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 considerations 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 91% of our total production revenues in 2008. 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 throughout the second half of 2008, ending the year at $5.71 per Mcf in the spot markets for our region, with further price erosion to a six-year low during the first quarter of 2009. 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 the 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 surged 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, conservation and tax measures, including proposed legislation to eliminate IDC and depletion deductions for federal income tax purposes, beginning in 2011, which could impair our ability to raise capital through sponsored drilling partnerships if adopted.
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 may not only decrease our revenues on a per unit basis but may also reduce the amount of natural gas that we can produce economically. Although we increased our estimated proved developed reserves at December 31, 2008 by 20% to 57.4 Bcfe, our proved undeveloped reserves decreased 64% from prior-year vertical PUD reserves that were no longer economic based on 2008 year-end commodity prices, coupled with higher vertical drilling costs for the year. 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 drilling results, 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 would 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 $37 million outstanding principal amount of convertible notes due in December 2010 and $72 million of outstanding borrowings at year-end under our revolving credit facility, which is scheduled to mature in September 2011. The facility is secured by liens on substantially all our assets and had a borrowing base of $80 million at year-end 2008. The borrowing base limits the amount we can borrow or have outstanding at any one time, as determined semi-annually by the lenders. These redeterminations are based primarily on 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 and letters of credit could 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 level of indebtedness may limit our financial and operating flexibility and performance.
The amount and maturities of our debt may adversely affect our business in various ways. Among other adverse consequences, our level of indebtedness could:
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limit our ability to fund planned capital expenditures, 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.
Declining 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. We have reduced our operating and capital budget for 2009 to meet our drilling commitments and objectives with internally generated cash flow, coupled with a return to our established drilling partnership structure and sales network for participation in these initiatives. However, these sources have historically covered only part of our total expenditures for property development, and we have generally funded property acquisitions and infrastructure development for our own account, relying on the financial markets to provide us with additional capital for these projects. 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 access to the capital markets, we could be required to sell properties or find other ways to monetize assets. Otherwise, we would have to reduce our planned 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 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 reserves will decline as they are produced. Although the production history for most of our Appalachian wells is substantially less than the average reserve life of over 25 years for mature wells in the region, estimates of the proved developed reserves from our vertical wells as of December 31, 2008 were based on the extensive historical production profiles for the region. This resulted in a projected decline rate for our vertical wells of approximately 18.6% during 2009, decreasing hyberbolically to 5.5% in 2023. The actual performance of these wells could differ materially from the reserve estimates, and EURs from our horizontal wells is even more uncertain 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 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 then 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. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. 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 our estimates may require future revisions of the 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 recover our proved undeveloped reserves or resources from unproved properties due to general economic conditions or capital constraints.
As of December 31, 2008, approximately 26% of our estimated proved reserves were undeveloped. The ultimate recovery of our undeveloped reserves is uncertain. Recovering these PUD reserves and developing our unproved properties will require significant capital expenditures and successful drilling operations. The 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. Our reported reserves also assume the continuation of economic conditions at the time of the estimates, including the costs associated with reserve development, which may increase disproportionately with commodity prices over time. Any of these factors could cause our actual results from future development initiatives to vary significantly from the anticipated results reflected in our reserve estimates.
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 initiatives 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 during 2007 and the first half of 2008 in response to higher commodity prices and reported success in regional shale plays, notably in 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, and our 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 would 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 of toxic gas. Any of these hazards could result in personal injury, property and environmental damage, clean-up responsibilities and other regulatory penalties. While we maintain insurance to protect us against these operating risks, the operating hazards associated with our development and production activities may expose us to liabilities not 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 our 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 could also affect its market price. As of December 31, 2008, there were 26,543,646 shares of our common stock issued and outstanding. If all our convertible notes and stock options outstanding at year end are converted or exercised, there will be an additional 7,473,019 shares of our common stock outstanding. All of these 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 market price above $1.00 per share. Although the market price requirement for continued listing provides for various grace periods to regain compliance, the maximum grace period is currently limited to 360 days. If our common stock were to be delisted, liquidity in the common stock would be impaired. Any delisting of our common stock would also trigger an event of default requiring us to redeem our outstanding convertible notes.
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 validity of our gold and silver exploration rights. We have no plans to develop these properties independently and instead 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.
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 2008.
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 9, 2009, there were 2,781 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, 2008 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.
Stock Performance Graph
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, 2008. The financial data is derived from our audited consolidated financial statements, which have been audited by Hall, Kistler & Company LLP for 2008, 2007 and 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, 2008 and 2007 and for the three years ended December 31, 2008 should be read in conjunction with our consolidated financial statements and related notes included at the end of this report and with 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 and results of operations.
(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 generating and developing natural gas prospects in Appalachia and other unconventional plays with similar geologic characteristics. We also control the midstream and field-wide gas gathering facilities for our core Appalachian properties, providing deliverability directly from the wellhead to interstate pipelines serving major east coast natural gas markets, and we operate natural gas distribution facilities for two communities in Kentucky. Historically, we developed most of our prospects through sponsored drilling partnerships with outside investors, 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.
