ITEM 1A RISK FACTORS
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 the fourth quarter of 2008, and if our operating cash flow is not sufficient to carry out our drilling plans for 2009, 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 in 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 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:
•incur additional indebtedness;
•create liens;
•sell our assets or consolidate or merge with or into other companies;
•make investments and other restricted payments, including dividends; and
•engage in transactions with affiliates.
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 April 14, 2009, the lenders waived compliance with the current ratio as of December 31, 2008 and March 31, 2009, and with such other restrictive covenants, subject to certain financial caps, until the next borrowing base redetermination expected in the fall of 2009. We have also not been in compliance with certain financial covenants for the last four quarters, including the first quarter of 2009, but obtained waivers and/or amendments in each instance. As a result of such non-compliance, we are unable to borrow additional funds under our credit agreement. We believe that we may not be in compliance with certain restrictive covenants throughout 2009, but will seek additional waivers. There can be no assurance that we will be able to obtain such waivers or that such waivers will be obtained on acceptable terms. If we are unable to obtain future waivers and/or to comply with the restrictive covenants, the lenders could accelerate our indebtedness or foreclose on properties held by liens. In addition, due to borrowing base limitations, we are currently unable to borrow additional funds under the credit facility. In connection with the waiver of the restrictive covenants, the lenders reduced our borrowing base to $9.0 million, with further monthly reductions until the borrowing base reaches $6.5 million on October 1, 2009. If natural gas prices do not improve, we expect that our borrowing base could be further reduced in the future.
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 the fourth quarter of 2008 due to low natural gas prices. Future cash flows and the availability of financing will be subject to a number of variables such as:
•the level of production from existing wells;
•prices of natural gas and oil;
•our results in locating and producing new reserves;
•the success and timing of development of proved undeveloped reserves; and
•general economic, financial, competitive, legislative, regulatory and other factors beyond our control.
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:
•the domestic and foreign supply of natural gas and oil;
•the activities of the Organization of Petroleum Exporting Countries and state-owned oil companies relating to oil price and production controls;
•overall domestic and global economic and political conditions;
•the consumption pattern of industrial consumers, electricity generators and residential users;
•the availability of transportation systems with adequate capacity;
•price and availability of alternative fuels;
•weather conditions and fluctuating seasonal demand;
•natural disasters;
•acts of terrorism;
•political stability in the Middle East and elsewhere;
•domestic and foreign governmental regulations, including conservation efforts and taxation;
•the price and quantity of foreign imports; and
•the price and availability of alternative fuels.
In the past, natural gas prices have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2007, the NYMEX natural gas index price ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu, while the CIG natural gas index price ranged from a high of $7.11 per MMBtu to a low of $0.06 per MMBtu. For example, 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. Due to a decline in the price of natural gas during the third quarter and the beginning of the fourth quarter, we curtailed substantially all new drilling for the fourth quarter of 2008 and have shut-in a number of wells that are not economic at current natural gas price levels.
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, 2008 would decrease from $32.8 million to $31.7 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 $18.2 million for the years ended December 31, 2008 and 2007, respectively, due to low CIG index prices. Based on the CIG index price of $2.20 per Mcf on April 9, 2009, we would have been required to take a total impairment of approximately $46.7 million at December 31, 2008. 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 62% of our total proved reserves as of December 31, 2008 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.
As of December 31, 2008, approximately 18% of our total proved reserves were undeveloped and approximately 44% 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 2009, 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 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:
•geological conditions;
•changes in governmental regulations and taxation;
•assumptions governing future prices;
•the amount and timing of actual production;
•future operating costs; and
•the capital costs of drilling new wells.
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from 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.
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:
•unexpected or adverse drilling conditions;
•elevated pressure or irregularities in geologic formations;
•equipment failures, repairs or accidents;
•title problems;
•fires, explosions, blowouts, cratering, pollution and other environmental risks or other accidents;
•compliance with governmental regulations;
•adverse weather conditions;
•reductions in natural gas and oil prices;
•pipeline ruptures;
•unavailability or high cost of drilling rigs, other field services, equipment and labor; and
•limitations in the market for oil and gas.
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:
•the results of our exploration efforts and the acquisition, review and analysis of data;
•the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
•the approval of the prospects by the other participants after additional data has been compiled;
•economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability and prices of drilling rigs and crews; and
•the availability of leases and permits on reasonable terms for the prospects.
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. For example, in December 2007, the U.S. BLM imposed a permitting application fee of $4,000 per well drilled on federal lands. This fee increased our regulatory costs in 2008 by an additional $1.0 million and affected the timing of our development of federal leases.
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, 2008, Enserco Energy and United Energy Trading purchased 46% and 54% 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, 2008 through December 31, 2008,
Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.17 to a discount of $6.26, and the differential averaged a discount of $2.45.
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 otherwise receive from increases in prices for natural gas. Please see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Item 7A, Quantitative and Qualitative Disclosures About Market Risk-Commodity Price Risk 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. For example, 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.
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.
Shortages of drilling rigs and equipment and experienced personnel could delay our operations.
Higher natural gas prices generally increase the demand for drilling rigs and equipment, field services and personnel with drilling or other oil and gas operational experience, and can lead to shortages of, and increasing costs or wages for, such equipment, services and personnel. Shortages of, or increasing costs for, experienced operational personnel and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in wages or drilling or other operational costs could reduce our revenues.
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 2009 to 2018. 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 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. For example, in December 2007 the U.S. BLM imposed a permitting application fee of $4,000 per well drilled on federal lands. This fee increased our regulatory costs in 2008 by an additional $1.0 million and affected the timing of our development of federal leases.
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.
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:
•we cannot obtain future permits from applicable regulatory agencies;
•water of lesser quality is produced;
•our wells produce excess water; or
•new laws or regulations require water to be disposed of in a different manner.
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 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 Partner and Principal, respectively, of Avista Capital Holdings, L.P., or Avista, a private equity firm that makes investments in the energy sector. 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. 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 Schnabel is a Managing Director of DLJ Merchant Banking which holds a 32.9% 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 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. In addition, the public accounting firm auditing the company's financial statements must attest to and report on management's assessment of the effectiveness of the company's internal control over financial reporting. The requirement to include management's report first applies to this annual report. Our accounting firm will first be required to attest to and report on management's assessment in the annual report for the year ended December 31, 2009. 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, when required, 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.
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 32.9% 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 8.3% 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 2008, the closing price of our common stock ranged from a high of $5.10 per share to a low of $0.24 per share. The risk factors set forth in this report, among other items, could affect our stock price.
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. However, the NASDAQ has proposed suspending the $1.00 minimum bid requirement through July 19, 2009. If
NASDAQ reinstates the $1.00 minimum bid price requirement as scheduled and, thereafter, the closing bid price for our common stock is below $1.00 per share for 30 consecutive days or if we in the future fail to meet the other requirements for continued listing on the NASDAQ Global Market, then our common stock could be delisted.
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.
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. You do not have statutory "preemptive rights" and therefore are not 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, your 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:
•authorize the issuance of blank check preferred stock that could be issued by our board of directors to thwart a takeover attempt;
•classify the board of directors into staggered, three-year terms, which may lengthen the time required to gain control of our board of directors;
•prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;
•require super-majority voting by our stockholders to effect amendments to provisions of our certificate of incorporation concerning the number of directors;
•require super-majority voting by our stockholders to effect any stockholder-initiated amendment to any provision of our bylaws;
•limit who may call special meetings of our stockholders;
•prohibit stockholder action by written consent, thereby requiring all actions to be taken at a meeting of the stockholders;
•establish advance notice requirements for stockholder nominations of candidates for election to the board of directors or for stockholder proposals that can be acted upon at annual meetings of stockholders; and
•require that vacancies on the board of directors, including newly-created directorships, be filled only by a majority vote of directors then in office.
