Item 1A Risk Factors
Our business involves numerous business and operating risks, many of which have been heightened by the contraction of the financial markets and our economy as a whole. The risks and related factors we consider material to our business are summarized below.
Natural gas and NGL prices are volatile, and continuing weakness in commodity prices could reduce our revenue, liquidity and ability to grow.
Factors Affecting Market Volatility. Our financial performance and prospects depend on the prices we receive for sales of natural gas and NGL, which accounted for 93% of our total production revenues in 2009. Commodity prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Natural gas prices declined sharply since the second half of 2008. While the decline from mid-year 2008 levels has been extreme, natural gas prices have historically been subject to wide fluctuations in response to relatively minor changes in supply and demand, market uncertainty and many other factors beyond the control of producers. These factors are interrelated and include:
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the extent of domestic natural gas and NGL production, which has increased over the last few years from the use of horizontal drilling technologies to accelerate development of shale and other unconventional resource plays;
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the impact of weather and general economic conditions on consumer and industrial demand for natural gas;
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volatile trading patterns in the commodities trading markets;
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the proximity and capacity of pipelines;
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storage levels;
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comparative prices and availability of alternative fuels;
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worldwide supply and demand for oil, natural gas, NGL and liquefied natural gas; and
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federal and state regulatory and conservation programs, including possible climate-related measures for regulating greenhouse gas emissions.
Impact of Commodity Prices on Financial Performance. The volatility of energy markets makes it extremely difficult to predict future natural gas prices. Because we sell our natural gas production under market-sensitive arrangements, we are exposed us to this price volatility. We do not address this risk through financial hedging, but we do use fixed-price, fixed-volume physical delivery contracts that cover a portion of our natural gas production for various terms, up to two years from the contract date. While prices established by our outstanding physical delivery contracts are favorable compared to current spot markets indices, the use of these arrangements in volatile markets could result in future gas sales at fixed prices below prevailing market prices at the time of delivery. Continued weakness in the energy markets or further erosion of natural gas prices would limit our ability to obtain favorable terms for future production under these type of arrangements, potentially reducing our production revenue and cash flow.
Impact of Commodity Prices on Reserve Estimates. Lower natural gas prices not only decrease our revenues on a per unit basis but may also reduce the amount of natural gas that we can produce economically. Our estimated proved reserves as of December 31, 2009 reflect negative revisions of approximately 6.9 Bcfe from the prior year-end estimates as a result of commodity price declines. In addition, our 2009 year-end estimates include proved undeveloped locations that would generate positive future net revenue, based on the constant prices and costs determined under the current reserve rules, but would have negative present value when discounted at 10% per year under the standardized measure. Further deterioration in natural gas prices could require us to make additional downward adjustments to our estimated proved reserves. Under successful efforts accounting rules, this could potentially require impairment charges in future periods if the carrying value of any proved oil and gas property exceeds the expected undiscounted future net cash flows from that acreage based on commodity prices or other economic factors at the time of the impairment review. While any impairment charge would not affect our cash flow from operations, it could reflect our long-term ability to recover an investment based on prevailing conditions and would impact our reported earnings and leverage ratios.
We are leveraged and may be unable to repay or refinance our long-term debt on satisfactory terms.
We have $28.7 million principal amount of amortizing convertible notes due May 1, 2012 and $39.5 million of credit facility borrowings outstanding as of the date of this report, with a borrowing base of $53 million. The borrowing base limits the amount we can have outstanding under our revolving credit facility, as determined semi-annually by the lenders. A recent amendment to the credit agreement provides for borrowing base reductions of $1 million each month from February 2010 until the next semi-annual redetermination scheduled for April 2010. Redeterminations of the borrowing base primarily reflect estimated volumes of our proved developed oil and gas reserves. However, the lenders apply their own price decks, generally at a risk-adjusted discount to prevailing commodity prices, and they may also consider other credit factors and general economic conditions in our industry. Any reduction in our borrowing base below our outstanding indebtedness would require us to repay the excess or provide additional collateral. Our ability to reduce, repay or refinance our debt at maturity will be subject to our future performance and prospects as well as market and general economic conditions beyond our control. There can be no assurance that we will be able to secure the necessary refinancing on satisfactory terms.
Our outstanding convertible notes require monthly principal amortization payments either in cash, which may be unavailable, or in common shares, which may be dilutive to shareholders.
While our note restructuring in January 2010 reduced our outstanding convertible debt by $8.3 million and extended the final maturity of the debt until May 2012, monthly principal amortization requirements on outstanding exchange notes could adversely affect us. Under a credit agreement amendment entered in connection with the note restructuring, we may not receive any upstream dividends from our operating subsidiary for principal installments on the exchange notes if they would cause our revolving debt to exceed 80% of the facility’s borrowing base. In view of scheduled and anticipated reductions in the borrowing base, this could limit our ability to make amortization payments on the notes in cash. To the extent we use common shares for that purpose, they will be valued at the lesser of $2.18 per share or 95% of the 10-day volume-weighted average price of the stock (VWAP) prior to the installment date. In addition, under the true-up provisions of the notes, if the 20-day VWAP following an installment payment in stock differs from the share value applied to that payment, any shortfall will be settled in additional shares. Accordingly, although the exchange notes are intended to provide a flexible repayment structure with the potential for replacing part of the convertible debt with equity at a premium to our stock price at the time of the exchange, the use of common shares to pay all or part of the note installments could be dilutive to shareholders.
The level and terms of our outstanding debt may limit our financial and operating flexibility and performance.
The amount and terms of our debt may adversely affect our business in various ways. Among other adverse consequences, our outstanding indebtedness could:
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limit our ability to take advantage of acquisition and development opportunities or otherwise realize the value of our assets, to the extent that operating cash flow otherwise available for these activities is required to service or repay our debt;
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increase our vulnerability to adverse economic and industry conditions;
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limit our flexibility in planning for developments or reacting to changes in our industry; and
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place us at competitive disadvantage to producers in our operating areas with less debt and greater liquidity.
Challenging economic, business and industry conditions may adversely impact our operating results, liquidity and future prospects.
The economic downturn has required us to modify our business plan and may continue to adversely affect our business and prospects in various ways. The sale of our Appalachian Gathering System during 2009 enabled us to substantially reduce our revolving senior debt but also eliminated our cost savings from ownership of those facilities. Similarly, while we met our 2009 drilling commitments and near-term objectives with a drilling budget limited to internally generated cash flow, this required a return to our established partnership structure for participation in these initiatives, which proportionately reduces our interest in wells with joint ownership. Our ability to continue developing our properties with outside participation from sponsored drilling partnerships could be impaired by any adoption of legislative proposals for eliminating IDC and depletion deductions for federal income tax purposes, which is also included among the deficit reduction measures in the pending fiscal 2011 federal budget proposal released by the White House in February 2010.
Historically, we have relied on the financial markets to provide us with additional capital for property acquisitions and a more aggressive development program than we could fund internally. Adverse conditions have restricted our access to these markets, and continuation of these conditions may increase our cost of capital or our ability to raise capital from the sale of our debt or equity securities. Without greater access to the credit and capital markets, we could be required to sell additional assets or further reduce our drilling expenditures, which could result in the loss of undeveloped acreage from unsatisfied drilling commitments. Deteriorating economic conditions could also affect the collectability of our trade receivables, including production payments from our interests in non-operated wells, and could impair the effectiveness of our physical delivery contracts if counterparties are unable or unwilling to perform their obligations.
Our current proved developed reserves will decline from depletion of our existing wells.
Unless we continue to expand our reserves through the drillbit or acquire additional proved properties, our current proved developed reserves will decline as they are produced. Based on extensive historical production profiles for vertical wells in the Appalachian Basin and the limited production history for horizontal Devonian shale wells in the region, the blended decline rate for our proved developed reserves as of December 31, 2009 averaged 15.7% for 2010, decreasing hyberbolically to 5.5% in 2023. The actual performance of our wells could differ from these estimates, and EURs for our horizontal wells could vary even more materially from their estimated reserves in view of their limited production history. The depletion of our reserves, whether at anticipated rates or otherwise, will reduce cash flow for future growth as well as the assets available to secure financing for the development of our oil and gas properties and replacement of our existing reserves.
Estimates of our proved reserves are based on assumptions that could cause them to be substantially higher or lower than the volume and net present value of natural gas and oil actually recovered.
There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production, as well as the timing and amount of development expenditures and production costs. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be directly measured. The accuracy of any reserve estimate is dependent on the quality of available data and is subject to engineering and geological interpretation and judgment. Results of our drilling and production as well as changes in commodity prices and production costs after the date of our estimates may require future revisions of the estimates. In addition, estimates of our proved undeveloped reserves assume that we will be able to make the necessary capital expenditures, and we may not have the capital or financing we need for their development at the pace or levels assumed in our estimates. As a result, our reserve estimates may differ materially from the quantities of natural gas and oil that are ultimately recovered.
We may be unable to fully develop our oil and gas properties due to general economic conditions or capital constraints.
As of December 31, 2009, approximately 76% of our oil and gas properties were undeveloped. Our ability to develop our properties at the levels and pace anticipated by our business model is uncertain. Developing these properties will require significant capital expenditures for ongoing drilling operations, and we may not have the capital or financing we need for their development. Our costs associated with developing these resources is also uncertain and may increase disproportionately with commodity prices over time. Any of these factors could cause our actual results from future development initiatives on unproved properties to vary significantly from the results anticipated in our business plan.
The timing and costs of implementing our planned drilling schedule are uncertain and may differ materially from our expectations.
Our cash flow, earnings and prospects are highly dependent on our success in efficiently developing and exploiting our current reserves and resources, as well as our ability to find additional recoverable reserves economically. Executing our planned drilling schedule is subject to a number of uncertainties, including our access to capital, seasonal conditions, regulatory approvals and the continued availability of field services and equipment. Drilling activity increased appreciably prior to the third quarter of 2008 in response to higher commodity prices and reported success in regional shale plays, notably the Marcellus play near our operating areas in the Appalachian Basin. The heightened demand for field services contributed to constraints on the availability of skilled labor, equipment, pipeline capacity and other resources in the region. While the steep decline in natural gas prices after July 2008 ultimately reduced drilling activity, drilling costs did not begin to moderate until the first quarter of 2009.
Continued market disruptions may cause delays in drilling operations and the possibility of poor results. Because of these uncertainties, we may be unable to drill and produce our planned drilling locations or alternative prospects on schedule or on budget. Actual results from these initiatives may differ materially from our expectations, which could adversely affect all aspects of our business.
Our operations involve hazards and exposure to liabilities that might not be fully covered by insurance.
Our drilling, production and gas gathering operations involve many operating hazards and a high degree of risk. They include the risk of fire, explosions, blowouts, craterings, pipe or mechanical failure of drilling equipment, casing collapse and environmental hazards such as gas leaks, ruptures and discharges. Any of these hazards could result in personal injury, property and environmental damage, clean-up responsibilities and other regulatory penalties. See “Business and Properties - Regulation.” While we conduct our operations to comply with applicable environmental regulations, permits and lease conditions, including maintenance of insurance against these risks, we remain exposed to liabilities for inadvertent noncompliance, conditions beyond our control and undetected conditions resulting from activities by prior owners or operators of properties in which we own interests. As a result, the operating hazards associated with our development and production activities may result in substantial liabilities, some of which may not be fully covered by our insurance.
