and Exchange Commission's rules and forms.
Internal Control over Financial Reporting
The Company's principal executive officer and principal financial officer are responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers and effected by the Company's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the
110
risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In accordance with Item 308 of Regulation S-K, management is required to provide an annual report regarding internal controls over our financial reporting. This report, which includes management's assessment of the effectiveness of our internal controls over financial reporting, follows below.
The Company's management assessed the effectiveness of its internal control over financial reporting as of December 31, 2009. In making this assessment, the Company's management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.
Based on the Company's assessment, management believes that, as of December 31, 2009, the Company's internal control over financial reporting is effective based on those criteria.
This annual report does not include an attestation report of the Company's registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the Company's registered public accounting firm pursuant to temporary rules of the SEC that permit a Company to provide only management's report in this annual report.
There were no changes in the Company's internal controls over financial reporting or in other factors during the fourth quarter of 2009 that have materially affected or are reasonably likely to materially affect its internal controls over financial reporting. The certifications of the general partner's CEO and CFO, required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002, have been included as exhibits to this report on Form 10-K.
None.
111
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Set forth below are the names of the persons continuing to be directors on the Board of Directors of the Company.
INCUMBENT DIRECTORS—CLASS I
Terms Expiring in 2010
|
Name
|
Age | Position |
Director
Since |
||||||
|---|---|---|---|---|---|---|---|---|---|
|
Jeffrey P. Gunst |
33 |
Director |
2003 | ||||||
|
Thomas G. McGonagle |
50 |
Director |
2007 | ||||||
|
Peter G. Schoonmaker |
51 |
Chief Executive Officer, President and Director |
2006 | ||||||
INCUMBENT DIRECTORS—CLASS II
Terms Expiring in 2011
|
Name
|
Age | Position |
Director
Since |
||||||
|---|---|---|---|---|---|---|---|---|---|
|
Robert L. Cabes, Jr. |
40 |
Director |
2003 | ||||||
|
Sylvester P. Johnson, IV |
54 |
Director |
2003 | ||||||
INCUMBENT DIRECTORS—CLASS III
Terms Expiring in 2012
|
Name
|
Age | Position |
Director
Since |
||||||
|---|---|---|---|---|---|---|---|---|---|
|
F. Gardner Parker |
68 |
Director |
2003 | ||||||
|
Susan C. Schnabel |
48 |
Director |
2005 | ||||||
The members of the Company's Board of Director's have not collectively or individually been involved in any legal proceedings that are material to an evaluation of their ability or integrity. The principal occupations and employment of the continuing directors are set forth below:
Jeffrey P. Gunst. Mr. Gunst has served as a director since our inception in June 2003. Mr. Gunst serves as a Principal at Avista Capital Holdings, L.P., a private equity firm focused on investments in the energy, media and healthcare sectors, where he has worked since its inception in July 2005. Mr. Gunst previously worked with Global Energy Partners, or GEP, a specialty group within Credit Suisse's asset management business that made investments in energy companies, beginning in 2001. Mr. Gunst currently serves as a director of Celtique Energie Limited, Peregrine Oil and Gas II, Spartan Offshore Holdings, Hansa Hydrocarbons, Royal Offshore, and ACP II Marcellus. From 1999 until joining GEP, Mr. Gunst was an investment banker for Credit Suisse and Donaldson, Lufkin and Jenrette where he worked primarily on energy transactions. Mr. Gunst received a B.B.A. and B.S. from Southern Methodist University. Mr. Gunst was selected to serve on the Company's Board of Directors based on his experience with the energy industry and investment markets.
Thomas G. McGonagle. Mr. McGonagle became a director in August 2007 and was elected Chairman of our Board of Directors in March 2009. From April 2007 to December 2008, Mr. McGonagle was Senior Vice President—Corporate Development at MacDermid, Incorporated, a specialty chemical company (formerly listed on NYSE: MRD). From 2003 until joining MacDermid,
112
Mr. McGonagle was Senior Vice President and Chief Financial Officer at Vistar Corporation, a national food distribution company. From 2001 to 2003, Mr. McGonagle was Managing Director and Co-Head of the US Merchant Banking Group at Babcock & Brown LP in New York. From 1987 until joining Babcock & Brown, Mr. McGonagle was Managing Director of the Financial Sponsors Group of Donaldson, Lufkin & Jenrette / Credit Suisse. In this role, Mr. McGonagle was involved in numerous principal investment transactions, debt and equity securities offerings, and mergers and acquisitions across many different industries. Mr. McGonagle is also a director of Consolidated Container Company LLC, located in Atlanta, Georgia. Mr. McGonagle received a B.A. in Economics from Dartmouth College and a M.B.A. from the Amos Tuck School of Business Administration at Dartmouth College. Mr. McGonagle was selected to serve on the Board based on his extensive management experience and experience with investment transactions, securities offerings, and mergers and acquisitions.
F. Gardner Parker. Mr. Parker has served as a director since our inception in June 2003. Mr. Parker has served as a Trust Manager with Camden Property Trust, a real estate investment trust, since 1998 and as a director since 1993. Mr. Parker also serves on the Board of Directors of Carrizo, Sharps Compliance Corp. and Hercules Offshore, Inc. Mr. Parker serves on the Board of Directors of the following private companies: Gillman Automobile Dealerships, Net Near U Communications, Camp Longhorn, Inc. and Sherwood Healthcare Inc. In addition, Mr. Parker serves as Chairman of Norton Ditto Inc. Mr. Parker also worked with Ernst & Ernst (now Ernst &Young LLP) for 14 years, for seven of which he served as a partner. Mr. Parker received a B.B.A. from The University of Texas. Mr. Parker is also Chairman of the Board of Triangle Petroleum and is Board certified by the National Association of Corporate Directors. Mr. Parker was selected to serve on the Board based on his strong background in accounting and energy companies, as well as his extensive service as a board member.
Susan C. Schnabel. Ms. Schnabel has served as a director since July 2005. Ms. Schnabel has served as a Managing Director with and partner in DLJ Merchant Banking Partners, the leveraged corporate private equity platform of Credit Suisse's asset management business, since 1998. She joined Donaldson, Lufkin and Jenrette's Investment Banking Division in 1990. In 1997, she left Donaldson, Lufkin and Jenrette's Investment Banking Division to serve as Chief Financial Officer of PETsMART, a high growth specialty retailer of pet products and supplies, and joined DLJ Merchant Banking in her present capacity in 1998. Ms. Schnabel is also a director of DeCrane Aircraft Holdings, Inc., Target Media Partners, Specialized Technology Resources, Total Safety, U.S., Luxury Optical Holdings, Inc., Frontier Drilling, Laramie Energy II, LLC and Enduring Resources, LLC. Ms. Schnabel received a B.S. from Cornell University and an M.B.A. from Harvard Business School. Ms. Schnabel was selected to serve on the Board based on her background in complex financial transactions and financial management as well as her significant board service to other companies.
Peter G. Schoonmaker. Mr. Schoonmaker has served as Pinnacle's Chief Executive Officer since Pinnacle's inception in June 2003, and as President and a director since February 2006. Mr. Schoonmaker has over 20 years of experience in the acquisition, exploration and development of coalbed methane properties as well as conventional oil and gas properties. From 1980 to 1985 Mr. Schoonmaker was an independent landman for various oil and gas companies and operated a land management company in Denver, Colorado. From 1985 to 1995 he served as President, owner and operator of a land and agricultural company based in Colorado and Wyoming. In 1995, Mr. Schoonmaker joined U.S. Energy, a publicly held mining and energy company, as a land manager and also became Executive Vice President and a director of Yellowstone Fuels Corporation, a subsidiary of U.S. Energy. In November 1999, U.S. Energy formed Rocky Mountain Gas, a coal bed natural gas company. He served as President, Chief Operating Officer and was a director of Rocky Mountain Gas from its inception until June 23, 2003. Mr. Schoonmaker was selected to serve on the Board based on his extensive background in oil and gas transactions in the Rocky Mountain Region and his management skills.