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.
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
ITEM 1B UNRESOLVED STAFF COMMENTS
None.
ITEM 3
ITEM 3 LEGAL PROCEEDINGS
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of our business. 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, management believes, based on its 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 of Diamond Cross Ranch 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 court 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 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, we have continued our operations in the two project areas. To date, there has been no appeal by the plaintiff.
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. Therefore it is extremely difficult to reasonably quantify future environmental and regulatory expenditures.
Please see Items 1 and 2, Business and Properties-Regulation-Permitting Issues for Federal Lands, regarding litigation in which we have intervened with respect to CBM production in Wyoming and Montana.
ITEM 4
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5
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 April 9, 2009, we had 29,188,009 shares of common stock outstanding held of record by approximately 60 record holders.
The following table sets forth, for the periods indicated, the high and low closing sales prices for our common stock. The last reported sales price of our common stock on April 9, 2009 was $0.23 per share.
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.
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, 2008, 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
of Pinnacle Gas Resources, the Amex Natural Resources Industry 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 2008.
ITEM 6
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 Operations and our financial statements and related notes included elsewhere in this document.
(1)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 the provisions of Statement of Financial Accounting Standard
No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"). SFAS No. 133 requires us to record derivative instruments at their fair value. Our management has chosen not to use hedge accounting for these arrangements. For the years ended December 31, 2008, 2007, 2006, 2005 and 2004 we have classified the gains and losses (both realized and unrealized) on derivatives to 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.
(2)For all periods in which there was a net loss attributable to common stockholders, all of our stock options and warrants were anti-dilutive. Common stock equivalents of 676,250, 871,000, 1,035,000, 13,676,200 and 9,187,500 at December 31, 2008, 2007, 2006, 2005 and 2004, respectively, were excluded because they were anti-dilutive.
(1)Long-term debt does not include fair value of derivatives, asset retirement obligation and the long-term portion of production taxes for the year ended December 31, 2008. Debt from the credit facility of $11.5 million is included in "Long term debt-current portion" for the year ended December 31, 2008.
(2)On April 11, 2006, we used approximately $53.6 million of the net proceeds from our private placement to redeem all of the outstanding shares of our Series A Redeemable Preferred Stock, all of which were held by DLJ Merchant Banking.
ITEM 7
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, 2008, we owned natural gas and oil leasehold interests in approximately 477,000 gross (332,000 net) acres, approximately 90% of which were undeveloped. As of December 31, 2008, we had estimated net proved reserves of approximately 27.7 Bcf based on the year-end CIG index price of $4.61 per Mcf.
We had a total capital expenditure budget of $30.1 million for 2008 and expected to drill 146 gross (110 net) wells during the period. However, due to low CIG index prices, the economic climate and limited capital resources, we reduced our capital expenditure budget resulting in actual 2008 capital expenditures of $27.8 million. In connection with our reduced capital expenditure budget, we also reduced our drilling and completion targets for 2008 and drilled 117 gross (82 net) wells. We curtailed substantially all new drilling in the fourth quarter of 2008, and have shut-in a 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. Our capital expenditure budget for 2009 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" 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
Credit Facility and Liquidity. On April 14, 2009 we and the lenders entered into the fourth amendment to the credit facility which 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 next borrowing base redetermination expected in the fall of 2009, subject to certain financial caps. In connection with the waiver of the restrictive covenants, the lenders reduced our borrowing base to $9.0 million, with further monthly reductions until the borrowing base reaches $6.5 million on October 1, 2009. We believe that we may not be in compliance with certain restrictive covenants throughout 2009, but will seek additional waivers. There can be no assurance that we will be able to obtain such waivers or that such waivers will be obtained on acceptable terms. If we are unable to obtain future waivers and/or to comply with the restrictive covenants, the lenders could accelerate our indebtedness under the credit facility or foreclose on properties held by liens. We have remained in compliance with the payment of principal and interest pertaining to the credit facility including ensuring that our outstanding borrowings remain within the limitations of the borrowing base. Due to borrowing base limitations and waiver stipulations, we are currently unable to incur additional indebtedness under the credit facility.
In accordance with accounting guidance, we have classified all of the outstanding debt under the credit facility totaling $11.5 million as of December 31, 2008 as a current payable because it is unlikely that we will have cured the noncompliance of certain restrictive covenants during the next 12 months. We have further reduced our outstanding indebtedness under the credit facility to $9.0 million as of April 14, 2009 in order to be in compliance with the new borrowing base limitation.
We are actively marketing 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. 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. Management believes that appropriate steps, including cost-cutting measures, are being taken to make operations sustainable in the future. Although we are pursuing various alternatives to provide additional liquidity, there is no assurance of the likelihood or timing of any of these transactions.
Economic and Natural Gas Pricing Environment. During 2008, the global economy experienced a significant downturn. The downturn, which began over concerns related to the U.S. financial markets, spread to other industries which included the energy industry. The initial affects 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 our credit facility and 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 $7.84 per Mcf for the first eight months of 2008 but only $3.15 per Mcf for the last four months of 2008. This 60% decrease in price has caused us to reevaluate our 2009 business plan. We have curtailed drilling except for wells that will hold significant blocks of acreage. We have 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.
Supplemental Environmental Impact Statement. A record of decision for the SEIS covering federal lands in the Powder River Basin in Montana was signed by the BLM on December 30, 2008. This record of decision removed the injunction on drilling on federal leases in Montana, which impacted approximately 201,000 gross (168,000 net) acres of our leasehold position. We are evaluating our future plans of development in Montana.
Critical Accounting Policies
The most subjective and complex judgments used in the preparation of our financial statements are:
•Reserve evaluation and determination;
•Estimates of the timing and cost of our future drilling activity;
•Estimates of the fair valuation of hedges in place;
•Estimates of timing and cost of asset retirement obligations;
•Estimates of the expense and timing of exercise of stock options;
•Accruals of operating costs, capital expenditures and revenue; and
•Estimates for litigation. 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 $5.6 million, $0.7 million and $0 as of December 31, 2008, 2007, and 2006, 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 $7.3 million, $6.4 million and $5.7 million as of December 31, 2008, 2007, and 2006, 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 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, we calculate the full cost ceiling limitation. 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 in effect at that date. An impairment of approximately $21.5 million was therefore recorded in the fourth quarter of 2008, resulting in a total impairment for the year ended December 31, 2008 of approximately $21.5 million. The impairment of our oil and gas properties resulted from low commodity prices in the fourth quarter of 2008. Based on the CIG index price of $2.20 per Mcf on April 9, 2009, we would have been required to take a total impairment of approximately $46.7 million at December 31, 2008. A decline in gas prices or an increase in operating costs or reductions in economically recoverable quantities could result in the recognition of additional impairments of our oil and gas properties in future periods.
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, 2008, 2007 and 2006, 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, 2008, 2007 and 2006 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 $209,000 change for 2008, a $306,000 change for 2007 and a $319,000 change for 2006.
Asset Retirement Obligations
We follow the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for the Asset Retirement Obligations." SFAS No. 143 generally applies 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. SFAS No. 143 requires 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 $337,000 effect on our asset retirement obligation liability at December 31, 2008.
The following is a summary of our asset retirement obligation activity for the years ended December 31, 2008 and 2007 (in thousands):
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 $47,000 reduction in our inventory valuation as of December 31, 2008. 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 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 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 an impairment. No impairments were recorded during the years ended December 31, 2008, 2007 and 2006.
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, 2008 would have increased or decreased our expenses
billed to working interest owners by approximately $184,000. 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. General and administrative expenses for the year ended December 31, 2008 also include $2.1 million of merger related costs attributable to the failed merger with Quest Resource Corporation.
Income Taxes
We use the asset and liability method of accounting for income taxes, in accordance with SFAS No. 109, "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, 2008, 2007 and 2006, we had recorded a full valuation allowance for our net deferred tax asset.