Our production volumes may be less than anticipated.
Various field operating conditions may adversely our production volumes. These conditions include potential delays in obtaining regulatory approvals and easements for connecting completed wells to existing gathering facilities and the risk that production from connected wells could be interrupted, or shut in, from time to time for various reasons, including weather conditions, accidents, loss of pipeline access, mechanical conditions, field labor issues or intentionally as a result of market conditions. While close well monitoring and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Moreover, due to the short production history for horizontal shale wells in our operating areas and similar regional plays, the timing and extent of production declines for our horizontal wells cannot be predicted with any certainty.
We depend on key personnel for decision making and industry contacts.
We are dependent on the continued contributions of our executives and key personnel for the decision making and industry contacts necessary to manage and maintain growth within our highly competitive industry. There are a limited number of people with this level of knowledge and experience in our operating areas, and competition for qualified personnel can be intense. While we have retention agreements with our senior management or other key personnel, the loss of their services for any reason could have a material adverse effect on our business and prospects.
We have never paid dividends on our common stock and do not anticipate any change in that policy.
We have never paid cash dividends on our common stock. Our current policy is to retain future earnings to finance the acquisition and development of additional oil and gas reserves. Any future determination about the payment of dividends will be made at the discretion of our board of directors and will depend upon our operating results, financial condition, capital requirements, restrictions in debt instruments, general business conditions and other factors the board of directors deems relevant. If we issue any preferred stock, it will be eligible for dividends prior and in preference to our common stock, when and if declared by the board of directors.
Market prices for our common stock are volatile.
The market price of our common stock is subject to significant volatility in response to variations in our operating and financial results, perceptions about our future prospects and other factors. Sales of substantial amounts of our common stock can also affect its market price. There were 33,521,512 shares of our common stock issued and outstanding at March 10, 2010. As of that date, we also had outstanding exchange notes that are convertible at the option of their holders for a total of 13,165,137 common shares, as well as outstanding stock options and warrants exercisable for an additional 5,998,706 shares of our common stock. All of these underlying shares are eligible for public resale without restrictions. Sales of substantial amounts of our common stock in the public market, or the perception that substantial sales may occur, could adversely affect prevailing market prices of the common stock.
Failure to stay in compliance with Nasdaq listing requirements would adversely affect the market price and liquidity of our common stock.
To remain eligible for trading on the Nasdaq Global Select Market, we must meet various requirements, including corporate governance standards, specified shareholders’ equity and a minimum bid price for our common stock above $1.00 per share. Although the market price and related market value requirements for continued listing afford a grace period to regain compliance, it is currently limited to 180 days. If our common stock were to be delisted, liquidity in the stock would be impaired. Any delisting of our common stock would also trigger an event of default that would entitle holders of our outstanding convertible notes to require us to redeem the notes at a default rate equal to 125% of their face amount.
Our undeveloped gold and silver properties may never be profitable or monetized.
We have gold and silver properties in Alaska that are undeveloped, dormant and unprofitable. To retain our interests in the properties, we must expend funds each year to maintain the underlying mineral rights. We have no plans to develop these properties independently and instead monetize our interests in these properties through a joint venture arrangement or sale. are seeking either a joint venture partner to provide funds for additional exploration of the prospects or a buyer for the properties. Our ability to find a strategic partner or buyer will depend on the anticipated profitability of potential production activities as well as the price of gold and silver, which in turn is affected by factors such as inflation, interest rates, currency rates, geopolitical and other factors beyond our control. We have not derived any revenues from our gold and silver properties and may never be able to realize any production revenues or sale proceeds from the properties.
Item 1B
Item 1B Unresolved Staff Comments
None.
Item 3
Item 3 Legal Proceedings
We are involved in several legal proceedings incidental to our business, none of which is considered to be material to our consolidated financial position, results of operations or liquidity.
Item 4
Item 4 Submission of Matters to a Vote of Security Holders
No proposals were submitted for approval by our shareholders during the fourth quarter of 2009.
Part II
Item 5
Item 5 Market for Common Stock and Related Security Holder Matters
Trading Market
Our common stock has traded on the Nasdaq Global Select Market under the symbol NGAS. The following table shows the range of high and low bid prices for our common stock during the periods indicated, together with the average daily trading volume, as reported by Nasdaq. These quotations represent inter-dealer prices, without mark-ups or commissions, and they may not necessarily correspond to actual sales prices.
Security Holders
As of March 5, 2010, there were 609 holders of record of our common stock. We estimate there were approximately 7,500 beneficial owners of our common stock as of that date.
Dividend Policy
We have never paid cash dividends on our common stock. Our current policy is to retain any future earnings to finance the acquisition and development of additional oil and gas reserves. Any future determination about the payment of dividends will be made at the discretion of our board of directors and will depend on our operating results, financial condition, capital requirements, restrictions in debt instruments, general business conditions and other factors the board of directors deems relevant.
Common Shares Issuable under Equity Compensation Plans
The following table shows the amount of our common stock issuable as of December 31, 2009 under our equity compensation plans, which are defined to include stock award and option plans, individual compensation arrangements and obligations under warrants or options issued in financing transactions and property acquisitions.
Performance Graph
The following graph presents a comparison of annual percentage changes in the cumulative total return on our common stock over the last five years with the total return on the Dow Jones U.S. Exploration and Production Index and the S&P 500 over the same period, assuming the investment of $100 in our common stock and each index, with reinvestment of any dividends. The performance graph is being furnished, not filed, for purposes of the Exchange Act and is not incorporated by reference in any registration statement under the Securities Act of 1933.
Item 6
Item 6 Selected Financial Data
Our consolidated financial statements included in this report have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). All of our oil and gas operations are conducted within the continental United States, and all amounts reported in the consolidated financial statements are in U.S. dollars. We are organized at the parent company level under the laws of British Columbia, and we prepared our consolidated financial statements prior to 2006 in accordance with accounting principles generally accepted in Canada (Canadian GAAP). Our adoption of U.S. GAAP did not have a material effect on our reported financial condition or results for prior periods and did not require us to restate any previously issued financial statements, which included reconciliations between items with different treatment under Canadian and U.S. GAAP.
The following table presents our summary selected consolidated financial data as of and for each of the five years ended December 31, 2009. The financial data is derived from our audited consolidated financial statements, which have been audited by Hall, Kistler & Company LLP, beginning in 2006, under U.S. GAAP and by Kraft Berger LLP for prior years under Canadian GAAP. The summary selected consolidated financial data as of December 31, 2009 and 2008 and for the three years ended December 31, 2009 should be read in conjunction with our consolidated financial statements and related notes included at the end of this report, as well as the discussion following the table, which presents management’s analysis of events, factors and trends with an important effect or prospective impact on our financial condition, results of operations and cash flows.
(In thousands, except per share data)
Item 7
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an independent exploration and production company focused on natural gas shale plays in the Appalachian and Illinois Basins. We also operate the gas gathering facilities for our core properties, providing deliverability directly from the wellhead to interstate pipelines serving major east coast natural gas markets. We develop many of our prospects with participation from sponsored drilling partnerships, maintaining combined interests as both general partner and an investor ranging from 12.5% to 75%, along with additional reversionary interests after specified distribution thresholds are reached. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation.
Results of Operations - 2009 and 2008
Revenues. The following table shows the components of our revenues for 2009 and 2008, together with their percentages of total revenue in 2009 and percentage change on a year-over-year basis.
Our total revenues for 2009 reflect the impact of declining commodity prices, reduced drilling activity and the third-quarter sale of our Appalachian Gathering System, which also eliminated our cost savings from ownership of these facilities. In view of our current business model for maintaining capital expenditures in line with operating cash flows, we do not expect this trend to reverse without a significant recovery in commodity prices or increased participation by sponsored partnerships in our drilling activities.
Contract drilling revenues reflect the size and timing of our drilling partnership initiatives. Although we receive the proceeds from private placements in sponsored partnerships as prepayments under our drilling contracts, revenues from the interests of outside investors are recognized on the completed contract method as the wells are drilled, rather than when funds are received. Our contract drilling revenues in 2009 reflect the challenging economic environment, which contributed to a 44% reduction in the size of our 2009 drilling partnership compared to the prior year’s program. With a raise of $19.25 million, the partnership is participating in 22 horizontal wells, of which four wells are being drilled during the 2010 first quarter.
Production revenues for 2009 reflect year-over-year declines of 31% in natural gas prices, 45% in oil prices and 48% for sales of natural gas liquids. The impact of weak commodity prices was partially offset by an increase of 6% in production output to 3,978 Mmcfe, compared to 3,745 Mmcfe in the prior year. Our volumetric growth reflects our transition to horizontal drilling throughout our operated properties in 2009. During the year, approximately 55% of our natural gas production was sold under fixed-price physical delivery contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in 2009 averaged $7.24 per Mcf for our Appalachian production and $6.17 per Mcf overall, compared to an average overall realization of $8.89 per Mcf in 2008.
The contraction of gas transmission, compression and processing revenues was driven by our sale of the Appalachian Gathering System in the third quarter of 2009. See “Business and Properties - Recent Developments.” Following the sale, our gas transmission, compression and processing revenues were limited primarily to fees for moving third-party production through our retained gas gathering facilities, gas utility sales and our share of third-party fees for liquids extraction through our Rogersville plant, which we continue to co-own with Seminole Energy.
Expenses. The following table shows the components of our direct and other expenses for 2009 and 2008. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.
Contract drilling expenses reflect the level and timing of drilling initiatives conducted through our sponsored partnerships. These expenses represented 75% of contract drilling revenues in 2009, compared to 77% in the prior year. Margins for contract drilling operations reflect our cost-plus pricing model, which we adopted in 2006 to address price volatility for drilling services, equipment and steel casing requirements.
Production expenses represent lifting costs, field operating and maintenance expenses, related overhead, severance and other production taxes, third-party transportation fees and processing costs. Historically, our ownership of the Appalachian Gathering System eliminated transportation costs for our share of Leatherwood, Straight Creek, Fonde and Stone Mountain production delivered through the system. The increase in production expenses year-over-year primarily reflects higher transportation costs following our sale of the Appalachian Gathering System in the third quarter of 2009.
Our gas transmission and compression expenses, as well as capitalized costs for this part of our business, were substantially reduced following our sale of the Appalachian Gathering System. Our remaining infrastructure position is comprised of 100% interests in the gas gathering facilities for our Haley’s Mill and Kay Jay fields, 50% interests in our Haley’s Mill and Rogersville processing plants and a 25% interest in the gathering system for our non-operated Arkoma properties. Our gas transmission, compression and processing expenses in future periods will reflect this reduction in our infrastructure asset base.