Beginning in the second half of 2007, we changed our business model to accelerate organic growth by retaining all of our available working interest in new wells drilled on operated properties, with a view toward limiting our use of drilling partnerships to participation in non-operated projects. While we are committed to continue expanding our reserves and production through the drillbit, we are addressing current conditions in the financial and energy markets with a planned reduction in capital spending to approximately $15 million for 2009 and a resumption of drilling partnership participation in our operated initiatives until market conditions improve. This should enable us to continue meeting our drilling commitments and objectives for core properties without access to the capital markets and with limited reliance on additional draws under our credit facility.
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.
Our revenue mix for 2008 reflects our ongoing strategy for transitioning to a more production based business, with oil and gas sales accounting for 46% of total revenues, compared to 40% of total revenues in 2007. Despite our planned reduction in capital expenditures for 2009, we expect this trend to continue on a long-term basis as we expand our horizontal drilling initiatives and our infrastructure and acreage position in our core operating areas.
Contract drilling revenues reflect the size and timing of our drilling program initiatives, as well our ownership interest in sponsored programs. Although we receive the proceeds from private placements in sponsored programs as customers’ drilling deposits under our program drilling contracts, we recognize revenues from the interests of outside investors in these programs on the completed contract method as the wells are drilled, rather than when funds are received. 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. We anticipate ongoing production gains as we continue to bring completed wells on line, including substantial contributions from our horizontal drilling initiatives. Our natural gas production is sold primarily through gas marketing intermediaries. 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 fees totaling $5,029,815 for moving third-party gas through our NGAS Gathering system and $746,970 in related processing fees for liquids extraction through our Rogersville plant. This component of revenues also includes gathering and compression fees of $1,936,300 for moving our drilling program investors’ share of gas through our field-wide facilities, together with contributions of $565,727 from gas utility sales and $458,154 from our 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 reflect the level of drilling initiatives conducted through our sponsored partnerships. These expenses increased by 2% on a year-over-year basis and represented 77% of contract drilling revenues in 2008, compared to 78% in the prior year. 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.
Production expenses represent lifting costs, field operating and maintenance expenses, related overhead, severance and other production taxes, third-party transportation fees and processing costs. The increase in production expenses on a year-over-year basis 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 2008. Our margins in both reported periods reflect cost savings realized from ownership of the NGAS Gathering system acquired in March 2006, eliminating transportation fees for our dedicated Appalachian production, of which approximately 90% is now delivered through the system. As a percentage of oil and gas production revenues, our production expenses were 33% in 2008, compared to 27% in the prior year, 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 have benefited from third-party fees generated by the NGAS 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 dehydration and compression capacity required to bring new wells on line.
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 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 18.4% in 2007 to 16.6% in 2008.
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 $286,419 in 2008 for deferred compensation costs.
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 increase in DD&A charges 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. A first quarter charge of $347,840, coupled with a prior period reserve, represents the entire amount due for oil sales to a regional refinery prior to its filing for reorganization under the bankruptcy laws last year. A second quarter charge of $59,000 reflects a writeoff of a non-performing loan to a regional operator on a three-well project in Texas. In the third quarter of 2008, we recognized a bad debt expense of $342,195 for 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. Basic earnings per share (EPS) was $0.11 based on 26,409,275 weighted average common shares outstanding in 2008, compared to EPS of $(0.04) in 2007 based on 22,240,429 weighted average common shares outstanding in 2007.
Results of Operations - 2007 and 2006
Revenues. The following table shows the components of our revenues for 2007 and 2006, together with their percentages of total revenue in 2007 and percentage change on a year-over-year basis.
Contract drilling revenues reflect the size and timing of our drilling partnership initiatives, as well as our percentage interest in sponsored programs. The contraction in contract drilling revenues reflects the completion of program initiatives on operated properties and a reduction in our reliance on partnership financings for other drilling initiatives during 2007.
The growth in our production revenues for 2007 reflects a 15% increase in production output to 3,297 Mmcfe, compared to 2,868 Mmcfe in 2006. Our average gas sales prices were marginally lower on a year-over-year basis, amounting to $8.19 per Mcf in 2007. Approximately 40% of our natural gas production in 2007 was sold under fixed-price contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices.
Gas transmission, compression and processing revenues in 2007 were driven by fees totaling $3,812,116 for delivering third-party gas through our NGAS Gathering system. This component of revenues also reflects gathering and compression fees for our drilling program investors’ share of throughput from our field-wide facilities, together with contributions of $365,951 from gas utility sales and $354,449 from our interest in a limited liability company that owns and operates the gathering system for a non-operated coalbed methane project in the Arkoma Basin.
Expenses. The following table shows the components of our direct and other expenses in 2007 and 2006. 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 decreased by 32% on a year-over-year basis but represented 78% of contract drilling revenues in both 2007 and 2006. The contraction in this part of our business reflects a planned reduction in our use of drilling partnerships to participate in developing our operated properties in the Appalachian Basin, and our margins reflect the stabilizing effect of our transition from turnkey to cost-plus pricing, which we implemented in 2006 to address price volatility for drilling services, equipment and steel casing requirements.
Production expenses in 2007 were consistent with our volumetric growth. Our margins in both periods reflect cost savings realized from ownership of the NGAS Gathering system acquired in March 2006, eliminating transportation fees for our share of Leatherwood, Straight Creek and SME production delivered through the system.