On January 1, 2007, we adopted the Financial Accounting Standards Board Interpretation No. 48, "Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109" (FIN 48). FIN 48 prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. FIN 48 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 FIN 48, we performed a comprehensive review of our material tax positions in accordance with recognition and measurement standards established by FIN 48.
As a result of this review, we did not identify any material deferred tax assets that required adjustment. As of December 31, 2008 and 2007 we had not recorded any material uncertain tax benefits.
Our policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2008, 2007 and 2006, we have 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. The tax years that remain open to examination by the U.S. Internal Revenue Service are years 2004 through 2008. 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.
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 the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 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 of the notes to our 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 the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings.
Stock-Based Compensation
Effective January 1, 2006, we adopted SFAS No. 123(R), "Share-Based Payments," which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards. SFAS No. 123(R) 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 SFAS No. 123(R), 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, 2008, 2007 and 2006. We record compensation expense related to non-employees under the provisions of SFAS No. 123 and Emerging Issues Task Force EITF 96-18 "Accounting for Equity Instruments that are Issued to Other than Employees for Acquiring, or in conjunction with Selling Goods or Services" and recognize compensation expense over the vesting periods of such awards.
As required by SFAS No. 123, as amended by SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," we have computed the fair value of options granted using the Black-Scholes option pricing model. In order to calculate the fair value of the options, 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 grants after January 1, 2006, we used a volatility rate of 35% and began to include estimated forfeiture rates. We estimated the volatility rate of our common stock at the date of the grant based on the historical volatility of comparable companies. 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 were granted during the year ended December 31, 2008.
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, 2008 and 2007, respectively.
Transportation Costs
We account for transportation costs under Emerging Issues Task Force Issues 00-10, "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 SFAS No. 5, "Accounting for Contingencies," which states that a loss contingency be recorded if it is probable that a liability has been incurred and it is reasonably estimatable. At December 2008, 2007 and 2006, we recorded $0, $0 and $500,000 respectively, 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 676,250, 871,000 and 1,035,000 at December 31, 2008, 2007, and 2006, respectively, were excluded because they were anti-dilutive due to the net loss attributable to stockholders incurred in such periods.
Recent Accounting Pronouncements
For information concerning recent accounting pronouncements, please see Note 1 of 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, prices of oil and natural gas have dropped significantly at the end of 2008. As a result of low CIG index prices, the economic climate and limited capital resources, we reduced our 2008 capital expenditure budget and drilling and completion targets. We curtailed substantially all new drilling in the fourth quarter of 2008, and shut-in a number of non-economic wells. If natural gas prices remain low, we expect to continue to operate with a reduced capital expenditure plan. Under such 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.
We have also experienced increasing costs since our inception in 2003 due to increased demand for oilfield products and services. The cyclical nature of the natural gas industry causes fluctuations in demand for goods and services from oilfield companies, suppliers and others associated with the industry, which in turn affects the prices for those goods and services. Typically, as prices for natural gas increase, so do all the costs associated with natural gas production. The decline in natural gas prices and the general economy, beginning in the fourth quarter of 2008, have curtailed drilling and development of coalbed methane properties in our area. The resulting decrease in demand for drilling rigs, cement, and tubulars has resulted in a decrease in the cost of these goods and services.
Historically, natural gas prices have been extremely volatile, and we expect that volatility to continue. For example, 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. During the year ended December 31, 2007, the NYMEX natural gas index price ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu, while the CIG natural gas index price ranged from a high of $7.11 per MMBtu to a low of $0.06 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 years ended December 31, 2008, 2007 and 2006, 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 have 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, 2008 through December 31, 2008, Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.17 to a discount of $6.26, with an average differential of a discount of $2.45. The Rockies Express Pipeline which was completed and placed into service in early 2008, has increased takeaway capacity by approximately 1.5 Bcf per day from these 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 development schedule of proposed pipelines.
Results of Operations
Net loss attributable to stockholders for the year ended December 31, 2008 was $21.7 million, or $0.75 per diluted share, on total revenues of $22.4 million. Other income for the year ended December 31, 2008 included a $3.8 million unrealized gain associated with the change in the fair valuation of our natural gas hedges in place in accordance with the provisions of SFAS No. 133. Absent such change in the valuation of hedges, we would have shown a loss of $25.5 million. This compares to a net loss attributable to stockholders of $23.4 million for the year ended December 31, 2007 on total revenue of $13.1 million. Adjusted for an unrealized loss in the fair valuation of our natural gas hedges in place of $2.3 million shown in other income, our results for the year ended December 31, 2007 would have been a net loss attributable to common stockholders of $21.1 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 the provisions of SFAS No. 133. SFAS No. 133 requires us to record derivative instruments at their fair value. Management has chosen not to use hedge accounting for these arrangements. Therefore, in accordance with SFAS No. 133, changes in the fair market value are recognized in earnings.
For the year ended December 31, 2006, the gains and losses (both realized and unrealized) on derivatives were reported in "total revenues" in the statements of operations. For the years ended December 31, 2008, 2007 and 2006, we have reclassified the gains and losses (both realized and unrealized) on derivatives to other income/expense in the statements of operations. We believe that this presentation more 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, 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 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.
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, that we implemented in late 2008. On an 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 a $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.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Gas sales volume.
Gas sales volume increased 40%, from 2,413 MMcf in the year ended December 31, 2006 to 3,389 MMcf in the year ended December 31, 2007. Daily sales volume averaged 9.3 MMcf for the year ended December 31, 2007 as compared to 6.6 MMcf for the year ended December 31, 2006, a 2.7 MMcf per day increase. The increase was primarily due to production coming online in our Cabin Creek, Kirby and Deer Creek project areas.
Gas sales revenue.
Revenue from gas sales increased $0.9 million during the year ended December 31, 2007, to $13.1 million, an 8% increase compared to the year ended December 31, 2006. This increase was primarily due to an increase in gas sales volume which was partially offset by a decrease in the average realized price per Mcf. The average realized price per Mcf decreased 23%, from $5.05 per Mcf in the year ended December 31, 2006 to $3.88 per Mcf in the year ended December 31, 2007.
Derivatives.
For the year ended December 31, 2007, we had an unrealized loss of $2.3 million compared to an unrealized gain of $6.7 million for the year ended December 31, 2006. The unrealized loss is a noncash expense based primarily on the Black-Scholes model for valuing future cash flows utilizing price volatility with a normal discount rate. Hedges settled in the year ended December 31, 2007 resulted in a realized gain of $4.5 million compared to a hedge gain of $0.7 million in the year ended December 31, 2006. The hedge gains were 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 increased $1.7 million in the year ended December 31, 2007 to $4.7 million, a 58% increase compared to the year ended December 31, 2006. This increase resulted from an increase in the number of wells in the productive cycle during the year ended December 31, 2007. On an Mcf basis, lease operating expenses increased 12% from $1.24 per Mcf in the year ended December 31, 2006 to $1.39 per Mcf in the year ended December 31, 2007. 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 also contributed to our higher operating expenses.
Production taxes.
Production taxes increased $0.2 million in the year ended December 31, 2007 to $1.4 million, a 17% increase from the year ended December 31, 2006. 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. The increase in production taxes for the year ended December 31, 2007 was primarily due to increased revenues associated with increased volume and a slight increase in county tax rates in Wyoming. On an Mcf
basis, production taxes were $0.41 per Mcf for the year ended December 31, 2007 and $0.50 per Mcf for the year ended December 31, 2006, an 18% decrease, which correlates to the decrease in the price per Mcf received in the year ended December 31, 2007 from the year ended December 31, 2006.
Marketing and transportation.