Selling, general and administrative (SG&A) expenses are comprised primarily of selling and promotional costs for our sponsored drilling partnerships and general overhead costs. Our SG&A expenses decreased by 17% year-over-year, primarily from the decline in 2009 partnership sales. As a percentage of revenues, SG&A expenses increased from 17% in 2008 to 20% in 2009.
Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options. Under this method, employee stock options are valued at the grant date using the Black-Scholes valuation model, and the compensation cost is recognized ratably over the vesting period. We also recognized an accrual of $614,548 for deferred compensation cost in 2009.
Depreciation, depletion and amortization (DD&A) is recognized under the units-of-production method, based on the estimated proved developed reserves of the underlying oil and gas properties, and on a straight-line basis over the useful life of other property and equipment. The 13% increase in DD&A charges reflects additions to our oil and gas properties from drilling initiatives, partially offset by a reduction in historical depletion costs for the Appalachian Gathering System following its sale in the third quarter of 2009.
Cash interest expense in 2009 decreased 8% year-over-year, reflecting the reduction of debt levels under our revolving credit facility from proceeds of our infrastructure monetization and equity raise in the third quarter of 2009. Non-cash interest expense of $3,925,531 reflects the application of the effective interest method for accretion of the debt discount for the embedded conversion feature of our 6% notes, which had a face amount of $37 million prior to the restructuring of our convertible debt in January 2010. See “Liquidity and Capital Resources.” The carrying amount of the exchange notes issued in the restructuring will be reduced by the initial fair values of the equity components of the exchange transaction. The resulting debt discount will be amortized to interest expense though the conversion or repayment dates of exchange notes and the expiration or exercise dates of the warrants.
We recognized pre-tax gains totaling $3,346,491 during 2009, primarily from our sale of the Appalachian Gathering System. We acquired the open-access portion of the system from Duke Energy in March 2006 for $18 million and built out the field-wide infrastructure at historical costs totaling approximately $33.5 million.
Deferred income tax expense recognized in both reporting periods represents future tax liabilities at the operating company level. Although we generally have no current tax liability at that level due to the utilization of deductions primarily for intangible drilling costs and percentage depletion, our consolidated income tax expense is negatively impacted by the non-recognition of tax benefits at the parent company level. For 2009, we had an income tax benefit of $341,394 from our operating loss.
Other expenses in 2009 totaled $845,560, net of minor income items. The recorded expenses include payments and accruals totaling $642,000 for various guaranteed obligations of a Virginia steam company in which we previously held a 50% interest. We have also accrued $350,000 for the unreimbursed part of a personal injury litigation settlement reached in March 2010, which we will seek to recoup under our umbrella liability insurance coverage.
Net Income (Loss) and EPS. We recognized a net loss of $7,701,161 in 2009, reflecting the foregoing factors. Earnings (loss) per share (EPS) was $(0.27) on 28,256,253 weighted average common shares outstanding, compared to net income of $2,936,275 realized in 2008, with EPS of $0.11 on 26,910,642 fully diluted shares.
Results of Operations - 2008 and 2007
Revenues. The following table shows the components of our revenues for 2008 and 2007, together with their percentages of total revenue in 2008 and percentage change on a year-over-year basis.
Contract drilling revenues reflect the application of prepayments by outside investors under our drilling contracts with sponsored partnerships, which we recognize under the completed contract method as the wells are drilled. During 2008, we sponsored a program for participation in 89 wells on non-operated properties known as the HRE fields, spanning six counties in West Virginia and Virginia. Our contract drilling revenues in 2008 reflect ongoing operations for that program and the completion of our 2007 HRE program. Outside investors have interests of 75% before payout and 60% after payout in both of those programs.
The growth in our production revenues for 2008 reflects a 13% increase in production output to 3,745 Mmcfe, compared to 3,311 Mmcfe in 2007. Our volumetric growth was driven by added production from wells brought on line during 2008, including substantial contributions from our horizontal drilling initiatives. Approximately 50% of our natural gas production in 2008 was sold under fixed-price contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in 2008 averaged $9.59 per Mcf for our Appalachian production and $8.89 per Mcf overall, compared to an average overall realization of $8.19 per Mcf in 2007.
Gas transmission, compression and processing revenues for 2008 were driven by gas gathering and compression fees totaling $6,966,115 for moving third-party production through the Appalachian Gathering System and $746,970 in related processing fees for liquids extraction through our Rogersville plant. We also had contributions of $565,727 from gas utility sales and $458,154 from our 25% interest in the gathering system that services a non-operated coalbed methane project in the Arkoma Basin.
Expenses. The following table shows the components of our direct and other expenses for 2008 and 2007. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.
Contract drilling expenses increased 2% year-over-year basis and represented 77% of contract drilling revenues, compared to 78% in 2007. All of our contract drilling activities in 2008 were conducted on non-operated HRE properties in West Virginia and Virginia. Margins for contract drilling operations reflect our cost-plus pricing model, which we adopted in 2006 to address price volatility for drilling services, equipment and steel casing requirements.
The increase in production expenses in 2008 primarily reflects our volumetric growth and higher severance and production taxes, as well as $2,282,841 in hauling costs for natural gas liquids, which we began stripping from our Appalachian production through our Rogersville plant during the first quarter of the year. As a percentage of oil and gas production revenues, our production expenses were 33%, compared to 27% in 2007, primarily reflecting start-up costs for bringing our Rogersville processing plant and our Fonde and Haley’s Mill gathering systems on line, as well as added transportation fees for extracted natural gas liquids.
Gas transmission, compression and processing expenses in 2008 were 40% of associated revenues, compared to 47% in the prior year. The margins for this part of our business benefited from third-party fees generated by the Appalachian Gathering System. Our gas transmission, compression and processing expenses do not include capitalized costs of approximately $10.1 million during 2008 for extensions of our field-wide gas gathering systems and additions to compression capacity required to bring new wells on line.
SG&A expenses in 2008 increased by 8% from the prior year, primarily reflecting sales costs for a drilling partnership launched in April 2008 for participation in our non-operated initiatives in West Virginia and Virginia, along with overhead costs for supporting our expanded operations as a whole. As a percentage of revenues, SG&A expenses decreased from 18% in 2007 to 17% in 2008.
Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options. We also recognized an accrual of $286,419 in 2008 for deferred compensation costs.
The increase in DD&A charges in 2008 reflects substantial additions to our oil and gas properties, gas gathering systems and related equipment.
We recognized bad debt expenses aggregating $749,035 in 2008 for write-offs of receivables from a regional refinery for sales prior to its bankruptcy filing, a separate non-performing loan to a regional operator on a three-well project in Texas and unreimbursed trade debt we paid on behalf of a Virginia steam company in which we previously held a 50% interest. See “Critical Accounting Policies and Estimates - Allowance for Doubtful Accounts.”
Interest expense for 2008 decreased from lower variable rates under our revolving credit facility. Draws under the credit facility were used primarily to support our ongoing drilling initiatives and enhancements of our field-wide gas gathering systems.
Deferred income tax expense recognized in both reported periods represents future tax liability at the operating company level. Although we have no current tax liability due to the utilization of intangible drilling costs, our consolidated income tax expense is negatively impacted by the non-recognition of tax benefits at the parent company level.
Net Income and EPS. We realized net income of $2,936,275 in 2008, compared to a net loss of $816,597 recognized in 2007, reflecting the foregoing factors. EPS was $0.11 based on 26,409,275 weighted average basic common shares outstanding in 2008, compared to EPS of $(0.04) in 2007 based on 22,240,429 weighted average common shares outstanding.
Liquidity and Capital Resources
Liquidity. We completed a registered direct placement of 3.48 million units at $1.90 per unit on August 13, 2009, with net proceeds of approximately $6.1 million applied to debt reduction under our revolving credit facility. Each unit consisted of one share of our common stock and a warrant to buy 0.5 common share. The warrants are exercisable for a total of 1.74 million shares of our common stock at $2.35 per share, subject to adjustment for certain dilutive issuances, during a four-year term expiring in February 2014.
During 2009, we generated net cash of $6,180,241 from operating activities and $22,755,628 from investing activities, which included our proceeds from the Appalachian Gathering System sale, all of which were applied to debt reduction under our revolving credit facility. Our investing activities also included capital expenditures aggregating $14,776,307, of which $11,914,566 was recorded as net additions to oil and gas properties. As a result of these activities, net cash increased to $4,332,650 at December 31, 2009 from $981,899 at the prior year-end.
Operating activities in 2008 provided net cash of $26,733,185. During the year, we used $56,875,544 in investing activities, most of which were capital expenditures for additions to our oil and gas properties and gathering systems. These investments were funded in part with net cash of $28,307,580 from financing activities, primarily consisting of advances under our revolving credit facility. As a result of these activities, net cash decreased from $2,816,678 at the end of 2007 to $981,899 at December 31, 2008.
Our working capital generally reflects wide fluctuations from the timing of customer deposits and expenditures under drilling contracts with our sponsored partnerships and from draws and payments under our credit facility. Since these fluctuations are normalized over relatively short time periods, we do not consider working capital to be a reliable measure of our liquidity. In addition, based on the December 2010 maturity of our 6% convertible notes, their entire carrying amount was reclassified as a current liability at December 31, 2009. This comprised most of the working capital deficit at year end, which was eliminated in January 2010 from the restructuring of our convertible debt.
Capital Resources. Our business involves significant capital requirements. The rate of production from oil and gas properties declines as reserves are depleted. Without successful development activities, our proved reserves would decline as oil and gas is produced from our proved developed reserves. We also have substantial annual drilling commitments under various leases and farmouts for our Appalachian properties, including an annual 25-well commitment for our Leatherwood field. Our long-term performance and profitability is dependent not only on meeting these commitments and recovering existing oil and gas reserves, but also on our ability to find or acquire additional reserves and fund their development on terms that are economically and operationally advantageous.
Historically, we have relied on a combination of cash flows from operations, bank borrowings and private placements of our convertible notes and equity securities to fund our reserve and infrastructure development and acquisition activities. We also relied on participation in our drilling initiatives by outside investors in our sponsored partnerships. For 2008, we changed our business model to accelerate organic growth by retaining all of our available working interest in wells drilled on operated properties, limiting our use of drilling partnerships to non-operated initiatives. While we are committed to continue expanding our reserves and production through the drillbit, we have addressed the challenging conditions in our industry during the last two years by monetizing the Appalachian Gathering System, restructuring our convertible debt, reducing our capital expenditures and returning to our successful partnership structure for sharing development costs on operated properties.
We raised $19.25 million last year for our 2009 drilling partnership. This enabled us to meet our near-term commitments and objectives with a reduced drilling budget of $12 million, reflecting a 75% reduction from our 2008 capital expenditures allocated to drilling. We have a 20% interest before payout and a 35% interest after payout in our 2009 program, which is participating in 22 horizontal wells. We plan to retain this strategy for participation by our 2010 drilling partnership in up to 57 horizontal wells on our core properties, while continuing to maintain capital expenditures in line with our anticipated cash flow from operations. With our critical infrastructure in place to provide deliverability with strong market access for our production, this will allow us to continue delivering organic growth, although at lower rates than we could achieve by retaining more of our available working interest in new wells. If market conditions improve, we would expect to raise additional capital to advance our long-term resource development objectives.
