Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Proved Oil and Gas Reserves
General. This report includes estimates of our proved oil and gas reserves and future net cash flows from those reserves as of December 31, 2006, 2005 and 2004. The reserves were estimated Wright & Company, Inc., independent petroleum engineers (Wright & Co.), in accordance with regulations of the Securities and Exchange Commission (SEC), using market or contract prices at the end of each reported period. These prices were held constant over the estimated life of the reserves. The following reserve estimates should be read in conjunction with supplementary disclosure on our oil and gas development and producing activities and oil and gas reserve data included in the footnotes to our consolidated financial statements at the end of this report.
There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. 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 drilling, testing and production after the date of an estimate may justify revision of the estimate. As a result, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered.
Reserve Quantities. The following table summarizes the estimates by Wright & Co. of our net proved reserves as of December 31, 2006, 2005 and 2004. Proved developed reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage
where the existence and recoverability of reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion.
At December 31, 2006, our proved undeveloped reserves represented 58.4% of our total estimated proved reserves (developed and undeveloped) on an energy equivalent basis, compared to 54.3% of total reserves at the end of 2005. Estimates of our proved undeveloped reserves are highly dependent on our ability to continue raising the capital needed to sustain the pace of drilling activities at assumed rates. The estimates are therefore subject to considerable uncertainty in view of the historic volatility in domestic natural gas markets and the importance of market strength in attracting investment capital.
Reserve Values. The following table summarizes the estimates by Wright & Co. of future net cash flows from the production and sale of our estimated proved reserves and the present value of those estimated cash flows, discounted at 10% per year, as of December 31, 2006, 2005 and 2004. The estimated future net cash flows are computed after giving effect to estimated future development and production costs, based on year-end costs and assuming the continuation of existing economic conditions. The standardized measure of future net cash flows gives effect to future income taxes on discounted future cash flows based on year-end statutory rates, adjusted for any operating loss carryforwards and tax credits.
The prices used in the following estimates were based on prices we received for our oil and gas production at the end of each reported period, without escalation. The prices as of December 31, 2006 had a weighted average of $6.15 per Mcf of natural gas and $56.88 per barrel of crude oil, compared to $12.39 per Mcf of natural gas and $54.65 per barrel of crude oil December 31, 2005 and $6.89 per Mcf and $43.23 per Bbl at December 31, 2004. The estimates are highly dependent on the year-end prices used in their computation. In view of historic volatility in domestic natural gas and crude oil markets, those estimates are subject to considerable uncertainty.
In computing the present value of the estimated future net cash flows, a discount factor of 10% was used in accordance with SEC regulations to reflect the timing of net cash flows. Regardless of the discount rate used, present value is materially affected by assumptions on the timing of future production, which involve a number of uncertainties.
(In thousands)
We have not filed any estimates of our proved oil and gas reserves with any federal authority or agency during the past year other than estimates filed with the SEC in accordance with our reporting obligations under the Securities Exchange Act of 1934 (Exchange Act).
Oil and Gas Properties
Oil and Gas Interests. As of December 31, 2006, we owned oil and gas development rights under leases and farmouts covering 76,603 gross (27,148 net) developed acres and 225,518 gross (191,119 net) undeveloped acres, all located onshore within the continental United States. Our oil and gas leases and farmouts are for varying primary terms and are generally subject to specified royalty or overriding royalty interests, development obligations and other commitments and restrictions, none of which is expected to materially interfere with our development or operation of these properties. Some of our farmouts provide the lease holders or mineral interest owners with participation rights, which have been exercised in our Leatherwood field for average working interests of 25.4% in wells drilled during 2006 and 28.75% during 2005. See Business - Drilling Operations - Participation Rights. The following table shows our ownership interests under oil and gas leases and farmout agreements, by state, as of December 31, 2006.
(1)
Acres spaced or assignable to productive wells.
(2)
Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether that acreage contains proved reserves.
Productive Wells. The following table shows, by state, our gross and net productive oil and gas wells as of December 31, 2006. The table does not include 116 gross (65.5924 net) wells that were drilled by year end but were awaiting installation of gathering lines prior to completion.
Significant Fields. Our producing properties and associated development prospects are concentrated in the southern portion of the Appalachian basin. The following table shows estimated proved reserves from our interests in our Appalachian and other fields as of December 31, 2006.
Additional information about our significant fields is summarized below. Unless otherwise indicated, well counts, production volumes and reserve data are provided as of December 31, 2006.
Leatherwood. The Leatherwood field covers approximately 59,000 acres, extending 40 miles through Letcher, Perry, Leslie and Harlan Counties in eastern Kentucky. We acquired our interests in this field during 2002 under a farmout agreement with the mineral interest owners. At that time, there was no gas gathering infrastructure in this region, which has a history as an active coal producing district. During 2003, we formed a specialized drilling program for 25 exploratory wells to test five natural gas pay zones within this field at depths between 3,500 and 5,300 feet. These wells were all successful, producing from the Maxon sand, Big Lime and Devonian shale formations. Through subsequent drilling programs, we have drilled an additional 188 development wells in Leatherwood, for a total of 213 wells. As of year end, we had 193 wells in Leatherwood producing to sales through the NGAS Gathering system, with total daily gross production of 5,997 Mcf.