Gas transmission, compression and processing expenses in 2007 were 47% of associated revenues, compared to 56% in 2006. The margins for this part of our business have benefited from third-party fees generated by the NGAS Gathering system. The improvement in margins for 2007 reflect our first full year of owning these midstream assets, which we acquired in March 2006 for $18 million. Our gas transmission, compression and processing expenses do not reflect those acquisition costs or capitalized costs of approximately $7.2 million in 2007 for extensions of our field-wide gas gathering systems, additions to dehydration and compression capacity or build-outs of gas processing and treatment facilities.
We expensed the suspended exploratory well costs during 2007 for 27 wells in a 30-well program we began late in 2005 to test the shallow New Albany shale formation on the eastern rim of the Illinois Basin in western Kentucky. This resulted in an impairment charge of $964,000 in the carrying value of our oil and gas assets during 2007, in addition to a charge of $178,700 recognized for the first three wells in that program during 2006.
SG&A expenses are comprised primarily of selling and promotional costs for our sponsored drilling programs and overhead costs for supporting our expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased salary and other employee related expenses over the last several years.
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 accruals of $540,244 in 2007 and $583,208 in 2006 for deferred compensation costs.
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 increase in DD&A charges on a year-over-year basis reflects substantial additions to our oil and gas properties, gas gathering systems and related equipment.
We recognized a bad debt expense of $215,000 in the third quarter of 2007 to reflect a reserve against past due accounts receivable from oil sales to a regional refinery. See “Critical Accounting Policies and Estimates - Allowance for Doubtful Accounts.” We also recognized a loss of $54,304 from the sale of fixed assets in 2007, compared to gains aggregating $3,197,834 from asset sales in 2006.
Interest expense for 2007 increased from higher overall bank borrowings. Draws under our credit facility during 2007 were used primarily to support our ongoing drilling initiatives and enhancements of our field-wide gas gathering systems.
Deferred income tax expense 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 recognized a net loss of $816,597 in 2007, compared to net income of $1,992,438 in 2006, reflecting the foregoing factors. Basic EPS was $(0.04) based on 22,240,429 weighted average common shares outstanding in 2007, compared to EPS of $0.09 based on 21,510,594 weighted average common shares outstanding in 2006.
Liquidity and Capital Resources
Liquidity. Net cash of $26,733,185 was provided by operating activities in 2008. During the year, we used $56,875,544 in investing activities, most of which reflects net 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.
Net cash of $1,828,345 was provided by operating activities in 2007. During the year, we used $50,832,815 in investing activities, most of which reflects net additions to our oil and gas properties and gathering systems. These investments were funded in part with net cash of $37,389,171 from financing activities. As a result of these activities, net cash decreased from $14,431,977 at December 31, 2006 to $2,816,678 at the end of 2007.
As of December 31, 2008, we had a working capital deficit of $5,519,114. This reflects wide fluctuations in our current assets and liabilities from the timing of customer deposits and expenditures under drilling contracts with our sponsored programs. Since these fluctuations are normalized over relatively short time periods, we do not consider working capital to be a reliable measure of liquidity. The working capital deficit at the end of 2008 is not expected to have an adverse effect on our financial condition or results of operations in future periods.
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 related infrastructure build-outs on terms that are economically and operationally advantageous.
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. Historically, we also relied on participation in our operated 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, with a view to 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 by reducing our 2009 capital spending budget to $15 million, allocated 80% to drilling and the balance to infrastructure and lease acquisition projects. This is in line with our anticipated cash flow from operations and may be adjusted during the year in response to market developments. To meet our 2009 drilling commitments and objectives with limited reliance on additional draws under our credit facility, we are returning to our established partnership structure and sales network, which raised over $34 million for a non-operated program last year. We expect to maintain a 20% interest in this year’s program, which will increase to 35% after program payout. With our critical infrastructure in place to provide deliverability for our production at a low cash cost, this will allow us to continue delivering organic growth, although at lower rates than we could achieve with access to the capital markets. If market conditions improve, we would expect to raise additional capital to accelerate drilling and meet our long-term resource development objectives.
We have a senior secured revolving credit facility maintained by our U.S. operating subsidiary, Daugherty Petroleum, Inc. (DPI), 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. We amended the facility in May 2008 to add to the collateral package and in August 2008 to increase the borrowing base from $75 million to $90 million. The borrowing base was lowered to $80 million at year end to reflect the downturn in the energy and credit markets. 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 DPI’s oil and gas properties and gathering facilities. As of December 31, 2008, outstanding borrowings under the facility aggregated $72 million, with $2 million in letters of credit, and the interest rate amounted to 4.25%. We are in compliance with our financial and other covenants under the credit facility at December 31, 2008.
We have an outstanding series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible into our common shares at a conversion price of $12.94, reflecting an antidilution adjustment based on the pricing of a registered direct equity placement of our common stock at $6.00 per share in November 2007. We will be entitled to redeem the notes at their face amount plus accrued interest if the prevailing market price of our common stock exceeds 160% of the note conversion price for specified periods. In the event of a default under the notes or any change of control, the holders may require us to redeem the notes at a default rate equal to 125% of their principal amount or a change of control rate equal to the greater of 110% of their principal amount or the consideration that would be received by the holders for the underlying shares in the change of control transaction. Any notes that are neither redeemed nor converted prior to maturity will be repayable in cash or in common shares, valued for that purpose at 92.5% of their prevailing market price.