In January 2010, we retired $37 million of our 6% convertible notes due December 15, 2010 (retired notes) in exchange for an aggregate of $28.7 million in new amortizing convertible notes due May 1, 2012 (exchange notes), together with 3,037,151 shares of our common stock, five-year warrants to purchase 1,285,038 common shares (exchange warrants) and cash payments totaling approximately $2.7 million. The exchange notes bear interest at 6% per annum, payable in cash at the beginning of each calendar quarter. They are convertible at the option of the holders into our common stock at $2.18 per share, and the exchange warrants are exercisable at $2.37 per share, subject in each case to certain volume limitations and adjustments for certain fundamental change transactions or share recapitalizations. Under certain conditions, we may call the exchange notes for redemption to force their conversion.
During the period from June 1, 2010 through the maturity date, we will be obligated to make 24 equal monthly principal amortization payments on outstanding exchange notes. Subject to certain volume limitations, true-up adjustments and other conditions, we may elect to pay all or part of each principal installment in common stock, valued at the lesser of $2.18 per share or 95% of the 10-day VWAP prior to the installment date. Each holder may elect to defer any installment payment to maturity. Holders also have the right to require us to redeem their exchange notes in cash upon any event of default at 125% of their principal amount or upon a change of control at 110% of their principal amount. Any exchange notes that are neither repaid, redeemed nor converted will be repayable at maturity in cash plus accrued and unpaid interest.
We have a senior secured revolving credit facility maintained by our operating subsidiaries with KeyBank National Association, as agent and primary lender. The facility provides for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a scheduled maturity in September 2011. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from the agent’s prime rate to 1.0% above that rate, depending on the amount of borrowing base utilization. We are also responsible for commitment fees at rates ranging from 0.375% to 0.5% of the unused borrowing base. The facility is guaranteed by NGAS and is secured by liens on our oil and gas properties. Outstanding borrowings under the facility aggregated $38.5 million at December 31, 2009, with a borrowing base of $55 million and a 5% interest rate. We are in compliance with our financial and other covenants under the credit agreement covering the facility.
In January 2010, we entered into an amendment to the credit agreement that permitted us to consummate the exchange transaction for our convertible debt, subject to certain non-financial covenants and borrowing base modifications. These include restrictions on upstream dividends from our operating subsidiary for any principal amortization payments on the exchange notes that would cause outstanding borrowings under the facility to exceed 80% of the prevailing borrowing base. The amendment also provides for monthly reductions of $1 million to the borrowing base from February 2010 until the next semi-annual redetermination scheduled for April 2010, resulting in a borrowing base of $53 million as of the date of this report. Under the terms of the amendment, the borrowing base will be further reduced by $2.7 million, representing an upstream dividend we used for repurchasing retired notes in the exchange transaction, unless recontributed for debt reduction under the credit facility by June 1, 2010.
Our ability to service and repay our revolving and convertible debt will be subject to our future performance and prospects as well as market and general economic conditions. Our future revenues, profitability and rate of growth will continue to be substantially dependent on the market price for natural gas. Future commodity prices will also have a significant impact on our ability to maintain or increase our borrowing capacity, obtain additional capital on acceptable terms and attract drilling partnership capital. While we have been able to mitigate some of the steep decline in natural gas prices with fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production, we are exposed to price volatility for future production not covered by these arrangements. See “Risk Factors” and “Quantitative and Qualitative Disclosures about Market Risk.”
We have addressed the economic downturn and challenging conditions in our industry by monetizing most of our gas gathering infrastructure, deleveraging and modifying our business model to reduce our reliance on the financial and capital markets. To realize our long-term goals for growth in revenues and reserves, however, we will continue to dependent on those sources of capital or other financing alternatives. Any prolonged constriction in the capital markets or protracted weakness in domestic energy markets could require us to sell additional assets or pursue other financing or strategic arrangements to meet those objectives and to repay or refinance our long-term debt at maturity.
Forward Looking Statements
Some statements made by us in this report are prospective and constitute forward-looking statements within the meaning of Section 21E of the Exchange Act and Section 27A of the Securities Act of 1933. Other than statements of historical fact, all statements that address future activities, outcomes and other matters we plan, expect, budget, intend or estimate, and other similar expressions, are forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which are beyond our control. Among other things, these include:
•
uncertainty about estimates of future natural gas production and required capital expenditures;
•
commodity price volatility;
•
increases in the cost of drilling, completion, gas gathering and processing or other costs of developing and producing our reserves;
•
unavailability of drilling rigs and services;
•
drilling, operational and environmental risks; and
•
uncertainties about future federal and state regulatory, conservation and tax measures.
If the assumptions we use in making forward-looking statements prove incorrect or the risks described in this report occur, our actual results could differ materially from future results expressed or implied by the forward-looking statements. See “Risk Factors.”
Financial Market Risk
Interest Rate Risk. Borrowings under our secured credit facility bear interest at fluctuating market-based rates. Accordingly, we are exposed to interest rate risk on current and future indebtedness under the facility.
Foreign Market Risk. We conduct operations solely in the United States. As a result, our financial results are unlikely to be affected by factors such as changes in foreign currency exchange rates or weak economic conditions in foreign markets, except to the extent that global demand may affect domestic energy markets.
Contractual Obligations and Commercial Commitments
General. Our contractual obligations include long-term debt, operating leases, drilling commitments, transportation commitments, asset retirement obligations and leases for office facilities and various types of equipment. The following summarizes our contractual financial obligations at December 31, 2009 and their future maturities. The table does not include commitments under our gas gathering and sales agreements described below.
Gas Gathering and Sales Commitments. We have various commitments under our gas gathering and sales agreements entered with Seminole and Seminole Energy in connection with our sale of the Appalachian Gathering System during the third quarter of 2009. See “Business and Properties - Recent Developments.” These agreements provide us with firm capacity rights for daily delivery of 30,000 Mcf of controlled gas and have an initial term of fifteen years with extension rights. Our commitments under these agreements include:
•
Monthly capital fees in amounts intended to yield a 20% internal rate of return for all capital expenditures on the Appalachian Gathering System by Seminole Energy.
Related Party Transactions
Because we operate through subsidiaries and managed drilling partnerships, our corporate structure causes various agreements and transactions in the normal course of business to be treated as related party transactions. Our policy to structure any transactions with related parties only on terms that are no less favorable to NGAS than could be obtained on an arm’s length basis from unrelated parties. Significant related party transactions are summarized in Notes 6 and 15 to the consolidated financial statements included in this report.
Critical Accounting Policies and Estimates
General. The preparation of financial statements requires management to utilize estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. These estimates are based on historical experience and on various other assumptions that management believes to be reasonable under the circumstances. The estimates are evaluated by management on an ongoing basis, and the results of these evaluations form a basis for making decisions about the carrying value of assets and liabilities that are not readily apparent from other sources. Although actual results may differ from these estimates under different assumptions or conditions, management believes that the estimates used in the preparation of our financial statements are reasonable. The critical accounting policies affecting our financial reporting are summarized in Note 1 to the consolidated financial statements included in this report. Policies involving the most significant judgments and estimates are summarized below.
Estimates of Proved Reserves and Future Net Cash Flows. Estimates of our proved oil and gas reserves and related future net cash flows are used in impairment tests of goodwill and other long-lived assets. These estimates are prepared as of year-end by independent petroleum engineers and are updated internally at mid-year. There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of any reserve estimate is dependent on the quality of available data and is subject to engineering and geological interpretation and judgment. Results of our drilling, testing and production after the date of these estimates may require future revisions, and actual results could differ materially from the estimates.
Impairment of Long-Lived Assets. Our long-lived assets include property, equipment and goodwill. Long-lived assets with an indefinite life are reviewed at least annually for impairment, and all long-lived assets are reviewed whenever events or changes in circumstances indicate that their carrying values may not be recoverable. During 2007, we recognized an impartment charge of $964,000 for exploratory well costs that had been capitalized for less than one year pending our assessment of reserves for the project.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts when deemed appropriate to reflect losses that could result from failures by customers or other parties to make payments on our trade receivables. The estimates of this allowance, when maintained, are based on a number of factors, including historical experience, aging of the trade accounts receivable, specific information obtained on the financial condition of customers and specific agreements or negotiated settlements.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet debt or other unrecorded obligations with unconsolidated entities to enhance our liquidity, provide capital resources or for any other purpose.
Item 7A
Item 7A Quantitative and Qualitative Disclosures about Market Risk
Our major market risk exposure is the pricing of natural gas production, which has been highly volatile and unpredictable during the last several years. While we do not use financial hedging instruments to manage these risks, we do use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production at specified prices during varying periods of time up to two years from the contract date. Because these physical delivery contracts qualify for the normal purchase and sale exception under derivative fair value accounting standards, they are not treated as financial hedging activities and are not subject to mark-to-market accounting. The financial impact of physical delivery contracts is included in our oil and gas revenues at the time of settlement, which in turn affects our average realized natural gas prices. See “Business and Properties - Producing Activities.”
Item 8
Item 8 Financial Statements and Supplementary Data
Item 9
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A
Item 9A Controls and Procedures
Management’s Responsibility for Financial Statements
Our management is responsible for the integrity and objectivity of all information presented in this report. The consolidated financial statements included in this report have been prepared in accordance with U.S. GAAP and reflect management’s judgments and estimates on the effect of the reported events and transactions.
Disclosure Controls and Procedures
Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this report. Based on management’s evaluation as of December 31, 2009, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures are effective to ensure that material information about our business and operations is recorded, processed, summarized and publicly reported within the time periods required under the Exchange Act, and that this information is accumulated and communicated to our management to allow timely decisions about required disclosures.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008 using the criteria established under Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on those criteria, management concluded that our internal control over financial reporting was effective as of December 31, 2009. Management reviewed the results of their assessment with the audit committee of our board of directors. The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Hall, Kistler & Company LLP, our independent registered public accounting firm, as stated in their report appearing on page of this report.
Changes in Internal Control over Financial Reporting
We regularly review our system of internal control over financial reporting to ensure the maintenance of an effective internal control environment. There were no changes in our internal control over financial reporting during the period covered by this report that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Item 9B
Item 9B Other Information
None.
Part III
Item 10
Item 10 Directors, Executive Officers and Corporate Governance
Executive Officers
Our executive officers are listed in the following table, together with their age and term of service with the Company.
A summary of the business experience and background of our executive officers is set forth below.
William S. Daugherty has served as our President, Chief Executive Officer and member of our board of directors since September 1993, as well as our Chairman of the Board since 1995. He has also served as the Chairman of the Board of NGAS Production Co., our operating subsidiary (NGAS Production), since 1984. Mr. Daugherty currently serves as the Governor of Kentucky’s Official Representative to the Interstate Oil and Gas Compact Commission and as a member of the Board of Directors of the Independent Petroleum Association of America. He also serves on the Unconventional Resources Technology Advisory Committee. He is a past president of both the Kentucky Oil and Gas Association (KOGA) and the Kentucky Independent Petroleum Producers Association. Mr. Daugherty holds a B.S. Degree from Berea College, Berea, Kentucky.