113
Robert L. Cabes, Jr. Mr. Cabes has served as a director since Pinnacle's inception in June 2003. Mr. Cabes has been Partner of Avista Capital Holdings, L.P., a private equity firm focused on investments in the energy, healthcare and media sectors since 2005. From April 2001 to June 2005, Mr. Cabes served as a Principal of Global Energy Partners, or GEP, a specialty group within Credit Suisse's asset management business that made investments in energy companies. Mr. Cabes is based in Houston, Texas and currently serves as a director of ACP II Marcellus, Hansa Hydrocarbons, Royal Offshore, Celtique Energie, Geokinetics, Laramie Energy, Manti Exploration and Spartan Offshore Drilling. He previously served as a Director of Copano Energy, Medicine Bow Energy and MedServe. Prior to joining GEP, Mr. Cabes was with Credit Suisse's and Donaldson, Lufkin and Jenrette's Investment Banking Division (prior to its acquisition by Credit Suisse in 2000) where he worked on debt and equity securities underwriting and mergers and acquisitions for energy companies. Before joining Donaldson, Lufkin and Jenrette, Mr. Cabes spent six years with Prudential Securities in its energy corporate finance group in Houston and New York. Mr. Cabes holds a B.B.A. from Southern Methodist University and is a CFA charterholder. Mr. Cabes was selected to serve on the Board based on his experience in the energy industry and financial markets.
Sylvester P. Johnson, IV. Mr. Johnson has served as a director since Pinnacle's inception in June 2003. Mr. Johnson has served as President, Chief Executive Officer and a director of Carrizo since December 1993. Prior to December 1993, he worked for Shell Oil Company for 15 years. His managerial positions included Operations Superintendent, Manager of Planning and Finance and Manager of Development Engineering. Mr. Johnson serves as a director of Basic Energy Services, Inc. Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado. Mr. Johnson was selected to serve on the Board based on his experience in the energy industry as well as his engineering background as a Registered Petroleum Engineer with a degree in Mechanical Engineering.
2009 Director Compensation
|
Name
|
Fees
Earned or Paid in Cash ($) |
Stock
Awards ($)(1) |
All Other
Compensation ($) |
Total
($) |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Steven A. Webster(2) |
$ | — | $ | 5,000 | $ | — | $ | 5,000 | |||||
|
Robert L. Cabes, Jr. |
— |
38,500 |
— |
38,500 |
|||||||||
|
Jeffrey P. Gunst |
— |
27,500 |
— |
27,500 |
|||||||||
|
Sylvester P. Johnson, IV(3) |
— |
36,500 |
— |
36,500 |
|||||||||
|
F. Gardner Parker |
— |
53,500 |
— |
53,500 |
|||||||||
|
Susan C. Schnabel(4) |
— |
40,000 |
— |
40,000 |
|||||||||
|
Thomas G. McGonagle |
— |
85,500 |
— |
85,500 |
|||||||||
|
Peter G. Schoonmaker(5) |
— |
— |
— |
— |
|||||||||
114
All non-employee directors received an annual fee of $20,000 in 2009. In addition, the Board chairman and chairman of each of the following committees received the following annual fees: Board Chairman—$50,000, Audit Committee—$15,000, Compensation Committee—$5,000, and Nominating and Corporate Governance Committee—$5,000. Non-employee directors received a fee of $1,500 for each board or committee meeting attended in person and a fee of $1,000 for attendance at a board or committee meeting held telephonically. Each non-employee director was granted restricted stock in lieu of cash compensation. The number of shares granted to each director is determined by dividing the aggregate amount of cash compensation owed to such director on a quarterly basis by an amount equal to the greater of the (i) closing price of the company's common stock on the first day of the last month of the quarter, plus 5% of such price, rounded up to the nearest cent, or (ii) the average of the closing stock price of the company's common stock during the five consecutive business days preceding the first day of the last month of the quarter, plus 5% of such price, rounded up to the nearest cent. The Board of Directors expects that cash compensation to non-employee directors will remain the same in 2010, and has not yet authorized 2010 equity grants to directors.
Employee directors do not receive compensation for service on our board or committees. Pursuant to company policy, all directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of the board or committees and for other reasonable expenses incurred in connection with service on the board and any committees.
Each director will be fully indemnified by us for actions associated with being a member of our board to the extent permitted under Delaware law as provided in our second amended and restated certificate of incorporation, our amended and restated bylaws and the indemnification agreements by and between us and each of our directors.
On October 13, 2009 a special committee of independent directors was formed for the purpose of evaluating certain merger related activities. The special committee is authorized and empowered to negotiate the Scotia merger proposal and any competing proposals received. The special committee is also authorized to retain independent legal and financial advisors and has been provided sufficient funds, by the company, for such expenses. The special committee is authorized and empowered to accept or reject any proposals or the terms of any proposed transactions. The chairman of the special committee will receive a $50,000 fee upon completion of a transaction. Each non-employee director received a fee of $1,500 for each committee meeting attended in person and $1,000 for attendance telephonically.
MANAGEMENT
Executive Officers
Our executive officers are appointed by our Board of Directors and serve at their discretion. None of our executive officers and directors are related. Set forth below is information regarding our current executive officers:
|
Name
|
Age | Position | |||
|---|---|---|---|---|---|
| Peter G. Schoonmaker | 51 | Chief Executive Officer and President | |||
| Ronald T. Barnes | 50 | Chief Financial Officer, Senior Vice President and Secretary | |||
115
Peter G. Schoonmaker. Mr. Schoonmaker has served as Pinnacle's Chief Executive Officer since Pinnacle's inception in June 2003, and as President and a director since February 2006. Mr. Schoonmaker has over 20 years of experience in the acquisition, exploration and development of coalbed methane properties as well as conventional oil and gas properties. From 1980 to 1985 Mr. Schoonmaker was an independent landman for various oil and gas companies and operated a land management company in Denver, Colorado. From 1985 to 1995 he served as President, owner and operator of a land and agricultural company based in Colorado and Wyoming. In 1995, Mr. Schoonmaker joined U.S. Energy, a publicly held mining and energy company, as a land manager and also became Executive Vice President and a director of Yellowstone Fuels Corporation, a subsidiary of U.S. Energy. In November 1999, U.S. Energy formed Rocky Mountain Gas, a coalbed natural gas company. He served as President, Chief Operating Officer and was a director of Rocky Mountain Gas from its inception until June 23, 2003.
Ronald T. Barnes. Mr. Barnes has served as our Chief Financial Officer and Senior Vice President since December 2005 and our Secretary since February 2006 and since joining Pinnacle in January 2004, has also served as our Vice President—Finance and our Controller. Mr. Barnes has 28 years of experience in public accounting and industry related to all aspects of the upstream sector of oil and gas acquisition, exploration, development and production. Prior to joining Pinnacle, Mr. Barnes worked for EnCana Oil and Gas (USA), Inc. from 2002 through January, 2004 as lead controller and was responsible for all accounting aspects of U.S. operations. From 1988 through 2002, Mr. Barnes held various positions with JN Exploration and Production LP, including most recently serving as Controller and Vice President of Marketing of JN Exploration and Production where he managed the accounting and marketing for the acquisition, drilling and production of properties in 17 states and the Outer Continental Shelf of the Gulf of Mexico. From 1983 through 1988, Mr. Barnes held various positions with Raymond T. Duncan Oil Properties and from 1981 through 1983, he worked for a major public accounting firm. Mr. Barnes is a member of the Council of Petroleum Accountants Societies, the Independent Petroleum Association of Mountain States, the Petroleum Association of Wyoming and the Montana Petroleum Association. Mr. Barnes earned a B.S. in accounting from the University of Wyoming and an M.B.A. from the University of Colorado.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the SEC. Such persons are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2009.
Code of Ethics
The Board of Directors adopted our Code of Ethics that applies to all officers, directors and employees. The Code of Ethics is available on our website at www.pinnaclegas.com . Amendments to, and waivers from, the Code of Ethics will be disclosed at the same website address provided above and in such filings as may be required pursuant to applicable law or listing standards; however, any technical, administrative or other non-substantive amendments to the Code of Ethics may not be posted. Please be aware that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet addresses or at our website in general is intended or deemed to be incorporated by reference. We intend to satisfy the disclosure requirement under Item 5.05(c) of Form 8-K regarding certain amendments to, or waivers from a provision of this code of ethics by posting such information on our website at www.pinnaclegas.com under "Corporate Governance."
116
CORPORATE GOVERNANCE
Board of Directors
Our Board of Directors currently consists of seven directors: three Class I directors with terms expiring in 2010, two Class II directors with terms expiring in 2011, and two Class III directors with terms expiring in 2012. There is no family relationship between any director and any other director or executive officer.
Board of Directors and Committee Meetings and Attendance
The Board of Directors has four standing committees: an Audit Committee, a Compensation Committee, a Nominating and Corporate Governance Committee and a Hedging Committee. Each of the Audit Committee, the Compensation Committee and the Nominating and Corporate Governance Committee operates under a written charter adopted by the Board of Directors. Copies of these charters are available on our website at www.pinnaclegas.com. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.