Our ability to repay our revolving credit 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 demand and market price for natural gas. Future market prices for natural gas will also have a significant impact on our ability to maintain or increase our borrowing capacity, to obtain additional capital on acceptable terms and to 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 general economic downturn and current unsettled conditions in natural gas markets by reducing our capital expenditure budget and returning to our established drilling partnership structure for participation in our development initiatives. To realize our long-term goals for growth in revenues and reserves, however, we will continue to dependent on the credit and capital markets or other financing alternatives. Any prolonged constriction in the capital markets could require us to sell 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 Securities 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;
•
regulatory changes and litigation risks; and
•
uncertainties in estimating proved oil and gas reserves, projecting future rates of production and timing of development and remedial expenditures.
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, our interest expenses are sensitive to market changes, which exposes us to interest rate risk on current and future indebtedness under the facility.
Foreign Market Risk. We sell our products and services exclusively in the United States and receive payment solely in United States dollars. 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
We are parties to leases for office facilities and various types of equipment. We are also obligated to make payments at specified times and amounts under instruments governing our long-term debt and other commercial commitments. The following table lists our minimum annual commitments as of December 31, 2008 under these instruments.
Related Party Transactions
Because we operate through subsidiaries and affiliated 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 the Company than could be obtained on an arm’s length basis from unrelated parties. Significant related party transactions are summarized in Notes 4 and 13 to the consolidated financial statements and related disclosure included elsewhere 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 these aspects of our financial reporting are summarized in Note 1 to the consolidated financial statements included in this report. Policies involving the more significant judgments and estimates used in the preparation of our consolidated financial statements 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 our 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, while other long-lived assets are reviewed whenever events or changes in circumstances indicate that carrying values of these assets are not 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 with customers.
Item 7A
Item 7A Quantitative and Qualitative Disclosures about Market Risk
Commodity Price 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 our exposure to these fluctuations or for speculative trading purposes, 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 SFAS No. 133, 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. During 2008, approximately 50% of our natural gas production was sold under fixed-price contracts at rates ranging from $8.03 to $9.15 per Dth. The balance of our natural gas production for the year was sold primarily at prices determined monthly under formulas based on prevailing market indices. As of December 31, 2008, we had contracts in place for portions of our anticipated 2009 gas production from operated Appalachian properties at sales prices ranging from $9.58 per Mcf to $9.70 per Mcf. 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, 2008, 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, 2008. 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, 2008 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 directors and 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 Daugherty Petroleum, Inc., our operating subsidiary (“DPI”), 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 DPI since September 2005, having served as a Vice President of DPI from 1993 until being appointed its CEO. Mr. Barr has more than 30 years’ experience in the corporate and legal sectors of the oil and gas industry. Before joining DPI, 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 DPI between 1995 and September 2005, when he was appointed as its President. For six years before joining DPI, he served as the Director of the Kentucky Division of Oil and Gas. He has more than 25 years’ 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 DPI 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 2009 annual meeting of shareholders to be filed with the Securities and Exchange Commission before the end of April 2009.
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, 2009.
NGAS Resources, Inc.
By:
/s/ William S. Daugherty
By:
/s/ Michael P. Windisch
William S. Daugherty,
President and Chief Executive Officer
(Principal executive officer)
Michael P. Windisch,
Chief Financial 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.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of 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, 2008. 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, 2008, as stated in their report appearing on page.
/s/ William S. Daugherty
/s/ Michael P. Windisch
William S. Daugherty,
President and Chief Executive Officer
March 11, 2009
Michael P. Windisch,
Chief Financial Officer
March 11, 2009
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, 2008, 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, 2008, 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 10, 2009 expressed an unqualified opinion.
Canton, Ohio
March 10, 2009
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, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years ended December 31, 2008. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our 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 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 audit provides 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years ended December 31, 2008, 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), the effectiveness of NGAS Resources, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 10, 2009 expressed an unqualified opinion thereon.
Canton, Ohio
March 10, 2009
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
(a) General. The accompanying consolidated financial statements of NGAS Resources, Inc. (NGAS) for the years ended December 31, 2008, 2007 and 2006 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 stated in U.S. dollars. NGAS is organized under the laws of British Columbia, and we prepared our financial statements prior to 2006 in accordance with accounting principles generally accepted in Canada (Canadian GAAP). Our adoption of U.S. GAAP in 2006 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.
(b) Basis of Consolidation. The consolidated financial statements include the accounts of NGAS, our wholly owned subsidiary, Daugherty Petroleum, Inc. (DPI), a Kentucky corporation, and DPI’s wholly owned subsidiaries, NGAS Gathering, LLC (NGAS Gathering), Sentra Corporation (Sentra) and NGAS Securities, Inc. (NGAS Securities). DPI conducts all oil and gas drilling and production operations, including construction of field-wide gathering systems. NGAS Gathering owns and operates the open-access section of our gathering system acquired in 2006. Sentra owns and operates natural gas distribution facilities for two communities in Kentucky. NGAS Securities provides marketing support services for private placement financings. The consolidated financial statements also reflect our interests in drilling programs sponsored by DPI to participate in many of our drilling initiatives. DPI maintains a combined interest as both general partner and an investor in the drilling programs ranging from 12.5% to 75%, subject to specified increases 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 the Company, we, our or us include DPI, its subsidiaries and interests in sponsored drilling programs.