Marketing and transportation expenses increased $1.5 million in the year ended December 31, 2007 to $3.5 million, a 77% increase from the year ended December 31, 2006. The increase related primarily to increased sales volume in the year ended December 31, 2007, together with a slight increase in transportation fees and compression due to inflationary adjustments in the contracts along with fees paid for compression design capacity which was not used. On an Mcf basis, marketing and transportation expenses increased 26% to $1.02 per Mcf in the year ended December 31, 2007 from $0.81 per Mcf in the year ended December 31, 2006.
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 increased 27% to $1.6 million in the year ended December 31, 2007, from $1.2 million in the year ended December 31, 2006, due to increased productive wells which we operate and for which we charge an overhead fee. General and administrative expenses, net increased $0.8 million in the year ended December 31, 2007 to $5.2 million from $4.3 million in the year ended December 31, 2006. This increase was due primarily to an increase in payroll expenses due to the hiring of additional employees during the year ended December 31, 2007. On an Mcf basis, general and administrative expenses, net decreased 15% from $1.80 per Mcf in the year ended December 31, 2006 to $1.53 per Mcf in the year ended December 31, 2007.
Depreciation, depletion, amortization and accretion.
Depreciation, depletion, amortization and accretion expense decreased $0.2 million for the year ended December 31, 2007 to $6.5 million, a 2% decrease compared to the year ended December 31, 2006. This decrease was due to a decrease in the full cost pool due to the impairments recorded in 2007 coupled with higher year-end reserves at December 31, 2007 compared to December 31, 2006. On an Mcf basis, the depreciation, depletion, amortization and accretion rate decreased 31% to $1.92 per Mcf in the year ended December 31, 2007 from $2.77 per Mcf in the year ended December 31, 2006.
Impairment.
At December 31, 2007, the full cost ceiling of our oil and gas properties exceeded the capitalized cost basis by approximately $10.6 million, based upon a natural gas price of approximately $6.04 per Mcf in effect at that date. An impairment was recorded for the nine months ended September 30, 2007 of approximately $18.2 million, resulting in a total impairment for the year ended December 31, 2007 of approximately $18.2 million. The impairment of our oil and gas properties resulted from low commodity prices throughout the year. For further information regarding this impairment, please see Note 1 of the notes to our audited financial statements appearing elsewhere in this report.
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 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.
Sales of Equity. In April 2006, we completed a private placement of an aggregate of 12,835,230 shares of our common stock at a price per share of $11.00, or $10.23 net of the initial purchaser's discount and placement fee. In May 2007, we completed an initial public offering of an aggregate of 3,750,000 shares of our common stock at a price per share of $9.00, or $8.37 net of the underwriters' discounts and commissions. Please see the information under the heading "Cash Flow from Financing Activities" in this Item 7.
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, 2008 and March 31, 2009, we had $11.5 million and $10.5 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 of approximately $666,667 per month until it reached $10.5 million on April 1, 2009. As of April 13, 2009, our borrowing base was reduced to $9.0 million, subject to automatic reductions of $500,000 per month until it reaches $6.5 million on October 1, 2009 where it will remain until the next borrowing base redetermination. If natural gas prices do not improve, we expect that our borrowing base could be further reduced in the future.
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 February 12, 2011.
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 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, as amended, contains covenants that among other things restrict our ability (subject to certain exceptions) to do the following:
•incur liens;
•incur debt;
•make investments in other persons;
•declare dividends or redeem or repurchase stock;
•engage in mergers, acquisitions, consolidations and asset sales or amend our organizational documents;
•enter into certain hedging arrangements;
•amend material contracts; and
•enter into related party transactions.
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.
On April 14, 2009, we and the administrative agent entered into the fourth amendment to the credit agreement which 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, subject to certain financial caps, until the next borrowing base redetermination expected in the fall of 2009. We believe that we may not be in compliance with certain restrictive covenants throughout 2009, but will seek additional waivers. There can be no assurance that we will be able to obtain such waivers or that such waivers will be obtained on acceptable terms. If we are unable to obtain future waivers and/or to comply with the restrictive covenants and are therefore in default, the lenders could avail themselves of the remedies under the credit agreement, including acceleration and foreclosure. Due to borrowing base limitations and waiver stipulations, we are unable to incur additional debt 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 September 30, 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 September 30, 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.
We and the administrative agent entered into the fourth amendment to the credit agreement (the "fourth amendment") dated as of April 14, 2009. In addition to waiving compliance with certain restrictive covenants, the fourth amendment reduced our borrowing base as described above.
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 bore interest at 6.875% until November 15, 2008, and at a variable base rate plus 0.5% thereafter and 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 $531,300 will become due. As of December 31, 2008, we had $763,000 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%.
Capital Expenditure Budget. We had a total capital expenditure budget of $30.1 million for 2008 and expected to drill 146 gross (110 net) wells during that period. However, due to low CIG index prices, the economic climate and limited capital resources, we reduced our 2008 capital expenditure budget resulting in actual 2008 capital expenditures of $27.8 million. In connection with our reduced capital expenditure budget, we also reduced our drilling and completion targets for 2008 to 117 gross (82 net) wells. We curtailed substantially all new drilling in the third and fourth quarters of 2008, and have shut-in a 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 through 2009. 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 2007 and 2008 and at times reached unusually low levels. For instance, the CIG monthly index price per Mcf was $1.78, $3.41, $2.78 and
$4.63 for delivery in September, October, November and December of 2008, respectively. If prices remain low, our cash flows from operations will decrease and the borrowing base and borrowing availability under our credit facility could be further reduced. 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 2009 will be dependent upon CIG index prices, our operating cash flows and the availability of additional capital resources.
Cash Flow from Operating Activities
Net cash provided by operating activities was approximately $7.6 million for the year ended December 31, 2008, compared to net cash used by operating activities of $16.7 million for the year ended December 31, 2007 and net cash provided by operating activities of $6.0 million for the year ended December 31, 2006. The increase in 2008 was primarily due to an increase in our accounts payable balance, a decrease in our accounts receivables and prepaid expenses along with an impairment of our oil and gas properties.
As a result of low natural gas prices, our cash flows from operations have not been sufficient to fund our cash requirements and we have been required to draw on our credit facility. If natural gas prices continue to trend downward, our cash flows from operations will decrease and the borrowing base under our credit facility will be reduced.
Cash Flow from Investing Activities
Net cash used in investing activities was approximately $26.9 million, $9.4 million and $63.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. 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. Net cash used in investing activities decreased by approximately $54.5 million in 2007 compared to 2006 due to decreased investment in the acquisition and development of undeveloped leaseholds primarily due to low gas prices in the Rocky Mountain region.
Cash Flow from Financing Activities
Net cash provided by financing activities was approximately $11.5 million for the year ended December 31, 2008 as compared to $29.5 million and $59.9 million for the years ended December 31, 2007 and 2006, respectively. The change in 2007 from 2006 was primarily due to our April 2006 private placement and our May 2007 initial public offering. 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 $29.5 million from our May 2007 initial public offering.
In April 2006, we completed a private placement, exempt from registration under the Securities Act, of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors at a price of $11.00 per share, or $10.23 per share net of the initial purchaser's discount and placement fee. Out of the approximately $129.9 million of net proceeds (after expenses) we received in the private placement, we used (i) approximately $53.6 million to redeem all of the outstanding shares of our Series A Redeemable Preferred Stock, including the payment of all accrued and unpaid dividends and a redemption premium, (ii) approximately $27.0 million for our acquisition of the Green River Basin assets and (iii) approximately $16.3 million to repurchase an aggregate of 1,593,783 shares of common stock at a price of $10.23 per share from DLJ Merchant Banking and Gary W. Uhland, our former President, and (iv) approximately $33.0 million to fund our development drilling program and pay additional offering expenses and for general corporate purposes.
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 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, 2008. 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 8 and 9 of the notes to our audited financial statements appearing elsewhere in this report for information regarding our credit facility and other indebtedness.