William G. Barr III has served as a Vice President of NGAS since 2004 and as Chief Executive Officer of NGAS Production since September 2005, having served as a Vice President of NGAS Production from 1993 until being appointed its CEO. Mr. Barr has more than 30 years of experience in the corporate and legal sectors of the oil and gas industry. Before joining NGAS Production, he served in senior management positions with several oil and gas exploration and production companies and built a significant natural resource law practice. Mr. Barr currently serves as Governing Member Trustee for the Energy & Mineral Law Foundation. He also serves as President of KOGA and as a member of its Board of Directors, as well as Vice Chairman of the Kentucky Gas Pipeline Authority. He received a Juris Doctorate from the University of Kentucky, Lexington, Kentucky.
D. Michael Wallen has served as a Vice President of NGAS since 1997 and as a Vice President of NGAS Production between 1995 and September 2005, when he was appointed as its President. For six years before joining NGAS Production, he served as the Director of the Kentucky Division of Oil and Gas. He has more than 25 years of experience as a drilling and completion engineer for various exploration and production companies. Mr. Wallen recently served as President of KOGA and currently serves as a member of its Board of Directors and Executive Committee. He has also served as President of the Eastern Kentucky Section of the Society of Petroleum Engineers and as the Governor’s Representative to the Interstate Oil & Gas Compact Commission. Mr. Wallen holds a B.S. Degree in Physics from Morehead State University, Morehead, Kentucky.
Michael P. Windisch has served as Chief Financial Officer of NGAS and NGAS Production since 2002. Prior to that time, he was employed by PricewaterhouseCoopers LLP, participating for five years in the firm’s audit practice. He was recently named Regional Financial Executive of the Year by the Institute of Management Accountants and Robert Half International. Mr. Windisch is a member of the American Institute of Certified Public Accountants and holds a B.S. Degree from Miami University, Oxford, Ohio, where he serves on the Advisory Board of the Department of Finance.
Incorporation of Part III Information by Reference
The balance of Part III to this report is incorporated by reference to the proxy statement for our 2010 annual meeting of shareholders to be filed with the Securities and Exchange Commission before the end of April 2010.
Part IV
Item 15
Item 15 Exhibits, Financial Statement Schedules
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, NGAS Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 11, 2010.
NGAS Resources, Inc.
By:
/s/ William S. Daugherty
By:
/s/ Michael P. Windisch
William S. Daugherty,
Michael P. Windisch,
President and Chief Executive Officer
Chief Financial Officer
(Principal executive officer)
(Principal financial and accounting officer)
In accordance with the Exchange Act, this report has been signed as of the date set forth below by the following persons in their capacity as directors of the NGAS Resources, Inc.
By:
/s/ William S. Daugherty
March 11, 2010
William S. Daugherty,
Individually and *as attorney-in-fact
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of NGAS Resources, Inc. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process defined 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. They include policies and procedures that:
•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the Company;
•
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
•
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. Also, 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. The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management has concluded that, as of December 31, 2008, the Company’s internal control over financial reporting is effective based on those criteria.
The Company’s independent registered public accounting firm, Hall, Kistler & Company LLP, has audited the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, as stated in their report appearing on page.
/s/ William S. Daugherty
/s/ Michael P. Windisch
William S. Daugherty,
Michael P. Windisch,
President and Chief Executive Officer
Chief Financial Officer
March 11, 2010
March 11, 2010
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of NGAS Resources, Inc. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process defined 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. They include policies and procedures that:
•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the Company;
•
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
•
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. Also, 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. The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management has concluded that, as of December 31, 2008, the Company’s internal control over financial reporting is effective based on those criteria.
The Company’s independent registered public accounting firm, Hall, Kistler & Company LLP, has audited the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, as stated in their report appearing on page.
/s/ William S. Daugherty
/s/ Michael P. Windisch
William S. Daugherty,
Michael P. Windisch,
President and Chief Executive Officer
Chief Financial Officer
March 11, 2010
March 11, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
NGAS RESOURCES, INC.
We have audited NGAS Resources, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NGAS Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the 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 effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. 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 (3) 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. Also, 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 our opinion, NGAS Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and the related statements of operations, shareholders’ equity and cash flows of NGAS Resources, Inc., and our report dated March 9, 2010 expressed an unqualified opinion.
Canton, Ohio
March 9, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
NGAS RESOURCES, INC.
We have audited the accompanying consolidated balance sheets of NGAS Resources, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years ended December 31, 2009. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe 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 consolidated financial position of NGAS Resources, Inc. and subsidiaries as of December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), NGAS Resources, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 9, 2010 expressed an unqualified opinion thereon.
Canton, Ohio
March 9, 2010
NGAS Resources, Inc.
CONSOLIDATED BALANCE SHEETS
See accompanying notes.
NGAS Resources, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes.
NGAS Resources, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
See accompanying notes.
NGAS Resources, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes.
NGAS Resources, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
General. The accompanying consolidated financial statements of NGAS Resources, Inc. (NGAS) for each of the three years ended December 31, 2009 have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Although NGAS is organized under the laws of British Columbia, all of our oil and gas operations are conducted within the continental United States, and all amounts reported in the consolidated financial statements are stated in U.S. dollars.
Basis of Consolidation. The consolidated financial statements include the accounts of our direct and indirect wholly owned subsidiaries, NGAS Production Co. (NGAS Production), Sentra Corporation (Sentra) and NGAS Securities, Inc. (NGAS Securities). NGAS Production (formerly named Daugherty Petroleum, Inc.) conducts all our oil and gas drilling, production and gas gathering operations. Sentra owns and operates natural gas distribution facilities for two communities in Kentucky, and NGAS Securities provides marketing support services for private placement financings. The consolidated financial statements also reflect our interests in drilling partnerships sponsored by NGAS Production to participate in many of our drilling initiatives. NGAS Production maintains a combined interest as both general partner and an investor in the drilling partnerships ranging from 12.5% to 75%, with additional reversionary interests after certain distribution thresholds are reached. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation. References in the consolidated financial statements to we, our or us include NGAS, NGAS Production, its subsidiaries and interests in drilling partnerships.
Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, as well as the reported amounts of revenues and expenses. The most significant estimates pertain to proved oil and gas reserves and related cash flow estimates used in impairment tests of goodwill and other long-lived assets, estimates of future development, production and abandonment costs. The evaluations required for these estimates involve various uncertainties, and actual results could differ from the estimates.
Oil and Gas Properties.
• Proved Properties. We follow the successful efforts method of accounting for oil and gas producing activities. Under this method, costs for exploratory discoveries and development costs for proved properties are capitalized and amortized on a unit-of-production basis over the estimated reserve life of the properties. In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (Codification) Topic (ASC) 360-10, Property, Plant and Equipment - Impairment or Disposal of Long-Lived Assets, we evaluate our proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. If the evaluation indicates that undiscounted future net cash flows from estimated proved reserves of a property exceed its book value, the unamortized capital costs of the property would be reduced to its fair value.
• Exploratory Wells. We account for exploratory well costs under ASC 932-360-35, Extractive Industries-Oil and Gas-Property, Plant and Equipment-Subsequent Measurement, which provides for exploratory well costs to be initially capitalized but charged to expense unless the wells are determined to be successful within one year after completion of drilling. The one-year limitation may be exceeded only if reserves from an exploratory well are sufficient to justify its completion and sufficient progress has been made in assessing the economic and operating viability of the overall project. If an exploratory well does not meet both criteria, its capitalized costs must be expensed, net of any salvage value. Under ASC 932-235-50, annual disclosures are required about management’s evaluation of capitalized exploratory well costs, including disclosure of (i) net changes from period to period in the costs for wells that are pending the determination of proved reserves, (ii) the amount of any exploratory well costs that have been capitalized for more than one year after the completion of drilling and (iii) an aging of suspended exploratory well costs and the number of wells affected. See Note 3 - Oil and Gas Properties.
• Unproved Properties. Lease acquisition costs for unproved properties are capitalized and amortized based on a composite of factors, including past success, experience and average lease-term lives. Unamortized lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.
• Other Properties and Equipment. Other properties and equipment include well equipment, gathering and processing facilities, office equipment and other fixed assets. These items are recorded at cost and depreciated using either the straight-line method based on expected life of the assets, ranging from 3 to 25 years, or the unit-of-production method over the estimated reserve life of the underlying properties.
Revenue Recognition. We recognize revenue on drilling contracts using the completed contract method of accounting for both financial reporting purposes and income tax purposes. This method is used because the typical contract is completed in three months or less, and our financial position and results of operations would not be significantly affected by using the percentage-of-completion method. A contract is considered complete when all remaining costs and risks are relatively insignificant. Oil and gas production revenue is recognized as production is extracted and sold. Other revenue is recognized at the time it is earned and we have a contractual right to receive it.
Regulated Activities.
• Sentra. Regulated operations of Sentra, our gas utility subsidiary, are subject to the provisions of ASC 980-605, Regulated Operations-Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. Kentucky’s Public Service Commission regulates Sentra’s billing rates for natural gas distribution sales based on recovery of purchased gas costs. For the years ended December 31, 2009, 2008 and 2007, our gas transmission, compression and processing revenue includes gas utility sales from Sentra’s regulated operations aggregating $539,374, $565,727 and $365,951, respectively.
• NGAS Securities. NGAS Securities is a registered broker-dealer and member of the Financial Industry Regulatory Authority. Among other regulatory requirements, it is subject to the net capital provisions of Rule 15c3-1 under of the Securities Exchange Act of 1934 (Exchange Act). Because it does not hold customer funds or securities or owe money or securities to customers, NGAS Securities is required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness. At December 31, 2009, NGAS Securities had net capital of $62,599 and aggregate indebtedness of $26,654.
Investments. Long-term investments in which we do not have significant influence are accounted for using the cost method. In the event of a permanent decline in value, an investment is written down to estimated realizable value, and any resulting loss is charged to earnings.
Deferred Financing Costs. Financing costs for our convertible notes and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. Upon conversion of convertible notes, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs. See Note 7 - Deferred Financing Costs.
Goodwill. In accordance with the authoritative guidance, goodwill is tested for impairment annually and more frequently if events or changes in circumstances indicate that the carrying amount of goodwill or other reporting unit exceeds its fair value. We test goodwill impairment utilizing a fair value approach at a reporting unit level, as discussed in Note 8.
Customer Drilling Deposits. Net proceeds received under NGAS Production’s drilling contracts with sponsored drilling partnerships are recorded as customer drilling deposits at the time of receipt. We recognize revenues from contract drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits represent unapplied payments for wells that were not yet drilled as of the balance sheet dates. See Note 9 - Customer Drilling Deposits.
Convertible Notes. We issued $37 million principal amount of 6% convertible notes in December 2005 with a five-year maturity and an initial conversion price of $14.34, which was reduced to $11.16 per share from weighted-average antidilution adjustments triggered by subsequent equity raises. See Note 11 - Capital Stock. Based on the December 2010 maturity of the notes, their entire carrying amount was reclassified as a current liability at December 31, 2009. See Note 10 - Long-Term Debt. After year end, we completed an exchange with the holders of these notes to extend the maturity of our convertible debt and create a flexible repayment structure with the potential for replacing part of the debt with equity at a premium to the stock price at the time of the exchange. See Note 20 - Subsequent Events.