(c) Estimates. The preparation of financial statements in conformity with U.S. 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 and the reported amounts of revenues and expenses during the reporting periods. 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, dismantlement and abandonment costs and estimates relating to future oil and gas revenues and expenses. The evaluations required for these estimates involve significant uncertainties, and actual results could differ from the estimates.
(d) Oil and Gas Properties.
(i) Proved. We follow the successful efforts method of accounting for oil and gas producing activities. Under this method, exploratory well costs are initially capitalized but charged to expense if and when the well is determined to be unsuccessful. Costs resulting from exploratory discoveries and development costs for proved properties, whether or not successful, are capitalized and amortized on a unit-of-production basis method over the remaining life of the proved developed reserves estimated for the underlying properties. Development costs include leasehold acquisition costs for proved properties and the cost of support equipment and facilities. We evaluate our proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. We follow Statement of Financial Accounting Standards (SFAS) No. 144, Impairment of Long-Lived Assets, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value.
(ii) Unproved. Unproved properties consist of costs incurred to acquire unproved leases and unproved reserves. Unproved lease acquisition costs 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.
(iii) Exploratory Wells. Under SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, drilling costs for exploratory wells are initially capitalized but generally must be charged to
expense unless the wells are determined to be successful within one year after completion of drilling. Circumstances that permit continued capitalization of exploratory drilling costs are addressed by the Financial Accounting Standards Board (FASB) under Staff Position (FSP) No. 19-1, Accounting for Suspended Well Costs. The one-year limitation may be exceeded for an exploratory well only if sufficient reserves have been found to justify its completion and sufficient progress has been made in assessing the reserves and the economic and operating viability of the project. If the exploratory well does not meet both criteria, its capitalized costs are expensed, net of any salvage value. Annual disclosures are required under FSP No. 19-1 to provide information 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 2 - Oil and Gas Properties.
(iv) Other Properties and Equipment. Other properties and equipment include well equipment, gathering and transmission 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.
(e) 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 from use of 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 the revenue.
(f) Regulated Activities.
(i) Sentra. Regulated operations of Sentra, our gas utility subsidiary, are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. SFAS No. 71 requires regulated 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. These billing rates are based on evaluation of Sentra’s recovery of its purchased gas costs. For the years ended December 31, 2008, 2007 and 2006, gas transmission, compression and processing revenue includes gas utility sales from Sentra’s regulated operations aggregating $565,727, $365,951 and $273,180, respectively.
(ii) 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. 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, 2008, NGAS Securities had net capital of $96,609 and aggregate indebtedness of $18,853.
(g) 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.
(h) 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.
(i) Goodwill. Goodwill is tested for impairment at least annually and more frequently if indicated under SFAS No. 142, Goodwill and Other Intangible Assets. See Note 6 - Goodwill. Under these procedures, the fair value of goodwill or other reporting unit is compared with its carrying amount. If the carrying amount exceeds its fair value, an impairment test must be performed to compare the implied fair value of the reporting unit goodwill with its carrying amount to determine any impairment loss.
(j) Customer Drilling Deposits. Net proceeds received under DPI’s drilling contracts with sponsored drilling programs are recorded as customer drilling deposits at the time of receipt. We recognize revenues from 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 7 - Customer Drilling Deposits.
(k) 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.
(l) Stock Options. We account for stock options under the fair value recognition and compensation measurement provisions of SFAS No. 123(R), Share-Based Payment, which we adopted retroactively under its Canadian GAAP equivalent at the beginning of 2004. See Note 9 - Capital Stock.
(m) Deferred Compensation. We had long-term incentive agreements with four of our executive officers and one key employee, providing for the vesting of stock options and incentive awards based on their annual base salary and bonus if they continued to serve in their positions until February 25, 2009 or any earlier termination of their employment without cause or resignation for good reason following a change of control. The bonus awards were payable and the options became exercisable on the vesting date. In December 2008, we provided new long-term incentive agreements to our executive officers and twelve key employees for a five-year retention period beginning February 25, 2009. See Note 9 - Capital Stock -- Stock Options and Awards. The awards under these agreements vest 40% after three years and 100% after five years or any earlier termination of their employment without cause or resignation for good reason following a change of control. The cash incentive awards for our executive officers are set at 100% of their annual base salary and bonus at the time of vesting. The cash incentive awards for key employees total $705,000. Accruals for deferred compensation under these agreements are recorded ratably based on estimated future payment dates and forfeiture rates.
(n) 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 amounts with customers. We recognized bad debt expenses aggregating $749,035 in 2008 and $215,000 in 2007 as reserves against past due receivables.
(o) Reclassifications and Adjustments. Certain amounts included in the 2007 and 2006 consolidated financial statements have been reclassified to conform to the 2008 presentation.
(p) 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 periods reported.
Note 2. Oil and Gas Properties
(a) Property Acquisitions and Divestitures.