The Board of Directors held six meetings during the year ended December 31, 2009. Each director attended at least 75% of the aggregate of the meetings of the Board of Directors and of the committees, on which he or she served, held during the period for which he or she was a director or committee member, respectively. The following table sets forth the standing committees of the Board of Directors, the number of meetings held by each committee and the membership of each committee during the year ended December 31, 2009. Peter G. Schoonmaker and Thomas G. McGonagle attended the 2009 Annual Meeting of the Stockholders.
|
Name
|
Audit | Compensation |
Nominating
and Corporate Governance |
Special
Committee |
||||
|---|---|---|---|---|---|---|---|---|
| Steven A. Webster(1) | ||||||||
|
Robert L. Cabes, Jr. |
|
|
|
Chair |
|
|
|
X |
|
Jeffery P. Gunst |
|
|
|
|
|
|
|
X |
|
Sylvester P. Johnson, IV |
|
X |
|
X |
|
X |
|
|
|
Thomas G. McGonagle(2) |
|
X |
|
|
|
X |
|
Chair |
|
F. Gardner Parker |
|
Chair |
|
X |
|
|
|
|
|
Susan C. Schnabel |
|
|
|
X |
|
Chair |
|
|
|
Peter G. Schoonmaker |
|
|
|
|
|
|
|
|
|
Number of Meetings held in 2009 |
|
4 |
|
4 |
|
1 |
|
3 |
117
Audit Committee
Membership
Our Audit Committee currently consists of F. Gardner Parker (Chairman), Sylvester P. Johnson, IV and Thomas G. McGonagle. The Board of Directors annually reviews the definition of independence for Audit Committee members and has determined that all current members of our Audit Committee are independent (as independence is currently defined by NASDAQ listing requirements and SEC rules). In addition, the Board of Directors has determined that Mr. Parker is an audit committee financial expert (as defined by SEC rules). The principal duties of the Audit Committee include the following:
Report of the Audit Committee
The Audit Committee assists the Board of Directors in its oversight of the Company's financial reporting process. The Audit Committee's responsibilities are more fully described in its charter, which is accessible through the Company's website at www.pinnaclegas.com .
Management has the primary responsibility for the preparation and integrity of the Company's financial statements, accounting and financial reporting principles and internal controls and procedures designed to assure compliance with accounting standards and applicable laws and regulations. The Company's independent auditor, Ehrhardt Keefe Steiner & Hottman PC, is responsible for performing an independent audit of the financial statements and expressing an opinion thereon.
In fulfilling its oversight responsibilities, the Audit Committee has reviewed and discussed the audited financial statements for the year ended December 31, 2009 with the Company's management, and has discussed with Ehrhardt Keefe Steiner & Hottman PC the matters that are required to be discussed by the Statement on Auditing Standards No. 61, as amended, Communication with Audit Committees . In addition, Ehrhardt Keefe Steiner & Hottman PC has provided the Audit Committee with the written disclosures and the letter required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent auditor's communications with the Audit Committee concerning independence, and the Audit Committee has discussed with Ehrhardt Keefe Steiner & Hottman PC its independence.
Based on these reviews and discussions, the Audit Committee recommended to the Board of Directors that the audited financial statements be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2009 for filing with the Securities and Exchange Commission.
| THE AUDIT COMMITTEE | ||
|
|
|
F. Gardner Parker, Chairman Sylvester P. Johnson, IV Thomas G. McGonagle |
118
Compensation Committee
Membership
Our Compensation Committee currently consists of Robert L. Cabes, Jr. (Chairman), Sylvester P. Johnson, IV, F. Gardner Parker and Susan C. Schnabel, each of whom is an independent director (as independence is currently defined by NASDAQ listing requirements). This Form 10-K includes the report of our Compensation Committee and the Compensation Discussion & Analysis, which focuses on executive compensation. The principal duties of the Compensation Committee include the following:
Nominating and Corporate Governance Committee
Membership
Our Nominating and Corporate Governance Committee currently consists of Susan C. Schnabel (Chairperson), Sylvester P. Johnson, IV, and Thomas G. McGonagle, each of whom is an independent director (as independence is currently defined by NASDAQ listing requirements). The principal duties of the Nominating and Corporate Governance Committee include the following:
Director Nomination Procedures
All director nominees will be evaluated and recommended for nomination by the Nominating and Corporate Governance Committee. The Nominating and Corporate Governance Committee is responsible for reviewing with the Board of Directors the selection criteria for director nominees and the appropriate skills and characteristics required of Board members in the context of the then current composition of the Board of Directors. The Nominating and Corporate Governance Committee will also consider director candidates recommended by stockholders. In considering candidates submitted by stockholders, the Nominating and Corporate Governance Committee will take into consideration the needs of the Board of Directors and the qualifications of the candidate. The Nominating and Corporate Governance Committee may also take into consideration the number of shares held by the recommending stockholder and the length of time that such shares have been held. To have a candidate
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considered by the Nominating and Corporate Governance Committee, a stockholder must submit the recommendation in writing and must include the following information:
The stockholder recommendation and information described above must be sent to the Corporate Secretary at 1 E. Alger, Sheridan, Wyoming 82801, Attention: Secretary, not less than 120 days in advance of the first anniversary of the date of the Company's proxy statement for the previous year's annual meeting of stockholders or, if the date of the annual meeting of stockholders has changed by more than 30 calendar days from the date contemplated at the time of the previous year's proxy statement, the notice must be received by the Company not later than the close of business on the later of (i) the 90 th day prior to such annual meeting or (ii) the 10 th day following the date on which public announcement of the date of such meeting is first made.
The Nominating and Corporate Governance Committee believes that the minimum qualifications for serving as a director are that a nominee demonstrate he or she (1) has business and/or professional knowledge and experience that will benefit the Company, its business and the goals and perspectives of its stockholders, (2) is well regarded in the community, with a long-term reputation for honesty and integrity, (3) has good common sense and judgment, (4) has a positive record of accomplishment in present and prior positions, (5) will set high expectations for management, and (6) has the time, energy, interest and willingness to become involved in the Company and its future.
Corporate Governance Guidelines and Practices
We are committed to good corporate governance practices and as such we have adopted formal Corporate Governance Guidelines. A copy of the Corporate Governance Guidelines may be found at our website at www.pinnaclegas.com . Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.
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ITEM 11.
EXECUTIVE COMPENSATION
The following discussion and analysis of compensation arrangements of the named executive officers of the Company should be read together with the compensation tables and related disclosures set forth below.
Compensation Committee Report
The Compensation Committee of our Board of Directors has reviewed and discussed with management the following Compensation Discussion and Analysis section. Based on its review and discussions with management, the Compensation Committee recommended to our Board of Directors that the Compensation Discussion and Analysis be included in this form 10-K relating to the 2009 Annual Meeting of Stockholders.
| The Compensation Committee: | ||
|
|
|
Robert L. Cabes, Jr., Chairman Sylvester P. Johnson, IV F. Gardner Parker Susan C. Schnabel |
Compensation Discussion and Analysis
Introduction
Our named executive officers for the fiscal year ended December 31, 2009 were (1) Peter G. Schoonmaker, our Chief Executive Officer and President, and (2) Ronald T. Barnes, our Chief Financial Officer, Senior Vice President and Secretary. We did not have any other executive officers during this period.
We first discuss our compensation policies and objectives as it relates to our named executive officers, including the elements of our compensation program and certain policies regarding stock ownership, tax deduction limits, recoupment of compensation and employment agreements. We then discuss the manner in which we determine the compensation of our named executive officers and our decisions regarding their compensation for 2009.
Compensation Policies and Objectives
Overall Policies and Objectives. Our overall policy with respect to executive compensation has been to provide levels and types of compensation that attract and retain highly qualified executive officers and align their interests with those of our stockholders. We believe this policy is best accomplished by linking portions of their compensation with specific business and strategic objectives and our overall business and financial performance. Accordingly, our policy is to pay our executive officers a competitive compensation package that includes a significant incentive compensation component in addition to base salary. In addition, it is our policy to pay incentive compensation in both cash and equity consideration that is tied to both our short- and long-term performance. During 2009, short- and long-term incentive compensation could have potentially accounted for approximately 55.2% and 47.6% of Messrs. Schoonmaker's and Barnes' total compensation, respectively, although no payments were actually made under our short-term incentive compensation plan (the Management Incentive Plan), as described below. Long-term incentive compensation (in the form of grants of restricted stock that vest in one-third increments on the first, second and third anniversaries of the date of grant) accounted for approximately 12.1% and 11.9% of Messrs. Schoonmaker's and Barnes' total compensation during 2009, respectively (based on the grant date fair value of their restricted stock awards).
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Elements of Compensation. We seek to achieve the compensation objectives for our named executive officers through compensation packages that consist of four principal elements:
These elements, taken together, promote the objectives described above and constitute a flexible and balanced approach to determining the total compensation of our named executive officers. For example, the performance-based cash bonus for 2009 was tied to our achievement of certain objective and subjective goals over a period of one year, while the ultimate value of the restricted stock will largely depend upon our overall performance over a multi-year period.