The following table summarizes by period our contractual obligations as of December 31, 2008:
At December 31, 2008, the commodity derivatives asset was valued at $4,345,000, which represents a current receivable attributable to 2008.
ITEM 7A
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 market 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, 2008. At December 31, 2008, we had hedged volumes through December 2009. Please see Note 6 and Note 20 of the notes to the audited
financial statements appearing elsewhere in this report for further information regarding our derivatives.
(1)Volumes hedged using the CIG index price published in the first issue of Inside FERC's Gas Market Report for each calendar month of the derivative transaction.
(2)Assumes ceiling prices for natural gas collar volumes.
(3)Fair value based on CIG index price in effect for each month as of December 31, 2008. Interest Rate Risk
Borrowings under our credit facility bear interest at fluctuating market-based rates. Accordingly, our interest expenses are sensitive to market changes, which expose us to interest rate risk on current and future borrowings under our credit facility.
As of December 31, 2008 and March 31, 2009, we had $11.5 million and $10.5 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 5.3% for the year ended December 31, 2008. 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 $115,000 per year based on our outstanding indebtness at December 31, 2008.
ITEM 8
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, 2008 and 2007, and the related statements of operations, redeemable preferred stock and stockholders' equity and cash flows for each of the years in the three year period ended December 31, 2008. 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, 2008 and 2007 and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.
/s/ Ehrhardt Keefe Steiner & Hottman PC
Denver, Colorado
April 14, 2009
PINNACLE GAS RESOURCES, INC.
Balance Sheets
See Notes to Financial Statements
PINNACLE GAS RESOURCES, INC.
Statements of Operations
See Notes to Financial Statements
PINNACLE GAS RESOURCES, INC.
Statements of Cash Flows
(In thousands)
See Notes to Financial Statements
Pinnacle Gas Resources, Inc.
Statements of Redeemable Preferred Stock and Stockholders' Equity
See Notes to Financial Statements
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 over 94% 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, 2008 was located in the northern end of the Powder River Basin in northeastern Wyoming and southern Montana.
As of December 31, 2008, the Company owned natural gas and oil leasehold interests in approximately 477,000 gross (332,000 net) acres, approximately 90% of which were undeveloped. At December 31, 2008, the Company had estimated net proved reserves of 27.7 Bcf, based on a year-end Colorado Interstate Gas, or CIG, index price of $4.61 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, 2008, the Company owned interests in 663 gross (366 net) producing wells and operated 97% of these wells. During the year ended December 31, 2008, the Company drilled 117 gross (82 net) wells and produced an average of 10.6 MMcf per day net to its interest. The Company exited 2008 producing 10.1 MMcf per day net to its interest. During 2007, the Company drilled 87 gross (61 net) wells and produced an average of 9.3 MMcf per day net to its interest.
The Company had a total capital expenditure budget of $30.1 million for 2008 and expected to drill 146 gross (110 net) wells during the period. However, due to low CIG index prices, the economic climate and limited capital resources, the Company reduced its 2008 capital expenditure budget resulting in actual 2008 capital expenditures of $27.8 million. In connection with the reduced capital expenditure budget, the Company also reduced its drilling and completion targets for 2008. The Company curtailed substantially all new drilling in the fourth quarter of 2008, and shut-in a number of wells that are not economic at current natural gas price levels. If natural gas prices remain low, the Company expects to continue to operate with a reduced capital expenditure plan. Under its reduced capital expenditure plan, the Company expects to 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 Company's capital expenditure budget for 2009 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.
The Company is not in compliance with the current ratio financial covenant and certain other restrictive covenants related to accounts payable, permitted liens and permitted debt under the credit facility. On April 14, 2009, the Company entered into a fourth amendment to the credit facility that waived compliance with the current ratio covenant as of December 31, 2008 and March 31, 2009, and
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
with such other restrictive covenants, subject to certain financial caps, until the next borrowing base redetermination expected in the fall of 2009. In connection with the waiver of the restrictive covenants, the lenders reduced our borrowing base to $9.0 million, with further monthly reductions until the borrowing base reaches $6.5 million on October 1, 2009. The Company believes that it may not be in compliance with certain covenants throughout 2009, but management anticipates receiving waivers in the future based on prior dealings with the lender and compliance with the borrowing base limitations. Due to borrowing base limitations and waiver stipulations, the Company is currently not able to receive further credit extensions under the credit facility. Further, in accordance with Emerging Issues Task Force ("EITF") Issue 86-30, the Company has classified the debt related to the credit facility of $11.5 million in current liabilities as of December 31, 2008 because it is unlikely that the Company will have cured the noncompliance of the current ratio covenant during the next 12 months. However, such debt is due and payable to the administrative agent and lender in February 2011 pursuant the terms of the credit facility. The Company has remained in full compliance with the payment of principal and interest pertaining to the credit agreement including ensuring that the outstanding borrowings remain within the limitations of the borrowing base. The Company has further reduced the debt outstanding under the credit agreement to $9.0 million as of April 14, 2009 which was in compliance with the new borrowing base requirements.
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. 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 plans to use the remainder for general operating purposes. The Company has also put additional hedges of its gas in place to secure certain operating cash flow levels during the remainder of 2009. From January through April 2009, the Company had 4,500 MMbtu per day hedged through a combination of a fixed price swap and a costless collar at a weighted average floor price of $6.87 per MMbtu and a ceiling price of $7.32 per MMbtu. From May through December 2009, the Company has 7,000 MMbtu per day hedged through a combination of a fixed price swap and a costless collar at a weighted average floor price of $5.65 per MMbtu and a ceiling price of $5.93 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. 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
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
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 and 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 realizability of deferred tax assets, the estimates of expenses and timing of the exercise of stock options, accrual of operating costs, capital expenditures and revenue, and estimates for litigation.
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, 2008 and 2007, the Company had an allowance of $100,000.
Inventory
Pinnacle 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:
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
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 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 were recorded during the years ended December 31, 2008, 2007 and 2006.
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") 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. 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 are 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 unproved properties of $5.6, $0.7 and $0 million, respectively, during the years ended December 31, 2008, 2007 and 2006. (See Note 4 for additional discussion of unproved 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 $7.3, $6.4 and $5.7 million as of December 31, 2008, 2007, and 2006 respectively.
Under 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 prices and costs, including the effects of derivative instruments designated as cash flow hedges but excluding the future cash outflows
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
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. At December 31, 2008, the full cost ceiling limitation exceeded the capitalized costs of oil and gas properties by approximately $21.5 million, based upon a natural gas price of $4.61 per Mcf in effect at that date. As such, the Company was required to record an impairment in the fourth quarter of 2008. Based on the CIG index price of $2.20 per Mcf on April 9, 2009, the Company would have been required to take a total impairment of approximately $46.7 million at December 31, 2008. For the year ended December 31, 2007, the Company recorded an impairment of $18.2 million resulting from low commodity prices throughout the year, specifically in the first, second and third quarters of 2007. 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
Pinnacle follows the provisions of Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally applies 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. SFAS No. 143 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 its best estimate of its credit-adjusted risk free rate. The credit adjusted risk free rate is based on our borrowing under the credit facility or, if borrowings are not available under the credit facility, due to exhaustion of the borrowing base or covenant limitations, the rate is based on the interest rate available from our banks for senior secured debt or mezzanine debt. Based on our current inability to borrow against our facility, (see Note 8) our credit adjusted risk free rate at December 31, 2008 was the prime rate plus 7% or 10.25%. 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.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
Changes in the carrying amount of the asset retirement obligations are as follows:
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 2008, 2007 and 2006 were $199,000, $0 and $0, respectively.