(i) Acquisition of Transmission System. In March 2006, our NGAS Gathering subsidiary acquired an open-access gas transmission system spanning 116 miles in southeastern Kentucky and southwestern Virginia for $18 million. We operated this system since October 2004 and augmented it after the acquisition through two high-pressure lateral upgrades. Most of our Appalachian production is delivered through this system, which had daily throughput of over 20,000 Dth of controlled and third-party gas as of December 31, 2008.
(ii) Purchase and Sale of Royalty Interests. In August 2006, we acquired overriding royalty interests averaging 2.25%, together with related participation and pipeline capacity rights, for properties we operate under a farmout in Harlan County, Kentucky and Lee County, Virginia. The purchase price for the acquired assets was $1.5 million. We retained the participation and pipeline capacity rights and sold the overriding royalty interests to a third party, effective September 1, 2006, for $2.0 million.
(iii) Purchase and Sale of Lease Position. In November 2006, we completed the sale of our oil and gas lease position in the Williston Basin for $4.8 million. We retained an overriding royalty interest of 1.35% in the lease position. The position was assembled under a leasing program initiated in 2005 and covered 18,411 gross (14,864 net) acres in the southwestern portion of Dunn County, North Dakota. The sale resulted in an after-tax gain of approximately $1.6 million.
(b) 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, 2008 and 2007.
(c) Suspended Well Costs. The following table reflects the net changes in capitalized exploratory well costs, in accordance with FSP No. 19-1, Accounting for Suspended Well Costs, during each of the years presented:
The following table provides an aging of capitalized exploratory well costs at December 31, 2008, 2007 and 2006, based on the dates that drilling was completed. As of those dates, we had no wells for which exploratory wells costs had been capitalized for more than one year after completion of drilling.
Note 3. Property and Equipment
The following table presents the capitalized costs and accumulated depreciation for our other property and equipment as of December 31, 2008 and 2007.
Note 4. 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 $79,188 at December 31, 2008 and $85,635 at December 31, 2007. The loan is collateralized by the shareholder’s interests in our drilling programs and is repayable over a five-year term from program production revenues, with a balloon payment at maturity. The loans receivable from officers totaled $171,429 at December 31, 2008 and 2007. These loans are non-interest bearing and unsecured.
Note 5. 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 8 - 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 outstanding notes and credit facility aggregated $1,689,580 at December 31, 2008 and $1,706,852 at December 31, 2007, net of accumulated amortization.
Note 6. Goodwill
Goodwill of $1,789,564 was recorded in connection with our acquisition of DPI in 1993 and was amortized over ten years on a straight-line basis until 2002, when we adopted the Canadian equivalent of SFAS No. 142, Goodwill and Other Intangible Assets. Under the adopted standard, goodwill is no longer amortized but is instead tested for impairment at least annually. Our annual analyses indicated that no impairment charges were required. Accordingly, accumulated amortization of goodwill remained at $1,476,387 as of December 31, 2008 and 2007, with unamortized goodwill of $313,177.
Note 7. Customer Drilling Deposits
Net proceeds received under drilling contracts with sponsored programs are recorded as customer drilling deposits at the time of receipt. We recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits were $2,262,955 at December 31, 2008 and $2,857,806 at December 31, 2007, representing unapplied drilling contract payments for wells that were not yet drilled as of the balance sheet dates.
Note 8. Long-Term Debt
(a) Convertible Notes. We have an outstanding series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible into our common shares at a conversion price of $12.94, reflecting an antidilution adjustment from the issuance of 4.2 million shares of our common stock in November 2007, based on our net proceeds of approximately $23.7 million. See Note 9 - Capital Stock. We will be entitled to redeem the notes at 100% of their principal amount plus accrued and unpaid interest if the prevailing market price of our common stock exceeds 160% of the note conversion price for specified periods. Upon any event of default under the notes or any change of control, we may be required to redeem the notes at a default rate equal to 125% of their principal amount or at a change of control rate equal to the greater of 110% of their principal amount or the consideration that would be received by the holders for the underlying shares in the change of control transaction. Any notes that are neither redeemed nor converted prior to maturity will be repayable at our option in cash or in common shares, valued for that purpose at 92.5% of their prevailing market price.
(b) Credit Facility. We have a senior secured revolving credit facility maintained by DPI with KeyBank National Association, as agent and primary lender, with a scheduled maturity in September 2011. The facility provides for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a borrowing base of $80 million at December 31, 2008. 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. Alternatively, we may elect Eurodollar based pricing from 1.5% to 3.0% above quoted Libor rates. We are also responsible for commitment fees at rates ranging from 0.375% to 0.5% of the unused borrowing base. As of December 31, 2008, outstanding borrowings under the facility aggregated $72 million, with $2 million in letters of credit. The facility is secured by liens on substantially all our assets and is guaranteed by NGAS.
(c) Equipment Loan. We obtained a term loan of $2.1 million in September 2007 from Central Bank & Trust Co. to finance two previously purchased drilling rigs that we leased to one of our drilling contractors. The loan was repayable in monthly installments over a five-year term, bearing interest at 8% per annum, and was prepaid without penalty during the first quarter of 2008.