We consider long-term equity incentive compensation to be an important element of our compensation program for our executive officers. We believe that meaningful equity participation by each executive officer motivates and rewards the creation and preservation of long-term stockholder value. This belief is reflected in the aggregate awards of stock options and restricted stock that have been made to our executive officers since our formation.
Stock Ownership Policy. We do not currently have any policies, requirements or guidelines relating to the level of ownership of our common stock by our directors or executive officers or to the hedging of the economic risk of such ownership. As of December 31, 2009, Messrs. Schoonmaker and Barnes owned 38,400 and 21,000 shares of our common stock, respectively, held options to purchase another 232,500 and 202,500 shares of our common stock, respectively, held stock appreciation rights of 35,000 and 29,000, respectively, and held 100,000 and 74,000 shares of restricted common stock, respectively, subject to vesting requirements. On a fully diluted basis, Messrs. Schoonmaker and Barnes held approximately 1.3% and 1.0%, respectively, of our issued and outstanding common stock as of December 31, 2009.
Policy with Respect to $1 Million Deduction Limit. Section 162(m) of the Internal Revenue Code generally disallows a tax deduction to public corporations for compensation over $1 million paid for any fiscal year to the corporation's chief executive officer and up to three other executive officers whose compensation must be included in this Form 10-K because they are the most highly compensated executive officers. However, the statute exempts qualifying performance-based compensation from the deduction limit if certain requirements are met. Since our initial public offering in 2007, the Compensation Committee has considered this deduction limit, but salaries and other compensation awards to our named executive officers have not exceeded this limit.
Policy Regarding Recoupment of Compensation. If we are required to restate our financial statements due to material non-compliance with financial reporting requirements under securities laws as a result of misconduct by an executive officer, applicable law permits us to recover incentive compensation from that executive officer (including profits realized from the sale of our common stock). In this event, our Board of Directors would exercise its business judgment to determine what action it believes is appropriate. Action may include recovery or cancellation of any bonus or incentive payments made to an executive on the basis of performance targets having been achieved if the Board determines that such recovery or cancellation is appropriate due to intentional misconduct by the executive officer that resulted in performance targets being achieved (or appearing to be achieved) that would not have been achieved (or appeared to have been achieved) absent such misconduct.
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Employment Agreements. We enter into employment agreements with senior executive officers, including our named executive officers, when the Compensation Committee determines that an employment agreement is desirable in order to obtain a measure of assurance regarding the executive's continued employment, or when the Compensation Committee determines that such an agreement may be necessary and appropriate to attract an executive in light of market conditions, the executive's experience and the company's practices with respect to other similarly situated officers.
Determination of Executive Compensation
Responsibilities of the Compensation Committee. The Compensation Committee determines compensation with respect to our named executive officers. The Compensation Committee's responsibilities include:
Role of the Executive Officers in Determining Executive Compensation. Our Compensation Committee determines the compensation for our named executive officers, although the full Board of Directors has input into their subjective performance evaluations. Mr. Schoonmaker has no role in determining his own compensation. As our Chief Executive Officer and President and a director, Mr. Schoonmaker evaluates the performance of Mr. Barnes, and the Compensation Committee considers Mr. Schoonmaker's evaluation when determining Mr. Barnes' compensation. Mr. Barnes has no role in determining his own compensation or that of Mr. Schoonmaker.
Use of Outside Consultants. During 2009, the Compensation Committee retained an outside compensation consultant, A G Ferguson & Associates, Inc., to assist the Compensation Committee in making compensation decisions. Among other things, the compensation consultant reviewed the base salaries, bonuses and equity awards of executives at several similarly-sized publicly traded companies in the oil and gas industry. These companies were NGAS Resources, Inc., TXCO Resources Inc., GeoMet, Inc., Warren Resources, Inc., Double Eagle Petroleum Co., Cano Petroleum, Inc., Infinity Energy Resources, Inc., Kodiak Oil & Gas Corp., Crimson Exploration, Gasco Energy Inc. and American Oil & Gas Inc. The Compensation Committee did not set the 2009 compensation of our named executive officers within a specified percentile range of the compensation paid by the comparable companies, and there were no specified guidelines for the use of the data provided by the compensation consultant. Rather, the Compensation Committee used the information regarding the compensation paid by comparable public companies in a general manner to help define competitive levels of base salary, bonus and equity compensation compared to companies with similar profiles. Although the Compensation Committee considered the comparative data carefully, it did not consider such data to be determinative because it believes that a subjective evaluation of the performance of our named executive officers should be paramount.
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2009 Executive Compensation
Base Salary. Generally, base salaries are determined according to the following factors: the individual's experience level, the scope and complexity of the position held, and the annual performance of the individual. Messrs. Schoonmaker's and Barnes' initial base salaries for 2009 were set at $250,000 and $200,000, respectively. Messrs. Schoonmaker's and Barnes' initial base salaries for 2008 were unchanged from their base salaries during 2007 due to the pendent merger with Quest Resource Corporation, which did not ultimately occur. In November, 2008, in light of the challenging economic and operating environment faced by the company, Messrs. Schoonmaker and Barnes voluntarily reduced their base salaries to $200,000 and $170,000, respectively.
For 2009, the base salaries of Messrs. Schoonmaker and Barnes remained unchanged from their reduced levels in November 2008 at $200,000 and $170,000, respectively.
Performance-Based Bonus. During 2009, we approved a Management Incentive Plan, or MIP. The MIP was intended to provide annual incentive compensation for our key executives that was tied to the achievement of critical strategic, operating and financial goals and objectives. Each of Messrs. Schoonmaker and Barnes was assigned performance measures that would affect the amounts paid under the MIP. Each performance measure included a range of levels of achievement. The objective performance measures for the MIP are set forth in the table below.
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Performance Metric
|
Threshold | Target | Maximum | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Annual gross general and administrative costs($) |
5.0 | 4.2 | 3.4 | |||||||
|
Annual transportation and compression costs($) |
4.6 |
3.8 |
3.0 |
|||||||
|
Lease operating expenses ($/well/month) |
1,440 |
1,200 |
960 |
|||||||
For each of Messrs. Schoonmaker and Barnes, the objective factors listed in the table above were given a relative weight of 10% in the overall annual bonus calculation. Other than with respect to these objective factors, no quantitative performance targets were established for either Mr. Schoonmaker or Barnes.
Under the MIP, Mr. Schoonmaker's annual bonus was also tied to the following subjective performance measures: investor relations (relative weight—10%) and board communication (relative weight—10%). In addition, a portion of Mr. Schoonmaker's annual bonus was tied to Mr. Barnes' overall success in achieving his goals and objectives for 2009 (relative weight—20%). Finally, a portion of Mr. Schoonmaker's annual bonus was based on a subjective evaluation by the Compensation Committee, with input from the Board of Directors, of the degree to which he had successfully fulfilled the primary duties and responsibilities of his position (relative weight—30%). The "target" bonus for Mr. Schoonmaker under the MIP was 0.5 times his annual base salary of $250,000, or $125,000. If Mr. Schoonmaker had achieved the minimum level of performance for every performance measure, he would have received no bonus for 2009. If Mr. Schoonmaker had achieved the highest level of performance for every performance measure, he would have received an annual bonus equal to 1.0 times his 2009 annual base salary, or $250,000, the maximum amount to which he is potentially entitled under his employment agreement.
Under the MIP, Mr. Barnes' annual bonus was also tied to the following subjective performance measures: investor relations (relative weight—10%), capital financing (relative weight—10%), timely reporting (relative weight—10%) and cash management (relative weight—10%). In addition, a portion of Mr. Barnes' annual bonus was based on a subjective evaluation by the Compensation Committee, with input from the Board of Directors, of the degree to which he had successfully fulfilled the primary duties and responsibilities of his position (relative weight—30%). The "target" bonus for Mr. Barnes under the MIP was 0.375 times his annual base salary of $200,000, or $75,000. If Mr. Barnes had achieved the minimum level of performance for every performance measure, he would have received
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no bonus for 2009. If Mr. Barnes had achieved the highest level of performance for every performance measure, he would have received an annual bonus equal to 0.75 times his 2009 annual base salary, or $150,000, the maximum amount to which he is potentially entitled under his employment agreement.
As described above, the performance measures under the MIP included both objective and subjective measures and represented the factors deemed most important by the Compensation Committee and the most likely to result in the creation of long-term stockholder value. We believe that the use of objective performance measures provides an element of transparency and accountability with respect to the annual bonuses paid to our executive officers, while the use of subjective performance measures allows us to be proactive in rewarding the initiative and contributions of each individual officer.