Stock Options and Awards. We account for stock options and awards under the fair value recognition and measurement provisions of ASC 718, Compensation-Stock Compensation. See Note 11 - Capital Stock.
Deferred Compensation. Accruals for deferred compensation are recorded ratably based on estimated future payment dates and forfeiture rates for contingent payouts and benefits under our executive retention program. The program in initially included long-term incentive agreements with our executive officers and a key employee, providing for vesting of stock options and incentive awards after a five-year retention period that ended in February 2009. At that time, we provided new long-term incentive agreements to our executive officers and twelve key employees. The cash incentive awards will amount to one times the annual base salary and bonus of our executive officers, determined at the time of vesting, and will total up to $705,000 for key employees participating in the program. Awards for all participants will vest 40% after three years and 100% after five years or any earlier employment termination without cause following a change of control. See Note 11 - Capital Stock-Stock Options and Awards.
Deferred Income Taxes. We provide for income taxes using the asset and liability method. This requires that income taxes reflect the expected future tax consequences of temporary differences between the carrying amounts of assets or liabilities and their tax bases. Deferred income tax assets and liabilities are determined for each temporary difference based on the tax rates that are assumed to be in effect when the underlying items of income and expense are expected to be realized. See Note 12 - Income Taxes.
Fair Value of Derivative Financial Instruments. During 2009, we adopted ASC 815-40-15, Contracts in Entity’s Own Equity, which requires the embedded conversion feature of our 6% convertible notes to be bifurcated and treated as a derivative liability based on its fair value as a stand-alone instrument. The transition provisions of ASC 815-40-15 required cumulative effect adjustments as of January 1, 2009 to reflect the amounts that would have been recognized if derivative fair value accounting had been applied from the original issuance date of an equity-linked financial instrument through the implementation date of the revised guidance. Our fair value analysis of the notes reflected an initial derivative liability of $16,575,445 for the embedded conversion feature. From the note issuance date through the end of 2008, we would have recorded fair value gains on derivative financial instruments of $16,560,608, offset by non-cash interest expenses totaling $8,094,400 reflecting accretion of the debt discount under the effective interest method. The unaccreted debt discount of $8,466,208 was recorded a cumulative effect adjustment to retained deficit at January 1, 2009, resulting in an opening retained deficit of $2,080,503, as adjusted.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts to reflect losses that could result from failures counterparties to make payments on our receivables. When maintained, an allowance is based on factors including historical experience, aging and financial information. We recognized bad debt expenses aggregating $749,035 in 2008 and $215,000 in 2007 as reserves against past due receivables.
Reclassifications and Adjustments. Certain amounts included in the 2008 and 2007 consolidated financial statements have been reclassified to conform to the 2009 presentation.
Subsequent Events. Except as discussed in Note 20, there were no events or transactions through March 12, 2010, the issuance date of the consolidated financial statements, requiring recognition or disclosure.
Comprehensive Income and Loss. The accompanying consolidated financial statements do not include statements of comprehensive income (loss) since we had no items of comprehensive income or loss for the reported periods.
Note 2 - Recently Adopted Accounting Standards
ASU 2010-09. In February 2010, the FASB issued Accounting Standards Update (ASU) 2010-09, Amendments to Certain Recognition and Disclosure Requirements, amending its guidance on subsequent events under ASC 855 to remove the requirement for SEC filers to disclose the date through which events or transactions occurring after the balance sheet date have been evaluated for potential recognition or disclosure. The ASU will be effective for the first reporting period after its issuance. ASC 855 became effective in June 2009, and its adoption did not affect our practices for evaluating, recording or disclosing subsequent events.
ASU 2010-03. In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-03, Extractive Industries-Oil and Gas (Topic 932) - Oil and Gas Reserve Estimation and Disclosures. The ASU aligns industry-specific accounting standards for oil and gas producing activities with revised oil and gas reserve estimation and disclosure rules adopted by the Securities and Exchange Commission (SEC) at the end of 2008 and subsequently consolidated in Subpart 1200 of Regulation S-K and amendments to Rule 4-10 of Regulation S-X under the Exchange Act. We adopted the revised standards and reserve reporting rules on December 31, 2009, as discussed in Note 21 and Note 22.
ASU 2009-05. In August 2009, the FASB issued ASU 2009-05, Fair Value Measurements and Disclosures - Measuring Liabilities at Fair Value, which provides clarification for the fair value measurement of liabilities, effective for the first reporting period after issuance. Our adoption of this update did not have a significant impact on our financial position, results of operations, cash flows or disclosures.
ASC 105. ASC 105, Generally Accepted Accounting Principles. was issued by the FASB in July 2009 to establish the Codification as the single source of authoritative nongovernmental GAAP, except for SEC rules and interpretive releases. Under ASC 105, the Codification became effective for reporting periods ended after September 15, 2009. The Codification did not change existing GAAP, and adoption of ASC 105 did not have any impact on our consolidated financial statements.
Note 3 - Oil and Gas Properties
Property Acquisitions and Divestitures.
• Sale of Appalachian Gas Gathering Assets. During the third quarter of 2009, we sold 485 miles of our Appalachian gas gathering facilities (Appalachian Gathering System) to Seminole Energy Services, LLC and its subsidiary (Seminole Energy) for $50 million, of which $14.5 million is payable in monthly installments through December 2011, together with interest at the rate of 8% per annum. See Note 5 - Note Receivable. As part of the transaction, we entered into various gas marketing and gas sales arrangements with Seminole Energy, enabling us to retain operating rights for the Appalachian Gathering System and firm capacity rights for daily delivery of 30,000 Mcf of controlled gas, ensuring long-term deliverability for our Appalachian production. Cash proceeds of $35.5 million from the sale and approximately $6.1 million from a contemporaneous equity raise were applied to debt reduction under our revolving credit facility. See Note 10 - Long-Term Debt and Note 11 - Capital Stock.
• Expansion of Leatherwood Position. In October 2009, we expanded our position in the Leatherwood field with the acquisition of a lease covering 10,300 gross (8,280 net) undeveloped acres in Leslie and Harlan Counties, Kentucky. The lease provides the mineral interest owner with participation rights for up to 50% of the working interest in wells drilled on the covered acreage and requires us to drill at least three horizontal wells by the end of March 2011, followed by a two-well annual drilling commitment.
• Chesapeake Farmout. In May 2009, we acquired a farmout for 56,000 gross (42,000 net) undeveloped acres contiguous to the Amvest portion of our Stone Mountain field in Letcher and Harlan Counties, Kentucky. The mineral interest owner and royalty interest owner each have participation rights for up to 25% of the working interests in our future wells on the acreage, and we have a minimum annual drilling commitment of four wells.
Capitalized Costs and DD&A. The following table presents the capitalized costs and accumulated depreciation, depletion and amortization (DD&A) for our oil and gas properties, gathering facilities and well equipment as of December 31, 2009 and 2008.
Exploratory Well Costs. The following tables show net changes in our capitalized exploratory well costs, together with the aging of these costs, for each reported period. As of December 31, 2009, exploratory wells costs for nine wells had been capitalized for more than one year after drilling. Six of the wells were drilled during 2008 in our Licking River project, where we have development rights and a 50% interest in constrained gathering infrastructure. We suspended this project pending completion of an operating plan for infrastructure development with the successor to the co-owner of the existing facilities. The remaining three wells were drilled during 2008 on the extreme eastern and western flanks of our New Albany shale project. While considered successful based on preliminary testing, they range from seven to twelve miles from our western Kentucky gathering system, and we elected to defer completion pending expansion of the system as additional wells are drilled on the acreage.
Note 4 - Other Property and Equipment
The following table presents the capitalized costs and accumulated depreciation for our other property and equipment as of December 31, 2009 and 2008.
Note 5 - Note Receivable
As part of the consideration for the sale of our Appalachian Gathering System during the third quarter of 2009, we received a promissory note issued by Seminole Energy in the original principal amount of $14.5 million. See Note 3 - Oil and Gas Properties. The note is payable in equal monthly installments through December 2011, with interest at 8% per annum. Performance of the note is secured by a second mortgage on Seminole Energy’s interest in the Appalachian Gathering System. We have assigned the note as part of the collateral package under our revolving credit facility and have agreed to apply note payments to debt reduction under the facility. See Note 10 - Long-Term Debt.
Note 6 - Loans to Related Parties
We extended loans to several of our officers prior to 2003 and to one of our shareholders in 2004. The shareholder loan bears interest at 5% per annum and had an outstanding balance of $75,679 at December 31, 2009 and $79,188 at December 31, 2008. The loan is collateralized by the shareholder’s interests in our drilling partnerships and is repayable from partnership distributions. The loans receivable from officers totaled $171,429 at December 31, 2009 and 2008. These loans are non-interest bearing and unsecured.
Note 7 - Deferred Financing Costs
Financing costs for our convertible notes and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. See Note 10 - Long-Term Debt. Upon conversion of convertible notes, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs. Unamortized deferred financing costs for our convertible notes and credit facility aggregated $1,235,705 at December 31, 2009 and $1,689,580 at December 31, 2008, net of accumulated amortization.
Note 8 - Goodwill
Goodwill of $1,789,564 was recorded in our 1993 acquisition of NGAS Production and was amortized on a straight-line, ten-year basis until 2002, when we adopted authoritative guidance for evaluating goodwill annually and whenever potential impairment exists under a fair value approach at the reporting unit level. With no impairment under our initial and subsequent analyses, unamortized goodwill has remained at $313,177.
Note 9 - Customer Drilling Deposits
Prepayments under drilling contracts with sponsored partnerships are recorded as customer drilling deposits upon receipt. Contract drilling revenues are recognized on the completed contract method as wells are drilled, rather than when funds are received. Customer drilling deposits of $5,581,877 at December 31, 2009 and $2,262,955 at December 31, 2008 represent unapplied prepayments for wells that were not yet drilled as of the balance sheet dates.
Note 10 - Long-Term Debt
Convertible Notes. At December 31, 2009, we had $37 million principal amount of 6% convertible notes outstanding, with a stated maturity on December 15, 2010. Upon any event of default under the notes or any change of control, holders could require us to redeem the notes at specified premiums above their face amount. Notes that were neither redeemed nor converted prior to maturity were repayable in cash or common shares, valued at 92.5% of their market price and subject to various volume limitations. During 2009, we adopted revised guidance for treating the embedded conversion feature of the notes as a derivative liability, resulting in an unaccreted debt discount of $4,555,513 at December 31, 2009, as discussed in Note 1. Based on the stated maturity date of the notes, their entire carrying amount, net of the unaccreted debt discount, was reclassified at the end of 2009 as a current liability. We completed a restructuring of our convertible debt in January 2010. See Note 20 - Subsequent Events.