(d) Acquisition Debt. We issued a note for $854,818 to finance our 1986 acquisition of mineral property on Unga Island, Alaska. The debt is repayable without interest in monthly installments of $2,000 and is secured by liens on the acquired property, buildings and equipment. Although the acquisition agreement provides for royalties at 4% of production revenues, the property has remained inactive. The outstanding acquisition debt was $294,818 at December 31, 2008 and $318,818 at December 31, 2007.
(e) Total Long-Term Debt and Maturities. The following tables summarize our total long-term debt at December 31, 2008 and 2007 and the principal payments due each year through 2013 and thereafter.
Note 9. Capital Stock
(a) Preferred Shares. We have 5,000,000 authorized shares of preferred stock, none of which were outstanding at December 31, 2008 or 2007.
(b) Common Shares. The following table reflects transactions involving our common stock during the reported periods.
(c) Stock Options and Awards. We maintain three stock plans for the benefit of our directors, officers, employees and certain consultants or advisors. The plans provide for the grant of options to purchase up to 3,600,000 common shares and, in the case of our most recent plan, either stock awards or options for an aggregate of up to 4,000,000 common shares. Option grants under all the plans must be at prevailing market prices and may be subject to vesting requirements over a period of up to ten years from the date of grant. Stock awards under the third plan may be subject to vesting conditions and trading restrictions specified at the time of grant. During 2008 and 2007, stock awards and option grants were made under these plans for a total of 2,350,000 and 10,430 shares, respectively. The following table shows transactions in stock options during 2008 and 2007.
At December 31, 2008, the exercise prices of options outstanding under our equity plans ranged from $1.51 to $7.64 per share, and their weighted average remaining contractual life was 3.27 years. The following table provides additional information on the terms of stock options outstanding at December 31, 2008.
In accounting for stock options, we apply the fair value recognition provisions of SFAS No. 123(R), Share-Based Payment, which we adopted retroactively in 2004. 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 interim consolidated financial statements, the fair value estimates for each 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 $625,142 in 2008 and 529,062 in 2007.
(d) Common Stock Purchase Warrants. We have issued common stock purchase warrants in various financing transactions. We had warrants for the purchase of 10,000 common shares at $4.03 per share outstanding at December 31, 2006, which were fully exercised in the first quarter of 2007.
Note 10. Income Taxes
(a) Components of Income Tax Expense. The following table sets forth the components of income tax expense for each of the years presented in the consolidated financial statements.
(b) 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.
(c) 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.
(d) Net Operating Loss Carryforwards. As of December 31, 2008, we had net operating loss carryforwards of $54.1 million, including approximately $30.6 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.
(e) Uncertain Tax Positions. We adopted the provisions of FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - Interpretation of FASB No. 109, on January 1, 2008. FIN No. 48 prescribes a two-step process for recognizing and measuring income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the benefit from an uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN No. 48 provides additional guidance on measuring the amount of the uncertain tax position. We may recognize a tax benefit from an uncertain tax position under FIN No. 48 only if it is more likely than not that the tax position will be sustained on examination by taxing authorities based on the technical merits of the position. The tax benefit recognized in the financial
statements from an uncertain position should be measured under FIN No. 48 based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification, transition and increased disclosure of uncertain tax positions. We recognized no liability for unrecognized tax benefits resulting from our adoption of FIN No. 48.
Note 11. Income (Loss) Per Share
The following table shows the computation of basic and diluted earnings per share (EPS) for each of the years presented.
Note 12. 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 the Company 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 $195,145 in 2008, $172,075 in 2007 and $123,596 in 2006.
Note 13. Related Party Transactions
(a) General. Because we operate through our subsidiaries and affiliated drilling programs, our corporate structure causes various agreements and transactions in the normal course of business to be treated as related party transactions. It is our policy to structure any transactions with related parties only on terms that are no less favorable to the Company than could be obtained on an arm’s length basis from unrelated parties. Significant related party transactions not disclosed elsewhere in these notes are summarized below.
(b) Drilling Programs. DPI invests in sponsored drilling programs on substantially the same terms as unaffiliated investors, contributing capital in proportion to its initial program interest. DPI has interests in these programs ranging from 12.5% to 75%, subject to specified increases after certain distribution thresholds are reached. Each program enters into drilling and operating contracts with DPI or any third-party operator for all wells to be drilled by that program. The portion of the profit on drilling contracts attributable to DPI’s ownership interest in each of these programs is eliminated on consolidation. The following table lists the total revenues recognized from the performance of these contracts with sponsored drilling programs for each of the years presented.
(c) 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 four senior 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 14. Financial Instruments
(a) Credit Risk. 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. In addition, at times throughout the year, we may maintain certain bank accounts in excess of FDIC insured limits.
(b) 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 rates. The following table sets forth the financial instruments with a carrying value at December 31, 2008 different from their estimated fair value, based upon discounted future cash flows using discount rates reflecting market conditions for similar instruments.
Note 15. 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 transmission activities and the direct expenses for each component, we do not consider the components as discreet operating segments under SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information.
Note 16. Commitments
We incurred operating lease expenses of $2,583,417 in 2008, $2,317,526 in 2007 and $1,727,982 in 2006. As of December 31, 2008, we had future obligations under operating leases and other commercial commitments in the amounts listed below.
(1)
Reflects commitments under a purchase contract for an airplane.