With respect to the objective performance measures, the threshold, target and maximum performance levels were determined in connection with a detailed review by the Compensation Committee of our 2009 budget and represented aggressive targets for operational and financial performance by us during 2009. When performing the subjective evaluations of the individual performances of Messrs. Schoonmaker and Barnes, the Compensation Committee considered, among other things, their success in implementing an efficient and effective management reporting regime, their ability to interact with investors and regulatory agencies in a positive and productive manner, including through making accurate and timely regulatory filings, their contributions to our culture of teamwork, open communication, integrity and safety, and their ability to quickly adjust to a very challenging operating environment. Due to difficult economic conditions during 2009 in our operating region and the broader U.S. economy, the drastic reduction in natural gas prices during the same period and our reduced 2009 capital expenditure budget, the Compensation Committee along with the executive officers, suspended any payment under the MIP.
The Compensation Committee has not yet adopted a management incentive plan for 2010.
Equity Incentive Awards. We have a Stock Incentive Plan pursuant to which equity awards, including stock options and restricted stock, may be granted to employees, directors and consultants. The Stock Incentive Plan is designed to motivate all of our employees, including our named executive officers, to assist us in achieving a high level of long-term performance and to tie the compensation of grant recipients to long-term stockholder value. The Compensation Committee administers the Stock Incentive Plan.
Historically, we have used stock options and restricted stock to attract new employees and to increase the stake of our existing employees, including our executive officers, in our long-term success. As such, we periodically evaluate the equity position of our executive officers and determine if increasing that position would be appropriate. Due to the favorable tax consequences to the grant recipient, our stock option grants have historically been intended to qualify as "incentive stock options" under Section 422 of the Internal Revenue Code. We have awarded all stock options to purchase our common stock at or above the fair market value of our common stock on the grant date. Options are granted only at regularly scheduled meetings of the Compensation Committee and/or the Board of Directors, and have exercise prices equal to the closing market price of shares of our common stock on the date of the meeting. There were no options granted during 2009.
We have adopted a stock incentive plan authorizing the grant of Stock Appreciation Rights ("SARs"). A SAR confers on the participant a right to receive, upon exercise, the excess of the fair market value of a share of Common Stock on the date of the exercise over $1.00. Such excess shall be paid in cash or common stock or a combination thereof to the participant. Messrs. Schoonmaker and Barnes were granted 35,000 and 29,000 SARs, respectively, in 2009. These SARs vest 33.33%, 33.33%, and 33.34% on the first, second, and third anniversary of the grant date.
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In 2009, Messrs. Schoonmaker and Barnes were granted 35,000 and 29,000 restricted shares of our common stock, respectively, under our Stock Incentive Plan. These grants were made in order to continue to incentivize our executive officers over the long term, and they will vest in one-third increments on the first, second and third anniversary of the date of grant. In addition, the review of equity compensation awarded to executive officers at several similarly-sized publicly traded companies in the oil and gas industry prepared by the compensation consultant indicated that many of these companies continued to provide their executives with significant equity compensation. Although the Compensation Committee did not establish a formal percentile range or other benchmark, the Compensation Committee felt that in light of our objective to provide our executives with a competitive compensation package, an additional grant of equity compensation to each of Messrs. Schoonmaker and Barnes was appropriate. The Compensation Committee believed that grants of restricted stock during 2009 would provide better incentives for our executive officers to both enhance and protect stockholder value. In addition, the issuance of restricted stock requires fewer shares, and thus less dilution, compared to delivering similar value in options to the award recipient. The significant continuing compensation expense associated with our out-of-the-money options has also contributed to the Compensation Committee's decision to favor restricted stock over options at this time.
Perquisites and Other Benefits. Messrs. Schoonmaker and Barnes receive no perquisites or benefits that are not generally available on a non-discriminatory basis to all employees. During 2009, for all employees, including Messrs. Schoonmaker and Barnes, we paid a portion of health, life and accidental death & disability insurance premiums, made health savings account contributions and matched their contributions to our 401(k) plan (up to 4% of their base salary).
Payments in Connection with a Change of Control or Termination
We entered into employment agreements with Messrs. Schoonmaker and Barnes on July 20, 2007, effective January 1, 2007. The initial term of these agreements was one year, with automatic renewals for additional one-year terms unless either party gives 60 days prior written notice. Under Mr. Schoonmaker's employment agreement, he is entitled to an initial base salary of $250,000, subject to annual adjustment, and an annual bonus of up to 1.0 times his then current base salary, payable in cash or in stock. Under Mr. Barnes' employment agreement, he is entitled to an initial base salary of $200,000, subject to annual adjustment, and an annual bonus of up to 0.75 times his then current base salary, payable in cash or in stock.
If either executive's employment is terminated by us without cause or by either executive for good reason, the executive will be entitled to severance benefits which will include a lump sum payment equal to the sum of (i) 1.0 times his annual base salary plus (ii) 18.0 times the monthly health savings account contribution last made by us for his benefit, and the payment of a pro-rated bonus. Additionally, if either executive's employment is terminated by us without cause or by either executive for good reason or due to retirement, in each case within one year following a change of control of us, the executive will be entitled to severance benefits which will include a lump sum payment equal to 1.5 times his annual base salary and the payment of a pro-rated bonus. In each case, any and all stock options, restricted stock awards and other equity compensation awards held by the executive will immediately vest and become exercisable. In the event that either executive's employment is terminated within six months preceding or following a change of control due to a non-renewal of his employment agreement by us, the executive will be entitled to the same change of control severance benefits described above.
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EXECUTIVE COMPENSATION
2009 Summary Compensation Table
The following table's sets forth the aggregate compensation earned by or awarded or paid to our named executive officers for each of the last three completed fiscal years.
|
Name and Principal Position
|
Year | Salary(1) |
Stock
Awards(2) |
Option
Awards(2) |
Non-Equity
Incentive Plan Compensation |
All Other
Compensation(6) |
Total | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Peter G. Schoonmaker |
2009 | $ | 200,000 | $ | 14,350 | $ | 13,300 | $ | — | (3) | $ | — | $ | 227,650 | ||||||||
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Chief Executive Officer, President |
2008 | 244,672 | 84,700 | — | — | (4) | — | 329,372 | ||||||||||||||
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and Director |
2007 | 250,000 | 209,400 | — | 125,000 | (5) | — | 584,400 | ||||||||||||||
|
Ronald T. Barnes |
2009 |
$ |
170,000 |
$ |
11,890 |
$ |
11,020 |
$ |
— |
(3) |
$ |
— |
$ |
192,910 |
||||||||
|
Chief Financial Officer, Senior |
2008 | 196,803 | 60,500 | — | — | (4) | — | 257,303 | ||||||||||||||
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Vice President and Secretary |
2007 | 200,000 | 139,600 | — | 75,000 | (5) | — | 414,600 | ||||||||||||||
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Grants of Plan-Based Awards During 2009
The following table sets forth the plan-based grants made to our named executive officers during 2009.
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|
Estimated Future Payouts Under Non-Equity Incentive
Plan Awards(1) |
All Other
Stock Awards: Number of Shares of Stock (#)(2) |
|
||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
Grant Date
Fair Value of Stock Awards ($) |
||||||||||||||||||
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Name
|
Grant Date | Threshold ($) | Target ($) |
Maximum
($) |
|||||||||||||||
|
Peter G. Schoonmaker |
$ | — | $ | 125,000 | $ | 250,000 | |||||||||||||
|
|
June 1, 2009 | (3) | 35,000 | $ | 13,300 | ||||||||||||||
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|
June 1, 2009 | (4) | 35,000 | $ | 14,350 | ||||||||||||||
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Ronald T. Barnes |
$ | — | $ | 75,000 | $ | 150,000 | |||||||||||||
|
|
June 1, 2009 | (3) | 29,000 | $ | 11,020 | ||||||||||||||
|
|
June 1, 2009 | (4) | 29,000 | $ | 11,890 | ||||||||||||||
Employment Agreements
We entered into employment agreements with Messrs. Schoonmaker and Barnes on July 20, 2007, effective January 1, 2007. The initial term of these agreements was one year, with automatic renewals for additional one-year terms unless either party gives 60 days prior written notice. Under Mr. Schoonmaker's employment agreement, he is entitled to an initial base salary of $250,000, subject to annual adjustment, and an annual bonus of up to 1.0 times his then current base salary, payable in cash or in stock. Under Mr. Barnes' employment agreement, he is entitled to an initial base salary of $200,000, subject to annual adjustment, and an annual bonus of up to 0.75 times his then current base salary, payable in cash or in stock. The termination of these agreements under certain circumstances will trigger termination payments or benefits payable by us. Please see "—Potential Payments upon Termination or Change of Control," below
Incentive Plan Awards
For a discussion of the performance metrics under our 2009 Management Incentive Plan, please see "Compensation Discussion and Analysis—2009 Executive Compensation—Performance-Based Bonus," above. Notwithstanding the contributions made by Messrs. Schoonmaker and Barnes during 2009, as part of our overall efforts to reduce costs in light of the decreased natural gas prices during 2009, and in the operating challenges inherent in the development of higher-cost properties such as the coal bed methane properties owned by us, the Compensation Committee determined to pay no cash bonus to Messrs. Schoonmaker and Barnes for 2009. The Compensation Committee has not yet adopted a management incentive plan for 2010.