Restricted Assets
Certificates of deposit. The Company holds a certificate of deposit ("CD"), which expires in July 2009, totaling $157,000. The CD is collateral on 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, 2008. Additionally, the Company holds two CDs for $604,000 and $964,000 which were issued in February 2006 and May 2008, respectively, and will expire in February 2010 and May 2009, respectively. These CD's 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 and Deer Creek areas. The Company has included these amounts in non-current assets as of December 31, 2008 because the Company also intends to renew the CDs in order to maintain a power supply on a long-term basis. In April 2007, the Company issued a $1,000,000 letter of credit which expires in April 2009 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. The Company has included this amount in non-current assets as of December 31, 2008 because the pipeline and compression facilities are not expected to be completed and fully utilized until the end of 2010.
Deposits. The Company has included approximately $199,000 and $20,000 related to royalty payments in deposits in the accompanying balance sheet at December 31, 2008 and 2007, respectively.
Gas Sales
Pinnacle uses the sales method for recording natural gas sales. Sales of gas applicable to Pinnacle's interest in producing natural gas 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 Pinnacle'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 Pinnacle's share of estimated total gas reserves
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
underlying the property at which time such excess is recorded as a gas imbalance liability. At December 31, 2008 and 2007, 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 Emerging Issues Task Force Issues 00-10, "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, 2008, 2007 and 2006 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, 2008, 2007 and 2006, shares that were excluded from the calculation because they were antidilutive were 676,250, 871,000 and 1,035,000, respectively.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes, in accordance with SFAS No. 109, "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, 2008, 2007 and 2006, the Company had recorded a full valuation allowance for its net deferred tax asset.
Derivatives
The Company accounts for derivative instruments or hedging activities under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires the Company 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.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
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 of the Company decided not to use hedge accounting for these agreements. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings. See Note 6 for additional discussion of derivatives.
Stock-Based Compensation
Effective January 1, 2006, the Company adopted SFAS No. 123(R), "Share-Based Payments," which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards.
Under SFAS No. 123(R), 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, 2008, 2007 and 2006. The Company records compensation expense related to non-employees under the provisions of SFAS No. 123 and Emerging Issues Task Force EITF 96-18 "Accounting for Equity Instruments that are Issued to Other than Employees for Acquiring, or in conjunction with Selling Goods or Services" and recognizes compensation expense over the vesting periods of such awards.
The Company has computed the fair value of options granted using the Black-Scholes option pricing model. In order to calculate the fair value of the options, 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 of comparable companies. 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 were granted during the year ended December 31, 2008. Accordingly, the Company has computed the fair value of all options granted during the years ended December 31, 2008, 2007 and 2006 using the Black-Scholes option pricing model and the following weighted average assumptions:
New Accounting Pronouncements
Effective January 1, 2008, the Company adopted the fair value measurement and disclosure provisions of Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS 157), which establishes specific criteria for the fair value measurements of financial and nonfinancial assets and liabilities that are already subject to fair value measurements under current
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
accounting rules. SFAS 157 also requires expanded disclosures related to fair value measurements. In February 2008, the FASB approved FASB Staff Position (FSP) SFAS No. 157-2, Effective Date of FASB Statement No. 157, which allows companies to elect a one-year delay in applying SFAS 157 to certain fair value measurements, primarily related to nonfinancial instruments. The Company elected the delayed adoption date for the portions of SFAS 157 impacted by FSP SFAS 157-2. The partial adoption of SFAS 157 was prospective and did not have a significant effect on the Company's financial statements. The Company does not expect that the application of the deferred portion of SFAS 157 to the nonrecurring fair value measurements of its nonfinancial assets and liabilities will have a material impact on the Company's financial statements. In accordance with FSP SFAS 157-2, the fair value measurements for nonfinancial assets and liabilities will be adopted effective for fiscal years beginning after November 15, 2008.
In October 2008, the FASB issued FSP SFAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active. FSP SFAS 157-3 clarifies the application of SFAS 157, which the Company adopted as of January 1, 2008, in situations where the market is not active. The Company has considered the guidance provided by FSP SFAS 157-3 in its determination of estimated fair values as of December 31, 2008.
Also effective January 1, 2008, the Company adopted SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment of FASB Statement No. 115 (SFAS 159). SFAS 159 creates a "fair value option" under which an entity may elect to record certain financial assets or liabilities at fair value upon their initial recognition. Subsequent changes in fair value would be recognized in earnings as those changes occur. The election of the fair value option would be made on a contract-by contract basis and would need to be supported by concurrent documentation or a preexisting documented policy. SFAS 159 requires an entity to separately disclose the fair value of these items on the balance sheet or in the footnotes to the financial statements and to provide information that would allow the financial statement user to understand the impact on earnings from changes in the fair value. The Company did not elect the fair value option for any of their financial assets or liabilities.
In December 2007, the FASB issued SFAS No. 141(R), "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 acquiree at fair value as of the acquisition date. SFAS No. 141 (R) also establishes guidance 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. SFAS No. 141(R) 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. SFAS No. 141(R) will be effective for the Company beginning with the 2009 fiscal year. The impact of the adoption of SFAS No. 141(R) 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 March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS No. 161 is intended to improve financial reporting by requiring transparency about the location and amounts of derivative instruments in an entity's financial statements, how
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 1-Summary of Significant Accounting Policies (Continued)
derivative instruments and related hedged items are accounted for under FAS No. 133, and how derivative instruments and related hedged items affect its financial position, financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of this pronouncement will not have an impact on the Company's financial statements, but it will require the Company to expand its disclosures about derivative instruments.
On December 31, 2008, the Securities and Exchange Commission ("SEC") published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company's disclosures, operating results, financial position, and cash flows.
Note 2-Property and Equipment
Property and equipment consists of the following:
Depreciation and amortization expense related to property and equipment for the years ended December 31, 2008, 2007, and 2006, was $1,012,000, $792,000, and $496,000 respectively.
Note 3-Acquisitions and Divestitures
2006 Transactions
On April 20, 2006, the Company purchased 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. The undeveloped leasehold is located in Sweetwater County in the Hay Reservoir area of the Green River Basin. In addition, the Company
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 3-Acquisitions and Divestitures (Continued)
acquired a 65% working interest in existing deep rights below the base of the Fort Union formation. The acquisition was funded with a portion of the net proceeds from the April 2006 private placement.
Effective June 1, 2006, Pinnacle acquired a 100% working interest in 10 producing wells and 1,410 gross acres in the Recluse area for a total purchase price of $1,575,000.
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.
Note 4-Unproved Properties
The Company is currently participating in coalbed methane gas exploration and development activities on acreage in Montana and Wyoming. At December 31, 2008, a determination cannot be made about the extent of additional gas reserves that should be 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, 2008 impairments of $1.6 million and $4.0 million were incurred in the third and fourth quarter, respectively.
Costs excluded from amortization relating to unproved properties at December 31, 2008 are as follows (in thousands):
(1)Acquisition costs included $5.6 million and $0.7 million of impairments for the years ended December 31, 2008 and 2007, respectively.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 4-Unproved Properties (Continued)
Suspended Wells Costs
The following table reflects the net changes in capitalized exploratory well costs during 2008, 2007 and 2006, and does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same period.