Note 17. 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 drilling and operating agreements with sponsored programs. We account for these obligations under SFAS No. 143, Accounting for Asset Retirement 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. SFAS No. 143 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.
Note 18. Recent Accounting Standards
Oil and Gas Reporting Requirements. In December 2008, the SEC amended its oil and gas reporting rules under the Exchange Act and Industry Guides. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves by aligning the oil and gas disclosure requirements with current industry practices and technology. The amendments will be effective for fiscal years ending on or after December 31, 2009 and will significantly impact reserve and resource reporting for all E&P companies.
SFAS No. 162. In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS 162 identifies the sources of accounting principles and the framework for selecting principles to be used in the preparation and presentation of financial statements in accordance with U.S. GAAP. The statement will be effective 60 days after the SEC approves the Public Company Accounting Oversight Board’s amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. We do not expect the adoption of SFAS 162 to have an effect on our consolidated financial statements.
SFAS No. 161. In March 2008, the FASB issued SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities, which expands the quarterly disclosure requirements in SFAS No. 133 for derivative instruments and hedging activities, effective for fiscal years beginning after November 15, 2008. We do expect SFAS No. 161 to affect our consolidated financial position and results of operations.
FSP No. 157-2. In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No. 157, which defers the effective date of SFAS 157 for certain nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis. The deferred provisions of SFAS 157 affect assets measured at fair value in goodwill impairment testing, nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. We will adopt these deferred provision on January 1, 2009 and do not expect them to have a material impact on our consolidated financial position or results of operations.
SFAS No. 160. In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which establishes accounting and reporting standards for noncontrolling or minority interests in a subsidiary, including changes in a parent’s ownership interest in a subsidiary. Under the new standard, noncontrolling interests in subsidiaries must be classified as a separate component of equity, and net income for both the parent and the noncontrolling interest must be disclosed on the consolidated statement of operations. SFAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008, and its disclosure requirements will then apply retrospectively for all prior periods presented. We are assessing the affect its adoption may have on our consolidated financial statements.
SFAS No. 141(R). In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. This statement provides revised guidance for recognizing and measuring assets acquired and liabilities assumed in a business combination. It also requires transactions costs for a business combination to be expensed as incurred. SFAS No. 141(R) will impact our accounting for any business acquisition we complete after 2008.
Note 19. Supplementary Information on Oil and Gas Development and Producing Activities
(a) General. This Note provides audited information on our oil and gas development and producing activities in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities.
(b) 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 this determination.
(c) 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.
(d) 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 20. Supplementary Oil and Gas Reserve Information - Unaudited
(a) General. Our estimated net proved oil and gas reserves and the present value of estimated cash flows from those reserves are summarized below. The reserve information is unaudited. The reserves were estimated by Wright & Company, Inc., independent petroleum engineers, in accordance with regulations of the Securities and Exchange Commission, using market or contract prices at the end of each of the years presented in the consolidated financial statements. These prices were held constant over the estimated life of the reserves. There are numerous uncertainties inherent in estimating quantities and values of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures, including factors involving reservoir engineering, pricing and both operating and regulatory constraints. All reserve estimates are to some degree speculative, and various classifications of reserves only constitute attempts to define the degree of speculation involved. Accordingly, oil and gas reserve information represents estimates only and should not be construed as being exact.
(b) Estimated Oil and Gas Reserve Quantities. The following table summarizes our estimated quantities of proved oil and gas reserves and changes in net proved reserves for each of the years presented in the consolidated financial statements. The reserve additions reflected in the table for 2008 resulted primarily from our transition to horizontal drilling in our Leatherwood field, where we added 8.3 Bcfe to our proved developed reserves at year-end. However, our proved undeveloped reserves at year-end 2008 were reduced by 64% from the prior year’s estimates, including 16.2 Bcfe in Leatherwood. The reduction 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. While we expect many of the former vertical PUDs to be drilled horizontally with substantially better economics than vertical wells, we were only able to book a total of 14 horizontal PUD locations at the end of 2008, all in Leatherwood, based on restrictions for unconventional shale plays under the current reserve reporting rules.
(c) Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is provided for the financial statement user as a common base for comparing oil and gas reserves of enterprises in the industry and may not represent the fair market value of our oil and gas reserves or the present value of future cash flows of equivalent reserves due to various uncertainties inherent in making these estimates. Those factors include changes in oil and gas prices from year-end prices used in the estimates, unanticipated changes in future production and development costs and other uncertainties in estimating quantities and present values of oil and gas reserves.
The following table presents the standardized measure of discounted future net cash flows from our ownership interests in proved oil and gas reserves as of the end of each of the years presented in the consolidated financial statements. The standardized measure of future net cash flows as of December 31, 2008, 2007 and 2006 are calculated using weighted average prices in effect as of those dates. Those prices were $5.51, $7.39 and $6.15, respectively, per Mcf of natural gas and $40.00, $87.98 and $56.88, respectively, per barrel of oil and natural gas liquids. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the estimated proved reserves based on year-end cost levels. Future income taxes are based on year-end statutory rates, adjusted for any operating loss carryforwards and tax credits. The future net cash flows are reduced to present value by applying a 10% discount rate. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of our oil and gas properties.
(In thousands)
(d) 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, are based on 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 after tax.
(In thousands)
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, 2007.