The restricted stock granted to Messrs. Schoonmaker and Barnes was granted pursuant to our Stock Incentive Plan. For a discussion of our Stock Incentive Plan, please see "Compensation Discussion and Analysis—2009 Executive Compensation—Equity Incentive Awards," above.
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Outstanding Equity Awards at 2009 Fiscal Year-End
The following table sets forth all outstanding equity awards held by our named executive officers as of December 31, 2009.
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|
Option Awards | Stock Awards | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
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Name
|
Number of
Securities Underlying Unexercised Options Exercisable (#) |
Number of
Securities Underlying Unexercised Options Unexercisable (#) |
Option
Exercise Price ($) |
Option
Expiration Date |
Number of
Shares of Stock That Have Not Vested (#) |
Market
Value of Shares of Stock That Have Not Vested ($)(5) |
|||||||||||||
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Peter G. Schoonmaker |
82,500 | — | $ | 4.00 | June 30, 2010 | 30,000 | (2) | $ | 9,900 | ||||||||||
|
|
30,000 | — | $ | 4.00 | March 5, 2011 | 23,331 | (3) | 7,699 | |||||||||||
|
|
50,000 | — | $ | 4.80 | December 9, 2012 | 35,000 | (4) | 11,550 | |||||||||||
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|
50,000 | — | $ | 5.20 | January 1, 2013 | ||||||||||||||
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|
20,000 | — | $ | 11.00 | June 1, 2013 | ||||||||||||||
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|
— | 35,000 | (1) | $ | 1.00 | June 1, 2016 | |||||||||||||
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Ronald T. Barnes |
25,000 |
— |
$ |
4.00 |
January 3, 2011 |
20,000 |
(2) |
$ |
6,600 |
||||||||||
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50,000 | — | $ | 4.80 | June 23, 2011 | 16,665 | (3) | 5,499 | |||||||||||
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37,500 | — | $ | 4.80 | January 3, 2012 | 29,000 | (4) | 9,570 | |||||||||||
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12,500 | — | $ | 4.80 | December 9, 2012 | ||||||||||||||
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50,000 | — | $ | 5.20 | January 1, 2013 | ||||||||||||||
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12,500 | — | $ | 5.20 | February 16, 2013 | ||||||||||||||
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15,000 | — | $ | 11.00 | June 1, 2013 | ||||||||||||||
|
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— | 29,000 | (1) | $ | 1.00 | June 1, 2016 | |||||||||||||
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Potential Payments upon Termination or Change-in-Control
The following table sets forth the potential termination payments due to our named executive officers, assuming the triggering event occurred on December 31, 2009.
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Name
|
Benefit |
Termination
without Cause or for Good Reason |
Termination
Following a Change of Control |
Termination
Due to Death |
Termination
for Cause or without Good Reason |
||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Peter G. Schoonmaker |
Severance | $ | 250,000 | $ | 375,000 | $ | 125,000 | $ | — | ||||||
|
|
Prorated bonus(1) | — | — | — | — | ||||||||||
|
|
Insurance premiums(2) | 11,124 | 11,124 | 11,124 | — | ||||||||||
|
|
Health savings account contributions(2) | 4,950 | — | — | — | ||||||||||
|
|
Acceleration of stock options and restricted stock(3) | 29,149 | 29,149 | 29,149 | — | ||||||||||
|
|
Unused vacation(4) | — | — | — | — | ||||||||||
|
Ronald T. Barnes |
Severance |
200,000 |
300,000 |
100,000 |
— |
||||||||||
|
|
Prorated bonus(1) | — | — | — | — | ||||||||||
|
|
Insurance premiums(2) | 11,124 | 11,124 | 11,124 | — | ||||||||||
|
|
Health savings account contributions(2) | 4,950 | — | — | — | ||||||||||
|
|
Acceleration of stock options and restricted stock(3) | 21,669 | 21,669 | 21,669 | — | ||||||||||
|
|
Unused vacation(4) | — | — | — | — | ||||||||||
Messrs. Schoonmaker and Barnes each entered into employment agreements with us on July 20, 2007, effective January 1, 2007. Pursuant to each employment agreement, upon termination of the executive's employment under any circumstances, he would be entitled to payment for accrued but unpaid salary, unused vacation days and unreimbursed business expenses. Upon termination of the executive's employment by us for any reason (including by reason of his disability) other than due to his death or due to an event or circumstance constituting cause, or by the executive with good reason, the executive would be entitled to receive the following additional payments and benefits: (i) a lump-sum payment equal to the sum of 1.0 times his then-current base salary plus 18.0 times the monthly health savings account contribution last made by us for his benefit; (ii) a prorated bonus; (iii) continued group health coverage (including payment of premiums) for him and his spouse and dependents for up to 18 months; (iv) accelerated vesting of any and all stock options, shares of restricted stock and other equity awards held by him; and (v) the potential extension of the period of time during which the stock options held by him may be exercised. If the executive's employment were to be terminated by us for any reason (including by reason of his disability) other than due to his death or due to an event or circumstance constituting cause, or by the executive with good reason or due to his retirement, in each case within one year following a change of control, or if the employment agreement were not to be renewed for any reason other than for cause within six months preceding or following a change of control, the executive would be entitled to receive the same additional payments and benefits as those described in the preceding sentence, except that his lump-sum payment would be equal to 1.5 times his then-current base salary and would not include health savings account contributions.
For purposes of the employment agreements, "cause" means (i) the executive's conviction of, plea of nolo contendere to or receipt of deferred adjudication with respect to a felony crime, (ii) a violation by the executive of federal or state securities laws, (iii) the executive's commission, in the good faith judgment of our Board of Directors, of an act of sexual or other unlawful harassment or moral turpitude, (iv) a breach by the executive of his fiduciary duties, (v) a breach by the executive of certain
130
provisions of his employment agreement, (vi) the commission by the executive of a material act of fraud upon us, (vii) the material misappropriation by the executive of our funds or other property, (viii) the executive's knowing engagement, without the written approval of our Board of Directors or Compensation Committee, in any material activity that directly competes with our business or that our Board of Directors or Compensation Committee determines in good faith would directly result in a material injury to our business or reputation or (ix) a material breach by the executive of the other provisions of his employment agreement or the willful, material and repeated nonperformance of the executive's duties, in each case after notice and an opportunity to cure.
For purposes of the employment agreements, "good reason" means (i) a substantial change in the executive's duties that constitutes a material breach by us of the terms of the agreement, the assignment to the executive of duties or responsibilities that are inconsistent with his previous duties and responsibilities or a material diminution or reduction in the executive's duties and responsibilities (excluding in each case an inadvertent action which is promptly cured and, in the case of Mr. Schoonmaker, a change in his title or responsibilities, provided that he continues to manage our assets and operations), (ii) a material breach by us of the agreement, (iii) a purported termination otherwise than as expressly permitted pursuant to the agreement or (iv) any failure by us to obtain the assumption of the agreement by a successor.
For purposes of the employment agreements, "change of control" means (i) the acquisition by any individual, entity or group of beneficial ownership of 50% or more of either the then outstanding shares of our common stock or the combined voting power of our then outstanding voting securities (subject to certain exceptions), (ii) the approval by our stockholders of a merger, consolidation or similar business combination unless immediately following such transaction substantially all of the holders of our voting securities immediately prior to such transaction beneficially own more than 50% of the common stock of the corporation resulting from such transaction in substantially the same proportions or (iii) the sale or other disposition of all or substantially all of our assets, unless immediately following such transaction substantially all of the holders of our voting securities immediately prior to such disposition beneficially own more than 50% of the common stock of the corporation acquiring such assets in substantially the same proportions.