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:
The $26.7 million of exploratory well costs capitalized for more than one year are for wells located in Kirby and Cabin Creek. These wells are hooked up to gas sales pipelines and are in the dewatering phase. As soon as the Company receives this approval, the wells will begin the dewatering phase. In the Kirby project area of Montana, the Sweetwater project area of Wyoming and the Cabin Creek area of Wyoming, as the wells produce gas and are determined to be proved reserves, the well costs will be reclassified to the full cost pool.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 5-Accrued Liabilities
Accrued liabilities consist of the following:
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, 2008, 2007 and 2006, the Company had natural gas hedges in place as follows:
The Company has elected not to designate these derivatives as cash flow hedges under provisions of SFAS No. 133. 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 assets totaling $4,345,000 and $556,000 at December 31, 2008 and 2007, respectively. The Company realized hedging gains in 2008, 2007 and 2006 of $1,973,000, $4,511,000, and $663,000 respectively which amounts are included in gains/losses on derivatives in the statement of operations and are included in the cash flows used in 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 gain of $3,789,000 for the year ended December 31, 2008, an unrealized loss of $2,300,000 for the year ended December 31, 2007, and an unrealized gain of $6,699,000 for the year ended December 31, 2006. Unrealized and realized gains and losses are included in gains or losses on derivatives in the statement of operations.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 6-Derivatives (Continued)
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:
The Company operates and disburses revenue to other working interest owners and royalty owners. Proceeds from gas sales are distributed and paid around 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, 2008 and March 31, 2009, the Company had $11.5 million and $10.5 million, respectively, of debt outstanding under the facility. As described below, the Company is 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 of approximately $666,667 per month until it reached $10.5 million on April 1, 2009. As of April 13, 2009, the Company's borrowing base was reduced to $9.0 million, subject to automatic reductions of $500,000 per month until it reaches $6.5 million on October 1, 2009 where it will remain until the next borrowing base redetermination. If natural gas prices do not improve, the Company expects that its borrowing base could be further reduced in the future.
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 February 12, 2011.
The 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
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 8-Line-of-Credit (Continued)
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 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, as amended, contains covenants that among other things restrict the Company's ability (subject to certain exceptions) to do the following:
•incur liens;
•incur debt;
•make investments in other persons;
•declare dividends or redeem or repurchase stock;
•engage in mergers, acquisitions, consolidations and asset sales or amend our organizational documents;
•enter into certain hedging arrangements;
•amend material contracts; and
•enter into related party transactions.
With regard to hedging arrangements, the 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 credit agreement, as amended, also requires that 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
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 8-Line-of-Credit (Continued)
permits and licenses and a change in control. The credit agreement requires any wholly-owned subsidiaries to guarantee the obligations under the credit agreement.
On April 14, 2009, we and the administrative agent entered into the fourth amendment to the credit agreement which 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 next borrowing base redetermination, subject to certain financial caps. The Company believes that it may not be in compliance with certain restrictive covenants throughout 2009, but will seek additional waivers. There can be no assurance that the Company will be able to obtain such waivers or that such waivers will be obtained on acceptable terms. If the Company is unable to obtain future waivers and/or comply with the restrictive covenants and are therefore in default, the lenders could avail themselves of the remedies under the credit agreement, including acceleration and foreclosure.
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, requires 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 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.
The Company and the administrative agent entered into the fourth amendment to the credit agreement (the "fourth amendment") dated as of April 14, 2009. In addition to waiving compliance with certain restrictive covenants, the fourth amendment reduced our borrowing base as described above.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 9-Long-Term Debt Obligations
Long-term debt and capital lease obligations consist of the following:
The following are future minimum obligations for long-term debt as of December 31, 2008 (in thousands):
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 10-Fair Value Measurements
Effective January 1, 2008, the Company adopted SFAS No. 157, "Fair Value Measurements" for all financial assets and liabilities measured at fair value on a recurring basis. The statement establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 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 statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement establishes a hierarchy for grouping these assets and liabilities, based on the significance level of the following inputs:
•Level 1-Quoted prices in active markets for identical assets or liabilities;
•Level 2-Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable;
•Level 3-Significant inputs to the valuation model are unobservable. 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, 2008 (in thousands):
A financial asset or liability is categorized within the hierarchy based upon the lowest level of input that is significant to the fair value measurement. The Company's valuation methodologies for oil and gas derivative instruments, which are measured at fair value and are included in the accompanying balance sheet, are listed below.
The Company uses Level 2 inputs to measure the fair value of oil and gas derivative instruments. The fair value is based on interpolated data. The Company uses an industry standard model that considers various inputs, including (a) quoted forward prices for the specific commodity and area which was hedged, (b) volatility factors with consistent time data that correlates to the remaining life of the derivative instruments and (c) time value. The Company believes that this approach provides a reasonable, non-biased and consistent methodology for valuing oil and gas derivative instruments. In addition, the Company also evaluates company credit risk and counterparty credit risk to determine fair value of the asset or liability and further action as needed.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 11-Income Taxes
The provision for income taxes consists of the following:
The effective income tax rate varies from the statutory federal income tax rate as follows:
The significant temporary differences and carry-forwards and their related deferred tax asset (liability) and deferred tax asset valuation allowance balances are as follows:
For income tax purposes at December 31, 2008, the Company has net operating loss carry-forwards of approximately $40,771,000, which expire in 2028. The Company has provided for a valuation
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 11-Income Taxes (Continued)
allowance of $16,977,000 due to the uncertainty of realizing the tax benefits from its net deferred tax asset.
On January 1, 2007, the Company adopted the provisions of FIN 48, "Accounting for Uncertainty in Income Taxes." FIN 48 prescribes 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. FIN 48 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 FIN 48, the Company performed a comprehensive review of its material tax positions in accordance with recognition and measurement standards established by FIN 48.
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 FIN 48, and as of December 31, 2008 and 2007, 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, 2008, 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 income tax. The tax years that remain open to examination by the U.S. Internal Revenue Service are years 2004 through 2008. 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, 120,000 and 455,000 options to employees under the plans during the years ended December 31, 2008, 2007, and 2006, respectively. At December 31, 2008, there were 1,684,208 shares available for grant under the plans.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 12-Stock Option Plans (Continued)
The options granted all vest as follows:
At December 31, 2008, the Company had unvested options to purchase 126,250 shares with a weighted average grant date fair value of $0.7 million. During the year ended December 31, 2008, the Company did not grant employee options and recognized compensation expense of approximately $613,000 for options granted in prior years. The Company will recognize compensation expense relating to non-vested options granted after January 1, 2006 of approximately $324,000 ratably over the next 2 years.
The following table summarizes stock option activity for the years ended December 31, 2008, 2007 and 2006:
The following table summarizes information about stock options outstanding at December 31, 2008:
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, 2008, 2007 and 2006:
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 July 1, 2008 the Company issued 86,650 shares of restricted stock to certain employees. On August 8, 2008 an additional 10,500 shares were issued to certain employees. In addition, on August 25, 2008, the Company issued 60,000 shares of restricted stock to executive officers of the Company. These shares will vest 33.34%, 33.33% and 33.33% on the first, second and third anniversary of the grant date. Also the Company issued 87,500 shares on August 25, 2008 to non employee directors which vested on December 31, 2008. The Company, recognized an expense of approximately $571,000, $356,000 and $79,000 for the years ended December 31, 2008, 2007 and 2006 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, 2008 and 2007 is presented below.
As of December 31, 2008, the Company had $0.9 million of unrecognized share-based compensation expense related to non-vested stock awards, which is expected to be amortized over the remaining period of 4 years.
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, 2008 and 2007, 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, 2008, 2007 and 2006, the Company issued no shares of Preferred Stock.
Note 14-Stockholders' Equity
Common Stock
As of December 31, 2008, there were 29,193,573 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, our former President, exercised options to acquire 50,000 shares of our 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 our 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
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 14-Stockholders' Equity (Continued)
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' 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 will be used 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 December 2013. Future minimum lease income under noncancelable operating leases is as follows:
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 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
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 15-Commitments and Contingencies (Continued)
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 benefit described above.
Litigation
From time to time, Pinnacle 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, Pinnacle'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 Pinnacle is involved. No assurance can be given that these legal actions will be resolved in Pinnacle's favor. However, Management believes, based on its experiences to date, that these matters will not have a material adverse impact on Pinnacle's business, financial position or results of operations.
Pinnacle, 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 Pinnacle 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 Pinnacle on the basis that Pinnacle'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.