Credit Facility. We have a revolving credit facility maintained by NGAS Production under a credit agreement with KeyBank National Association, as administrative agent. The facility provides for loans and letters of credit in an aggregate amount up to $125 million, with a scheduled maturity in September 2011. Credit availability under the facility is subject to borrowing base limits, as determined semi-annually by the lenders. Interest is payable at fluctuating rates ranging from the agent’s prime rate to 2.25% above that rate, depending on borrowing base utilization. We are also responsible for commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. The facility is guaranteed by NGAS and is secured by liens on our oil and gas properties.
As of December 31, 2009, we had outstanding borrowings of $38.5 million under the facility, with a borrowing base of $55 million. This reflects debt reductions totaling $41.5 million from proceeds of our Appalachian Gathering System sale and related equity raise in the third quarter of 2009, as well as a borrowing base reduction of $25 million from lower commodity prices and the release of our Appalachian Gathering System assets from the collateral package. See Note 3 - Oil and Gas Properties. Further borrowing base reductions will be implemented under a credit agreement amendment entered in connection with the restructuring of our convertible debt during the first quarter of 2010. See Note 20 - Subsequent Events.
Installment Loan. In June 2009, NGAS Production obtained a $2.3 million loan from Central Bank & Trust Co. to finance the balance of its commitment under an airplane purchase contract entered in 2005. The loan bears interest at 5.875% per annum and is repayable in monthly installments of $16,428 over a three-year term, with the balance due at maturity. The loan is secured by a lien on the airplane and had an outstanding balance of $2,268,615 at December 31, 2009.
Acquisition Debt. We issued a $854,818 note in 1986 to finance our acquisition of mineral claims in Alaska. The note is repayable $2,000 per month without interest and was $270,818 at December 31, 2009.
Total Long-Term Debt and Maturities. The following tables summarize our total long-term debt at December 31, 2009 and 2008 and the principal payments due each year through 2014 and thereafter.
Note 11 - Capital Stock
Preferred Shares. We have 5,000,000 authorized shares of preferred stock, none of which were outstanding at December 31, 2009 or 2008.
Common Shares. On August 13, 2009, we completed a registered direct placement of 3.48 million units under a shelf registration statement at $1.90 per unit. Each unit consisted of one share of our common stock and a warrant to buy 0.5 common share, as described below under “Common Stock Purchase Warrants.” The following table reflects the 2009 equity raise and other transactions involving our common stock during the reported periods.
Stock Options and Awards. We maintain equity incentive plans adopted in 2001 and 2003 for the benefit of our directors, officers, employees and certain consultants. The 2001 plan provides for the grant of options to purchase up to 3 million common shares, and the 2003 plan provides for the issuance of up to 4 million common shares as stock awards or upon exercise of stock options. Awards may be subject to restrictions or vesting requirements, and option grants must be at prevailing market prices. Stock awards aggregated 460,715 shares during 2009 and 50,000 shares during 2008. Transactions in stock options during those periods are shown in the following table.
At December 31, 2009, the exercise prices of options outstanding under our equity plans ranged from $1.51 to $7.64 per share, with a weighted average remaining contractual life of 2.81 years. The following table provides additional information on the terms of stock options outstanding at December 31, 2009.
We use the Black-Scholes pricing model to determine the fair value of each stock option at the grant date, and we recognize the compensation cost ratably over the vesting period. For the periods presented in the consolidated financial statements, the fair value estimates for option grant assumed a risk free interest rate ranging from 0.03% to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from six months to six years based on the vesting provisions of the options. This resulted in non-cash charges for options and warrants of $692,646 in 2009 and $625,142 in 2008.
Common Stock Purchase Warrants. As part of our registered direct equity placement on August 13, 2009, we issued warrants to purchase 1.74 million shares of our common stock at $2.35 per share, subject to adjustment for certain dilutive issuances. The warrants are exercisable during a four-year term ending on February 13, 2014.
Note 12 - Income Taxes
Components of Income Tax Expense. The following table sets forth the components of income tax expense (benefit) for each of the years presented in the consolidated financial statements.
Reconciliation of Tax Rates. The following table sets forth a reconciliation between prescribed tax rates and the effective tax rate for our income tax expense in each of the years presented in the consolidated financial statements.
Components of Deferred Income Tax Liabilities. The following table sets forth the components of our deferred income tax liabilities as of the end of each of the years presented in the consolidated financial statements.
Net Operating Loss Carryforwards. As of December 31, 2009, we had net operating loss carryforwards of $20.3 million, including approximately $6.3 million at the parent company level. We have provided a valuation allowance in the full amount of the parent company loss carryforwards. The following table summarizes those net operating loss carryforwards by year of expiry.
Uncertain Tax Positions. We apply the guidance and procedures prescribed under ASC 740, Income Taxes, for recognizing and measuring amount of any uncertain tax position, as well as the guidance under this standard relating to derecognition, classification, transition and increased disclosure of uncertain tax positions. We recognized no liability for unrecognized tax benefits resulting from our application of this guidance during the periods presented in the consolidated financial statements.
Note 13 - Income (Loss) Per Share
The following table shows the computation of basic and diluted earnings (loss) per share (EPS) for each of the years presented in the consolidated financial statements in accordance with ASC260, Earnings per Share.
Note 14 - Employee Benefit Plan
We maintain a salary deferral plan under section 401(k) of the Internal Revenue Code. The plan allows all eligible employees to defer up to 15% of their annual compensation through contributions to the plan, with matching contributions by NGAS Production up to 3% of the participating employees’ compensation, plus half of their plan contributions between 3% and 5% of annual compensation. The deferrals accumulate on a tax deferred basis until a participating employee withdraws the funds allowable based on a vesting schedule. Our matching contributions to the plan aggregated $180,814 in 2009, $195,145 in 2008 and $172,075 in 2007.
Note 15 - Related Party Transactions
Drilling Partnerships. NGAS Production invests in sponsored drilling partnerships on substantially the same terms as unaffiliated investors, contributing capital in proportion to its initial partnership interest, which range from 12.5% to 75%, with specified increases after certain distribution thresholds are reached. Each partnership enters into drilling and operating contracts with NGAS Production or any third-party operator for all wells to be drilled for the partnership. The portion of the profit on drilling contracts attributable to NGAS Production’s partnership interest is eliminated on consolidation. The following table lists the total revenues recognized from the performance of these contracts with sponsored drilling partnerships for each of the years presented.
Office Lease. The building in Lexington, Kentucky that houses our principal and administrative offices was acquired during 2006 by a company formed for that purpose by our executive officers and a key employee. At the time of the sale, our lease covered 12,109 square feet at a monthly rent of $18,389 through expiration in February 2008. Following the sale of the building, we entered into a lease modification for an additional 1,743 square feet at a monthly rent of $2,542. In November 2007, we entered into lease renewals for a five-year term at monthly rents totaling $20,398, subject to annual escalations on the same terms as our prior lease. The terms of the initial lease modification and subsequent lease renewals were negotiated on our behalf by one of our independent directors appointed for that purpose by our board. The negotiations were conducted at arms’ length with the management company for the building, and the terms reflect prevailing rental rates with other tenants in our building and comparable office buildings in our locale.
Note 16 - Financial Instruments
Credit Risk. We maintain bank accounts in excess of FDIC insured limits, and we grant credit to our customers in the normal course of business. We perform ongoing credit evaluations of customers’ financial condition and generally require no collateral.
Fair Value of Financial Instruments. The carrying values of cash, accounts receivable, other receivables, accounts payable, accrued liabilities and customer drilling deposits approximate fair value due to their short-term maturity. Bonds and deposits, loans receivable and payable and other long-term debt payable approximate fair value since they bear interest at variable, market-based rates. The following table sets forth the financial instruments with a carrying value at December 31, 2009 different from their estimated fair value, based upon discounted future cash flows using discount rates reflecting market conditions for similar instruments.
Note 17 - Segment Information
We have a single reportable operating segment for our oil and gas business based on the integrated way we are organized by management in making operating decisions and assessing performance. Although our financial reporting reflects our separate revenue streams from drilling, production and gas gathering activities, along with the direct expenses for each component, we do not consider the components as discreet operating segments under ASC 280, Segment Reporting.
Note 18 - Commitments
Operating Lease Obligations. We incurred operating lease expenses of $2,670,002 in 2009 and $2,583,417 in 2008. As of December 31, 2009, we had future obligations under operating leases as follows:
Gas Gathering and Sales Commitments. We have various long-term commitments under gas gathering and sales agreements entered with Seminole Energy in connection with our sale of the Appalachian Gathering System during the third quarter of 2009. See Note 3 - Oil and Gas Properties. These include (i) base monthly gathering fees of $850,000, with annual escalations at the rate of 1.5%, (ii) base monthly operating fees of $175,000, plus $0.20 per Mcf of purchased gas, and (iii) monthly capital fees in amounts intended to yield a 20% internal rate of return for all capital expenditures on system by Seminole Energy. These agreements have an initial term of fifteen years with extension rights.
Note 19 - Asset Retirement Obligations
We have asset retirement obligations primarily for the future abandonment of oil and gas wells, and we maintain reserve accounts for part of these obligations under our operating agreements with sponsored drilling partnerships. We account for these obligations under ASC 410-20, Asset Retirement and Environmental Obligations, which requires the fair value of an asset retirement obligation to be recognized in the period when it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement cost is capitalized as part of the carrying amount of the underlying long-lived asset. ASC 410-20 also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation is generally determined on a units-of-production basis over the life of the asset, while the accretion escalates over the life of the asset, typically as production declines. The amounts recognized are based on numerous estimates and assumptions, including recoverable quantities of oil and gas, future retirement and site reclamation costs, inflation rates and credit-adjusted risk-free interest rates. The following table shows the changes in our asset retirement obligations during the years presented in the consolidated financial statements.
Note 20 - Subsequent Events
Convertible Note Exchange. In January 2010, we retired $37 million of our 6% convertible notes due December 15, 2010 (retired notes) in exchange for an aggregate of $28.7 million in new amortizing convertible notes due May 1, 2012 (exchange notes), together with 3,037,151 shares of our common stock, five-year warrants to purchase 1,285,038 common shares (exchange warrants) and cash payments totaling approximately $2.7 million. The transaction was covered by separate exchange agreements with the holders of the retired notes, which had been issued in December 2005 and reclassified as a current liability at the end of 2009 based on their stated maturity date. See Note 10 - Long-Term Debt. The exchange notes bear interest at 6% per annum, payable in cash at the beginning of each calendar quarter. They are convertible at the option of the holders into our common stock at $2.18 per share, and the exchange warrants are exercisable at $2.37 per share, subject in each case to certain volume limitations and adjustments for certain fundamental change transactions or share recapitalizations.
During the period from June 1, 2010 through the maturity date, we will be obligated to make 24 equal monthly principal amortization payments on outstanding exchange notes, together with accrued and unpaid interest. Subject to certain volume limitations and other conditions, including the right of each holder to defer any installment payment to maturity, we may elect to pay all or part of each principal installment in common stock, valued at the lesser of $2.18 per share or 95% of the 10-day volume-weighted average price of the common stock ending on the second business day prior to the installment date. Any installment payment or partial payment in common shares is subject to certain true-up adjustments. In addition, the exchange notes and the exchange warrants include blockers that prohibit us from issuing any shares to a holder that would increase its beneficial ownership of our stock above 4.99% of the outstanding common shares. These provisions could limit our ability to make amortizing payments on the exchange notes in common stock.