In addition, pursuant to the employment agreements, upon the executive's death, his spouse would be entitled to receive the following payments and benefits: (i) a lump-sum payment equal to 0.5 times his then-current base salary; (ii) a prorated bonus; (iii) continued group health coverage (including payment of premiums) for her and her dependents for up to 18 months; (iv) accelerated vesting of any and all stock options, shares of restricted stock and other equity awards held by the executive prior to his death; and (v) the potential extension of the period of time during which the stock options may be exercised.
If the executive's employment is terminated by us for cause, or if the executive voluntarily resigns or otherwise terminates his employment without good reason (other than in connection with his retirement following a change of control), he would be entitled only to payment for accrued but unpaid salary, unused vacation days and unreimbursed business expenses.
Under their employment agreements, Messrs. Schoonmaker and Barnes are subject to covenants prohibiting them from (i) disclosing confidential information, (ii) making defamatory statements about us, (iii) soliciting or attempting to solicit business in products or services competitive with ours for a period of two years following the termination of their employment, (iv) competing with us for a period of one year following the termination of their employment or (v) recruiting our employees for a period of two years following the termination of their employment.
131
Compensation Committee Interlocks and Insider Participation
Messrs. Cabes (Chairman), Johnson and Parker and Ms. Schnabel serve as the members of our Compensation Committee. The Board of Directors has determined that Messrs. Cabes, Johnson and Parker and Ms. Schnabel are independent directors (as defined by NASDAQ listing standards). None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our Board of Directors or Compensation Committee.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth information as of March 26, 2010 concerning the shares of our capital stock beneficially owned by:
Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all shares of capital stock shown as beneficially owned by them, and their address is c/o Pinnacle Gas Resources, Inc., 1 E. Alger, Sheridan, Wyoming 82801.
|
Name and Address of Beneficial Owner
|
Number of
Shares of Common Stock Beneficially Owned(9) |
Percent
of Class |
|||||
|---|---|---|---|---|---|---|---|
|
DLJ Merchant Banking Partners III, L.P. and affiliated funds(1) |
9,751,262 | 32.3 | % | ||||
|
CCBM, Inc.(2) |
2,555,825 | 8.4 | |||||
|
Highview Capital Management, LLC(3) |
1,875,503 | 6.2 | |||||
|
Peter G. Schoonmaker(4) |
405,900 | 1.3 | |||||
|
Ronald T. Barnes(5) |
326,500 | 1.1 | |||||
|
Robert L. Cabes, Jr. |
157,442 | * | |||||
|
Thomas G. McGonagle(6) |
284,281 | * | |||||
|
Jeffrey P. Gunst |
109,629 | * | |||||
|
Sylvester P. Johnson, IV(7) |
— | * | |||||
|
F. Gardner Parker |
195,337 | * | |||||
|
Susan C. Schnabel(8) |
— | * | |||||
|
All directors and executive officers as a group (8 persons) |
1,479,089 | 4.9 | % | ||||
132
shares
include 151,760 shares of restricted common stock granted to Susan C. Schnabel in her capacity as a director of the Company, which shares have been transferred to DLJ Merchant Banking
III, Inc.
Credit Suisse, a Swiss bank (the "Bank"), owns a majority of the voting stock of Credit Suisse Holdings (USA) Inc., a Delaware corporation, which in turn owns all of the voting stock of Credit
Suisse
(USA) Inc., a Delaware corporation ("CS-USA"). The entities discussed in the previous paragraph are merchant banking funds managed by indirect subsidiaries of CS-USA and
form part of Credit Suisse's asset management business. The ultimate parent company of the Bank is Credit Suisse Group ("CSG"). CSG disclaims beneficial ownership of the reported common stock that is
beneficially owned by its direct and indirect subsidiaries.
All of the DLJ Merchant Banking entities can be contacted at Eleven Madison Avenue, New York, NY 10010-3629, except for the three "Offshore Partners" entities, which can be contacted at
John B. Gosiraweg, 14 Willemstad, Curacao, Netherlands Antilles.
133
in the table has sole voting power and investment power (or shares such power with his or her spouse) with respect to all shares of capital stock listed as owned by such person or entity.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth information regarding shares of our common stock authorized for issuance under our equity compensation plans as of December 31, 2009:
|
Plan Category
|
Number of
Securities to be Issued Upon Exercise of Outstanding |
Weighted Average
Exercise Price of Outstanding |
Number of
Securities Remaining Future Issuance |
|||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
Equity compensation plans approved by stockholders |
2,146,272 | $ | 2.79 | 603,728 | ||||||
|
Equity compensation plans not approved by stockholders |
N/A | — | — | |||||||
|
Total |
2,146,272 | $ | 2.79 | 603,728 | ||||||
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
CORPORATE GOVERNANCE
Board of Directors
Our Board of Directors currently consists of seven directors: three Class I directors with terms expiring in 2010, two Class II directors with terms expiring in 2011, and two Class III directors with terms expiring in 2011. There is no family relationship between any director and any other director or executive officer.
Director Independence
Our Board of Directors has determined that all of the directors, other than Peter G. Schoonmaker, are independent directors under the NASDAQ listing standards. Our Board of Directors considered all relevant facts and circumstances in determining that none of these directors, other than Mr. Schoonmaker, has any relationship with us or our management that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. Among other things, our Board of Directors considered the independence tests listed below. Pursuant to these independence tests, a director may not be deemed to be independent if any of the following relationships exists:
134
solely from investments in our securities or payments under non-discretionary charitable contribution matching programs;
Our Board of Directors has determined that each of the current members of our Audit, Compensation and Nominating and Corporate Governance Committees is independent under the independence standards applicable to such committees. In accordance with NASDAQ listing standards, each of our Audit, Compensation and Nominating and Corporate Governance Committees were composed entirely of independent directors within one year of our listing on NASDAQ.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Messrs. Cabes and Gunst have in the past provided consulting services to certain DLJ Merchant Banking portfolio companies through arrangements with MB Advisory Partners, LLC, an affiliate of Avista Capital Holdings, L.P., a private equity firm that makes investments in the energy sector. Ms. Schnabel is a Managing Director of DLJ Merchant Banking. As described elsewhere in this Form 10-K, funds affiliated with DLJ Merchant Banking own approximately 32.3% of our common stock. In addition, Mr. Johnson serves as President and Chief Executive Officer and a director of Carrizo, which indirectly owns approximately 8.4% of our common stock. Mr. Parker is also a director of Carrizo. These relationships were considered by our Board of Directors in making its independence determinations, and the Board of Directors determined that none of these relationships would prevent the aforementioned directors from exercising independent judgment in carrying out their responsibilities.
Review, Approval or Ratification of Transactions with Related Persons
Our Board of Directors is responsible for approving all related party transactions between us and any officer or director that would potentially require disclosure. As of the date of this Form 10-K, the Board of Directors expects that any transactions in which related persons have a direct or indirect interest will be presented to the Board of Directors for review and approval. The Board of Directors has not adopted a written policy regarding related party transactions, but it makes inquiries to management and our auditors regarding any such transactions. We are not aware of any transaction that was required to be reported with the SEC where such policies and procedures either did not require review or were not followed.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The Audit Committee of our Board of Directors has selected Ehrhardt Keefe Steiner & Hottman PC as our independent auditor to audit our financial statements for the fiscal year ending December 31, 2009. Ehrhardt Keefe Steiner & Hottman PC has audited our financial statements since our inception in June 2003.
135
Fees paid
The following table presents the fees billed to us by Ehrhardt Keefe Steiner & Hottman PC for professional services rendered to us during 2009 and 2008, by category:
|
|
2009 | 2008 | |||||
|---|---|---|---|---|---|---|---|
|
|
(In thousands)
|
||||||
|
Audit fees |
$ | 209 | $ | 208 | |||
|
Audit-related fees(1) |
5 | 111 | |||||
|
Tax fees(2) |
29 | 33 | |||||
|
All other fees(3) |
— | 70 | |||||
|
Total |
$ | 243 | $ | 422 | |||
Audit Committee Pre-Approval Policies
In order to assure the continued independence of our independent auditor, our Audit Committee has adopted a policy requiring it's pre-approval of all audit and non-audit services performed for us by the independent auditor. Under this policy, the Audit Committee annually pre-approves certain limited, specified recurring services which may be provided by Ehrhardt Keefe Steiner & Hottman PC, subject to maximum dollar limitations. All other engagements for services to be performed by Ehrhardt Keefe Steiner & Hottman PC must be specifically pre-approved by the Audit Committee, or a designated committee member to whom this authority has been delegated.
The Audit Committee, or a designated member thereof, pre-approved all engagements by us of Ehrhardt Keefe Steiner & Hottman PC during 2009 and 2008, including the terms and fees thereof, and the Audit Committee concluded that all such engagements were compatible with the continued independence of Ehrhardt Keefe Steiner & Hottman PC in serving as our independent auditor.