Pinnacle, together with the defendants above, were also named as defendants in a 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, we have continued our operations in the two project areas. To date, there has been no appeal by the plaintiff.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 15-Commitments and Contingencies (Continued)
Pinnacle was named as a defendant in two related lawsuits, Civil Action No. 06CV0047J filed on March 30, 2006 in the United States District Court, Wyoming by Burning Rock Energy, LLC and Case No. 06-CV-01627-MDM-MEH filed on April 25, 2006 in the United States District Court for the District of Colorado by John R. Behrmann, et al., claiming various contract and tort claims against Pinnacle relating to a like-kind exchange between Pinnacle and the plaintiffs of approximately 1,000 acres of leased acreage in January 2004. The plaintiffs claimed, in part, that the leases transferred by Pinnacle to Burning Rock did not terminate upon nonpayment of shut-in rentals and further, that Pinnacle trespassed by releasing from the original lessors the properties originally transferred to Burning Rock under the exchange agreement. In April 2007, Pinnacle settled these claims with the plaintiffs and both lawsuits have been dismissed. The settlement arrangement included a $500,000 payment by Pinnacle to Burning Rock together with an assignment by Pinnacle to Burning Rock of a 69.5% carried working interest in the disputed leased acreage.
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. In December 2007, the U.S. Bureau of Land Management imposed a permitting application fee of $4,000 per well drilled on federal lands.
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, 2008, 2007 and 2006. The loss of any of these customers could have a material adverse effect on the Company's operations.
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. Long-term debt at December 31, 2008 and 2007, with a carrying value of approximately $763,000 and $786,000, respectively, is estimated to approximate fair value as the terms are comparable to current market terms.
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 17-Fair Value of Financial Instruments (Continued)
The fair value of the Company's derivatives are estimated using various models and assumptions related to the estimated terms of the instruments, volatility of the price of the Company's common stock, interest rates and the probability of conversion, among other items.
Note 18-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:
(1)The revision in 2008 is primarily due to the price decrease on December 31, 2008 to $4.61, based on the Rocky Mountain CIG Index, from the December 31, 2007 price of $6.04. The revision in
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 18-Supplemental Oil and Gas Information (Continued)
is primarily due to the price increase on December 31, 2007 to $6.04, based on the Rocky Mountain CIG Index, from the December 31, 2006 price of $4.46. The revision in 2006 is primarily due to the price decrease from December 31, 2005 of $7.72, based on the Rocky Mountain CIG Index, to the December 31, 2006 price of $4.46.
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:
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:
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 18-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:
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 SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." SFAS No. 69 requires 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.
The following table presents the average year-end market gas price used to compute future cash inflows for each period:
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 18-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, 2008, 2007 and 2006 assuming continuation of existing economic conditions.
The following reconciles the change in the standardized measure of discounted future net cash flow:
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.
Note 19-Quarterly Financial Data (Unaudited)
The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2007 and 2006 (in thousands, except per share data):
PINNACLE GAS RESOURCES, INC.
Notes to Financial Statements (Continued)
Note 19-Quarterly Financial Data (Unaudited) (Continued)
Note 20-Subsequent Events
The Company and the administrative agent entered into the fourth amendment to the credit agreement dated as of April 14, 2009. The fourth amendment waived compliance with the current ratio covenant as of December 31, 2008 and March 31, 2009, and with certain other restrictive covenants related to overdue accounts payable, permitted liens and permitted debt until the next borrowing base redetermination expected in the fall of 2009, subject to certain financial caps.
In March 2009, the Company hedged 2,500 MMbtu per day from May 2009 through April 2010 at a price of $3.445 per MMbtu based on the CIG Inside FERC published price.
In March 2009, the Company hedged 2,000 MMbtu per day from January 2010 through December 2010 at a price of $4.475 per MMbtu based on the CIG Inside FERC published price.
In April 2009, the Company sold its interest in approximately 800 net undeveloped acres in the Arvada prospect in Wyoming to an unrelated third party and sold certain of its gas gathering assets in the Cabin Creek area of Wyoming to Big Horn Gas Gathering, L.L.C., the field operator of such assets. The Company's aggregate net proceeds from these transactions were approximately $3.2 million. The Company used part of these proceeds to repay the Company's outstanding indebtedness under its credit facility to $9.0 million as of April 14, 2009.
ITEM 9
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A(T)
ITEM 9A(T) CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our principal executive officer and principal financial officer are responsible for establishing and maintaining adequate disclosure controls and procedures. Based on their evaluation as of the end of the fiscal year ended December 31, 2008, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.
Internal Control Over Financial Reporting
Our 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:
(i)pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
(ii)provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and
(iii)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.
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 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.
Our management assessed the effectiveness of the company's internal control over financial reporting as of December 31, 2008. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.
Based on our assessment, management believes that, as of December 31, 2008, our 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 our internal controls over financial reporting or in other factors during the fourth quarter of 2008 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting. The certifications of our 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.
ITEM 9B
ITEM 9B OTHER INFORMATION
None.
PART III
ITEM 10
ITEM 10 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item 10 is incorporated herein by reference to the "Proposal One: Election of Directors," "Management," "Code of Ethics," "Section 16(a) Beneficial Ownership Reporting Compliance" and "Audit Committee" sections of the definitive Proxy Statement relating to our 2009 Annual Meeting of Stockholders.
ITEM 11
ITEM 11 EXECUTIVE COMPENSATION
The information required by this Item 11 is incorporated herein by reference to the "Executive Compensation" section of the definitive Proxy Statement relating to our 2009 Annual Meeting of Stockholders.
ITEM 12
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item 12 is incorporated herein by reference to the "Security Ownership of Certain Beneficial Owners and Management" section of the definitive Proxy Statement relating to our 2009 Annual Meeting of Stockholders.
ITEM 13
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item 13 is incorporated herein by reference to the "Certain Relationships and Related Transactions" and "Director Independence" sections of the definitive Proxy Statement relating to our 2009 Annual Meeting of Stockholders.
ITEM 14
ITEM 14 PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item 14 is incorporated herein by reference to the "Proposal Two: Ratification of Ehrhardt Keefe Steiner & Hottman PC as our Independent Auditor" section of the definitive Proxy Statement relating to our 2009 Annual Meeting of Stockholders.
PART IV
ITEM 15
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, 2008 and 2007
Statements of Operations for the years ended December 31, 2008, 2007 and 2006
Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006
Statements of Redeemable Preferred Stock and Stockholders' Equity for the years ended December 31, 2008, 2007 and 2006
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).
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).
Exhibit
Number
Description
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).
*10.13
-
Summary of Director Compensation.
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 September 30, 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.
*31.1
-
Certification of President and Chief Executive Officer of Pinnacle Gas Resources, Inc. pursuant to Rules 13a-14(a) and 15d-14(a).
*31.2
-
Certification of Senior Vice President, Chief Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant to Rules 13a-14(a) and 15d-14(a).
*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.
*Filed herewith
Management contract or compensatory plan or arrangement
SIGNATURES
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: April 15, 2009
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
April 15, 2009
/s/ Ronald T. Barnes
Ronald T. Barnes
Senior Vice President, Chief Financial Officer
and Secretary (Principal Financial Officer
and Principal Accounting Officer)
April 15, 2009
/s/ Thomas G. McGonagle
Thomas G. McGonagle
Chairman of the Board of Directors
April 15, 2009
/s/ Robert L. Cabes, Jr.
Robert L. Cabes, Jr.
Director
April 15, 2009
/s/ Jeffrey P. Gunst
Jeffrey P. Gunst
Director
April 15, 2009
/s/ S. P. Johnson, IV
S. P. Johnson, IV
Director
April 15, 2009
/s/ F. Gardner Parker
F. Gardner Parker
Director
April 15, 2009
/s/ Susan C. Schnabel
Susan C. Schnabel
Director
April 15, 2009