The total shares issuable under the exchange notes upon conversion, amortization or otherwise (conversion shares), together with the common shares issued in the exchange (exchange shares) and shares issuable upon exercise of the exchange warrants (warrant shares) substantially exceed 20% of our common shares outstanding prior to the transaction. To ensure compliance with our Nasdaq listing standards, the exchange documents limit the total conversion shares and warrant shares that we may issue prior to shareholder approval of the transaction to 19.99% of our shares outstanding on the date of the exchange agreements, net of the exchange shares (share ceiling). The exchange agreements require us to use our best efforts to obtain shareholder approval at the next annual meeting for all share issuances under the exchange documents. If approved by our shareholders, this will have the effect of eliminating the share ceiling.
The exchange notes are subject to customary non-financial covenants and events of default. The covenants include restrictions on share repurchases or distributions without the consent of a majority-in-interest of the note holders and limitations on any future issuances of certain types of preferred stock or variable interest securities. Subject to customary grace and cure periods in certain cases, events of default include any delisting of our common stock, any failure to pay interest or principal installments or to honor conversion or other material obligations under the exchange notes or certain other indebtedness, the rendering of unbonded judgments above specified limits and certain events of bankruptcy or insolvency. The exchange notes are redeemable in cash at the option of the holders upon any event of default at 125% of their principal amount or any change of control at 110% of their principal amount. Upon a change of control, holders will also have the right to convert their exchange notes and receive an additional number of common shares based on the price of our stock at that time or the consideration that would be received by the holder for the underlying conversion shares in the change of control transaction.
Any exchange notes that are neither redeemed nor converted prior to maturity will be repayable in cash plus accrued and unpaid interest. In accordance with the accounting guidelines for convertible debt, we expect to record the initial carrying amount of the exchange notes net of allocations for the fair value of their conversion feature on the date of the exchange agreements and the initial fair value of the exchange warrants. The resulting debt discount will be amortized to interest expense though the conversion or repayment dates of exchange notes and the exercise or expiration of the exchange warrants.
Amendment to Credit Agreement. On January 11, 2010, we entered into an amendment to the credit agreement maintained by NGAS Production with KeyBank National Association, as administrative agent for the lenders. See Note 10 - Long-Term Debt. The amendment permitted us to consummate the exchange transaction, subject to certain non-financial covenants and borrowing base modifications. These include restrictions on upstream dividends from NGAS Production for any principal amortization payments on the exchange notes that would cause outstanding borrowings under the facility to exceed 80% of the prevailing borrowing base. The amendment also provides for monthly reductions of $1 million to the borrowing base from February 2010 until the next semi-annual redetermination scheduled for April 2010. Under the terms of the amendment, the borrowing base will be further reduced by $2.7 million, representing an upstream dividend used for repurchasing retired notes in the exchange transaction, unless recontributed to NGAS Production for debt reduction under the credit facility by June 1, 2010.
Note 21 - Supplementary Information on Oil and Gas Development and Producing Activities
General. This Note provides audited information on our oil and gas development and producing activities in accordance with ASC 932-235, Extractive Activities-Oil and Gas - Notes to Financial Statements, and Items 1204 though 1208 of Regulation S-K under the Exchange Act.
Results of Operations from Oil and Gas Producing Activities. The following table shows the results of operations from our oil and gas producing activities during the years presented in the consolidated financial statements. Results of operations from these activities are determined using historical revenues, production costs (including production related taxes) and depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense are excluded from the reported operating results.
Capitalized Costs for Oil and Gas Producing Activities. For each of the years presented in the consolidated financial statements, the following table sets forth the components of capitalized costs for our oil and gas producing activities, all of which are conducted within the continental United States.
Costs Incurred in Oil and Gas Acquisition and Development Activities. The following table lists the costs we incurred in oil and gas acquisition and development activities for the years presented in the consolidated financial statements.
Note 22 - Supplementary Oil and Gas Reserve Information - Unaudited
General. This Note provides unaudited information on our estimated proved oil and gas reserves and the present value of net cash flows from those reserves as of the end of each year presented in the consolidated financial statements. The reserves estimates for each period were prepared by Wright & Company, Inc., independent petroleum engineers meeting the standards of Society of Petroleum Engineers for estimating and auditing reserves. The estimates as of December 31, 2009 were prepared in accordance with ASU 2010-03 and Subpart 1200 of Regulation S-K under the Exchange Act (collectively, current reserve rules). The current reserve rules went into effect at the end of 2009 and are intended to modernize reserve reporting standards to reflect current industry practices and technologies. Reserve estimates as of December 31, 2008 and 2007 were prepared in accordance with SEC reserve reporting rules in effect prior to the current reserve rules (prior reserve rules).
Under the current reserve rules, proved reserves are generally defined as quantities of oil and gas that can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods and governmental regulations. The reasonable certainty standard must be based on analysis of geoscience and engineering data that provides a high degree of confidence for deterministic estimates or at least a 90% probability that EURs will meet or exceed estimates based on probabilistic methods. Economic producibility for estimates under the current reserve rules is determined using the unweighted average of the first-of-the-month spot prices for each commodity category during the twelve months preceding the date of the estimate, except for future production to be sold at contractually determined prices. Under the prior reserve rules, economic producibility was based on commodity prices as of the date of the estimate. In all cases, costs are determined as of the date the estimate, and both prices and costs are held constant over the estimated life of the reserves. Commodity prices used in the estimates of our proved reserves are shown in the following table. All prices are adjusted for energy content and basis differentials.
Estimated Oil and Gas Reserve Quantities. The following table summarizes our estimated quantities of proved developed and undeveloped reserves as of December 31, 2009, using the twelve-month average pricing model under the current reserve rules, and historical reserve estimates as of December 31, 2008 and 2007, using prices as of the date of the estimates in accordance with the prior reserve rules. Proved developed reserves are generally defined under the current reserve rules as the estimated amounts of oil and gas that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are estimated volumes that are expected with reasonable certainty to be recovered from new wells on undrilled acreage within a reasonable time horizon, generally limited to five years from the date of the estimate, based on reliable technology that has demonstrated by field testing to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In accordance with the current reserve rules, historical reserve estimates at December 31, 2008 and 2007 were not restated. All reserves are located within the continental United States.
(1)
Crude oil and NGL are converted to equivalent natural gas volumes at a 6:1 ratio.
Changes in Estimated Reserves. The following table summarizes changes in net proved reserves for each of the years presented in the consolidated financial statements.
As of December 31, 2009, our proved undeveloped (PUD) reserves of 27.6 Bcfe represented 35% of our total proved reserves. None of our 2009 year-end PUDs have been included in our reported reserves for more than five years. Based on modifications adopted under the current reserve rules for unconventional resources supported by reliable technology, we added 15.9 Bcfe in new horizontal PUD locations. We also converted 0.03 Bcfe in prior year-end PUDs and 19.4 Bcfe in unproved reserves into proved developed reserves during 2009. These additions were partially offset by negative revisions of 6.7 Bcfe to our proved developed reserves from lower 2009 average prices. Estimates of our proved undeveloped reserves as of December 31, 2009 include locations that would generate positive future net revenue based on the constant prices and costs determined under the current reserve rules but would have negative present value when discounted at 10% per year under the standardized measure. These locations have been included based on our business plan for their development, along with all other PUD locations, within the next five years.
The reserve additions at year-end 2008 resulted primarily from our transition to horizontal drilling in our Leatherwood field, which added 8.3 Bcfe to our proved developed reserves. However, our PUD reserves were reduced by approximately 37 Bcfe or 64% from the prior year’s estimates, including a reduction of 16.2 Bcfe in Leatherwood. The reduction in these reserves resulted primarily from the loss of previously booked vertical PUD locations that were no longer economic based on 2008 year-end commodity prices and drilling costs. Based on the limited production history for these horizontal wells and definitional restrictions for unconventional shale plays under the prior rules, we were only able to book a total of 14 horizontal PUD locations at the end of 2008, all in Leatherwood, based on restrictions the current reserve reporting rules.
The performance related revisions to our estimated reserves at the end of 2008 also reflect our first year of NGL extraction from our Appalachian natural gas production, which was undertaken in response to a FERC tariff limiting the upward range of energy content for transported natural gas to 1.1 Dth per Mcf. To comply with the tariff, we constructed a processing plant during 2007 with a joint venture partner in Rogersville, Tennessee to extract NGL from our Appalachian gas production delivered through our gathering system. The plant was brought on line in January 2008, ensuring our compliance with the FERC tariff. Prior to 2008, we had limited NGL sales, and reserves from estimated future NGL production were included in our natural gas reserves for prior periods. At year-end 2008, the positive performance revisions of our estimated oil and NGL reserves, amounting to 2,046 Mbbls, was attributable entirely to NGL processing, which reduced our estimated natural gas reserves at year end.
At the end of 2007, we added 23.3 Bcfe to our proved reserves from 82.15 net wells drilled during the year. The reserve additions were partially offset by approximately 5 Bcf from our election to terminate a farmout covering all but 25% of our interest in the CDX-Arkoma field and downward reserve revisions for our interests in the Leatherwood field, where our EURs were reduced by 27% based on year-end production rates. While an upgrade to the main suction line for the field was installed during 2007 to alleviate higher line pressures and allow production at previously projected rates, we were not able to lower field operating pressures to match those rates as new wells were turned on line during the year. The downward reserve revisions at the end of 2007 were partially offset by positive adjustments from higher year-end commodity prices.
Standardized Measure of Discounted Future Net Cash Flows. The following table presents the standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves as of the end of each of the years presented in the consolidated financial statements. Estimates at December 31, 2009 reflect an unweighted 12-month average of the first-of-the-month reference prices for each commodity. Estimates at December 31, 2008 and 2007 reflect commodity prices as of the date of the estimate. In all cases, prices were held constant over the estimated life of the reserves, except for future production to be sold at contractually determined prices. The estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on cost levels as of the date of the estimates. Future income taxes were based on year-end statutory rates, adjusted for any operating loss carryforwards and tax credits. The future net cash flows were reduced to present value by applying a 10% discount rate prescribed under both the current and prior reserve rules. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of oil and gas properties.
(In thousands)
(1)
Reflects the twelve-month average of the first-day-of-the-month reference prices for 2009 and the year-end reference prices for prior years.
Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of our proved oil and gas reserves after income taxes for each of the years presented in the consolidated financial statements. Sales of oil and gas, net of production costs, reflect historical pre-tax results. Extensions and discoveries, purchases of reserves in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented on an after-tax basis.
(In thousands)
(1)
Reflects the twelve-month average of the first-day-of-the-month reference prices for 2009 and the year-end reference prices for prior years.
Supplementary Selected Quarterly Financial Data - Unaudited
The following table provides unaudited supplementary financial information on our results of operations for each quarter in the two-year period ended December 31, 2009.