136
PART IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1)
Financial Statements
Included in Item 8 of this annual report:
Report of Independent Registered Public Accounting Firm
Balance Sheets as of December 31, 2009 and 2008
Statements of Operations for the years ended December 31, 2009, 2008 and 2007
Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007
Statements of Stockholders' Equity for the years ended December 31, 2009, 2008 and 2007
Notes to Financial Statements
(a)(2) Financial Statement Schedules
None.
(a)(3) Exhibits
The following documents are filed as exhibits to this annual report:
|
Exhibit
Number |
|
Description | ||
|---|---|---|---|---|
|
2.1 |
— |
Amended and Restated Agreement and Plan of Merger, dated as of February 6, 2008, among Quest Resources Corporation, Pinnacle Gas Resources, Inc. and Quest MergerSub, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 000-17371) filed by Quest Resource Corporation on February 6, 2008). | ||
|
3.1 |
— |
Second Amended and Restated Certificate of Incorporation of Pinnacle Gas Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on May 10, 2006). | ||
|
3.2 |
— |
Amended and Restated Bylaws of Pinnacle Gas Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on May 10, 2006) | ||
|
4.1 |
— |
Amended and Restated Securityholders Agreement, dated February 16, 2006 (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on May 10, 2006). | ||
|
4.2 |
— |
Registration Rights Agreement, dated April 11, 2006 (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on May 10, 2006). | ||
|
10.1 |
— |
Termination of AMI Agreement, dated April 11, 2006, by and among Pinnacle Gas Resources, Inc., CCBM, Inc., Carrizo Oil & Gas, Inc., U.S. Energy Corp., Crested Corp. and the CSFB Parties (as defined therein) (incorporated by reference to Exhibit 10.1 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). |
137
|
Exhibit
Number |
|
Description | ||
|---|---|---|---|---|
|
10.2 |
— |
Credit Agreement, dated February 12, 2007, by and among Pinnacle Gas Resources, Inc., as Borrower, the Lenders from time to time party thereto and Royal Bank of Scotland plc, individually and as Administrative Agent (incorporated by reference to Exhibit 10.2 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139556) filed by Pinnacle Gas Resources, Inc. on April 3, 2007). | ||
|
10.3 |
— |
Letter regarding waiver and amendment of Credit Agreement, dated March 9, 2007 (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139556) filed by Pinnacle Gas Resources, Inc. on April 3, 2007). | ||
|
10.4 |
— |
Purchase and Sale Agreement, dated February 7, 2006, between Kennedy Oil and Pinnacle Gas Resources, Inc. (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). | ||
|
10.5 |
— |
Gas Gathering Agreement (Low Pressure Field Gathering) by and among Bitter Creek Pipelines, LLC and Pinnacle Gas Resources, Inc., Quaneco L.L.C. and Dolphin Energy Corporation (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). | ||
|
10.6 |
— |
Gas Gathering Agreement (High Pressure Gathering Line) by and among Bitter Creek Pipelines, LLC and Pinnacle Gas Resources, Inc., Quaneco L.L.C. and Dolphin Energy Corporation (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). | ||
|
10.7 |
— |
Midstream Transportation Agreement, effective December 1, 2003, by and between Pinnacle Gas Resources, Inc. and Clear Creek Natural Gas, LLC (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). | ||
|
†10.8 |
— |
Amended and Restated Stock Incentive Plan, effective February 16, 2006 (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). | ||
|
†10.9 |
— |
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). | ||
|
†10.10 |
— |
Form of Restricted Stock Grant Agreement (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). | ||
|
†10.11 |
— |
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.13 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on September 15, 2006). | ||
|
10.12 |
— |
Purchase/Placement Agreement, dated March 31, 2006, between Pinnacle Gas Resources, Inc. and Friedman, Billings, & Ramsey & Co., Inc. (incorporated by reference to Exhibit 10.18 to the Registration Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on May 10, 2006). |
138
|
Exhibit
Number |
|
Description | ||
|---|---|---|---|---|
|
†10.14 |
— |
Employment Agreement, dated July 20, 2007, by and between Pinnacle Gas Resources, Inc. and Peter G. Schoonmaker (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on July 24, 2007). | ||
|
†10.15 |
— |
Employment Agreement, dated July 20, 2007, by and between Pinnacle Gas Resources, Inc. and Ronald T. Barnes (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on July 24, 2007). | ||
|
†10.16 |
— |
Pinnacle Gas Resources, Inc. Management Incentive Plan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on July 24, 2007). | ||
|
10.17 |
— |
Letter Agreement by and between Pinnacle Gas Resources, Inc. and the Royal Bank of Scotland, executed as of April 10, 2008, regarding the credit facility dated as of February 12, 2007 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on May 15, 2008). | ||
|
10.18 |
— |
Second Amendment to Credit Agreement, dated August 4, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on August 6, 2008). | ||
|
10.19 |
— |
Third Amendment to Credit Agreement, effective December 31, 2008 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on November 14, 2008). | ||
|
†10.20 |
— |
Second Amended and Restated Stock Incentive Plan, effective November 11, 2008 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on November 14, 2008). | ||
|
10.21 |
Fourth Amendment to Credit Agreement, dated as of April 14, 2009 (incorporated herein by reference to Exhibit 10.21 to the Annual Report on Form 10-K (File No. 001-33457) filed by Pinnacle Gas Resources, Inc. on April 15, 2009). | |||
|
10.22 |
— |
Waiver to Credit Agreement, dated as of August 19, 2009 (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed by Pinnacle Gas Resources on August 19, 2009). | ||
|
10.23 |
— |
Fifth Amendment to the Credit Agreement, dated August 26, 2009 (incorporated herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on August 27, 2009). | ||
|
10.24 |
— |
Sixth Amendment to the Credit Agreement, dated October 20, 2009 (incorporated herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on October 22, 2009). | ||
|
10.25 |
— |
Waiver and Amendment, dated October 26, 2009 (incorporated herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on October 29, 2009). | ||
|
10.26 |
— |
Waiver and Amendment, dated November 16, 2009 (incorporated herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on November 19, 2009). | ||
|
10.27 |
— |
Waiver and Amendment, dated November 23, 2009 (incorporated herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on November 23, 2009). | ||
|
10.28 |
— |
Waiver and Agreement dated as of January 5, 2010 (incorporated herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on January 8, 2010). |
139
|
Exhibit
Number |
|
Description | ||
|---|---|---|---|---|
|
10.29 |
— |
Seventh Amendment and Waiver to the Credit Agreement dated as of January 13, 2010 (incorporated herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on January 19, 2010). | ||
|
*23.1 |
— |
Consent of Netherland and Sewell Associates, Inc. | ||
|
*31.1 |
— |
Certification of President and Chief Executive Officer of Pinnacle Gas Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
*31.2 |
— |
Certification of Senior Vice President, Chief Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
*32.1 |
— |
Certification of President and Chief Executive Officer of Pinnacle Gas Resources, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
|
*32.2 |
— |
Certification of Senior Vice President, Chief Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
|
*99.1 |
— |
Estimate of Reserves and Future Revenue to the Pinnacle Gas Resources, Inc. interest in certain Coalbed Methane Properties located in Montana and Wyoming as of December 31, 2009. |
140
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| PINNACLE GAS RESOURCES, INC. | |||
|
|
By: |
|
/s/ PETER G. SCHOONMAKER Name: Peter G. Schoonmaker Title: President and Chief Executive Officer |
Date: March 31, 2010
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
||
|---|---|---|---|---|
|
|
|
|
|
|
|
/s/ PETER G. SCHOONMAKER
Peter G. Schoonmaker |
President and Chief Executive Officer
(Principal Executive Officer) and Director |
March 31, 2010 | ||
|
/s/ RONALD T. BARNES Ronald T. Barnes |
|
Senior Vice President, Chief Financial Officer and Secretary (Principal Financial Officer and Principal Accounting Officer) |
|
March 31, 2010 |
|
/s/ THOMAS G. MCGONAGLE Thomas G. McGonagle |
|
Chairman of the Board of Directors |
|
March 31, 2010 |
|
/s/ ROBERT L. CABES, JR. Robert L. Cabes, Jr. |
|
Director |
|
March 31, 2010 |
|
/s/ JEFFREY P. GUNST Jeffrey P. Gunst |
|
Director |
|
March 31, 2010 |
|
/s/ S. P. JOHNSON, IV S. P. Johnson, IV |
|
Director |
|
March 31, 2010 |
|
/s/ F. GARDNER PARKER F. Gardner Parker |
|
Director |
|
March 31, 2010 |
|
/s/ SUSAN C. SCHNABEL Susan C. Schnabel |
|
Director |
|
March 31, 2010 |
141
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