We completed the construction of a 23-mile gathering system for our Leatherwood wells and a 16-mile line that connects them to the NGAS Gathering system late in 2005, enabling us to bring a backlog of unconnected wells on line sequentially. After exceeding available compression capacity for Leatherwood production, we installed an additional compressor in the fourth quarter of 2006. While this gave us the compression capacity to bring new Leatherwood wells on line, a pressure backup at the end of the field with most of our existing production has required us to add a five-mile upgrade to the main suction line to the compressors. The upgrade is scheduled for completion early the second quarter of 2007 and is expected to significantly increase gas flows from new Leatherwood wells at the perimeter of the field.
Our farmout for Leatherwood had a 200-well drilling commitment, which we satisfied ahead of schedule in 2006. The farmout provides the mineral interest owners with participation rights for up to 50% of the working interest in new wells. The participation rights under the farmout were exercised for average total working interests of 25.4% in wells drilled during 2006 and for 28.75% during 2005. The exercise of these rights has proportionately reduced our working interest in Leatherwood wells drilled with third-party participants. To capitalize on our strategy for Leatherwood development, we tailored our core drilling programs in 2006 for tiered participation on a field-wide basis, retaining a 75% program interest in Leatherwood. Estimated proved reserves from our interests in Leatherwood are 27% proved developed.
Arkoma-CDX. The Arkoma-CDX field is a coalbed methane project covering approximately 14,000 acres in the Arkoma basin within Sebastian County, Arkansas and Leflore County, Oklahoma. Initial development of the project began in 2001 through a joint venture between CDX Gas, LLC, with a 75% stake, and Dart Energy Corporation, with a 25% interest. The joint venture drilled a total of 15 vertical and 33 horizontal CBM wells, with average daily gross production slightly over 7.0 Mmcf at November 1, 2005. Effective as of that date, we acquired Dart Energy’s 25% interest in the Arkoma-CDX field, including its 25% interest in the gathering system for the project area. Earlier in the fourth quarter of 2005, we entered into a farmout agreement with CDX for 90% of its majority (75%) interest in a minimum of 32 drilling locations on the Arkoma-CDX acreage. Under the terms of the farmout agreement, we assumed 100% of future developments costs attributable to the CDX working interest and granted CDX 25% carried working interest, increasing to 50% after payout of project wells. Combined with our interests from the Dart Energy acquisition, our CDX farmout gives us an overall position of approximately 73% in future development of the Arkoma-CDX field.
Through a specialized drilling program we sponsored in the third quarter of 2005, CDX drilled 4 CBM wells on locations in the Oklahoma sector of the Arkoma-CDX field, and one horizontal well in the Arkansas sector, which has drilling units up to twice the size permitted on the Oklahoma acreage. We launched a second program in the second quarter of 2006 to exploit the Arkansas sector of the field, which spans approximately 11,500 acres. We participated with a 12.5% program interest in both initiatives. At year end, we had 9 program wells online with total daily gross CBM production of 3,119 Mcf, and the remaining wells were awaiting connection upon installation of production lines. Estimated proved reserves from our interests in the Arkoma-CDX field are 42% proved developed.
SME. We acquired our interests in the SME fields, including existing wells and infrastructure, during the fourth quarter of 2004. These fields are divided between Amvest, spanning approximately 33,000 acres in Harlan County, Kentucky and Lee County, Virginia, and Martin’s Fork, with approximately 41,000 acres in Harlan County, Kentucky. Amvest produces from the Big Lime, Weir sand and Devonian shale formations at depths between 3,800 and 5,500 feet. Martin’s Fork produces from the Big Lime, Devonian shale and Clinton formations at depths between 3,200 and 6,500 feet. Oil is also produced from the Weir sand and the Big Lime formation in Amvest and the Big Lime in Martin’s Fork. Our interests in the SME fields are subject to annual drilling commitments for four wells in Amvest and two wells in Martin’s Fork. Since acquiring our interests in SME, we have drilled a total of 26 wells on this acreage through several drilling programs. At year end, we had a total of 62 wells in Amvest and 64 wells in Martin’s Fork producing to sales, with daily gross production aggregating 3,016 Mcfe. We operate all the wells and produce all natural gas in these field through the NGAS Gathering system. Estimated proved reserves from our interests in the SME fields are 58% proved developed.
Straight Creek. The Straight Creek field is located adjacent to the Big Sandy Gas field on the north side of the Pine Mountain fault system in Bell and Harlan Counties, Kentucky. We have interests in approximately 27,000 acres in this field. In addition to several wells we acquired in this field during 2004, we have drilled 156 wells in Straight Creek, which produce from the Maxon sand, the Big Lime, Devonian shale, Corniferous and Big Six sand formations at depths between 3,200 and 4,700 feet. We operate all of the wells and a 16-mile gathering system we completed in 2005 to enhance our Straight Creek production through compression into the NGAS Gathering system. A total of 162 wells in Straight Creek were producing to sales at year end, with daily gross production of 3,243 Mcf. Estimated proved reserves from our interests in the Straight Creek field are 39% proved developed.
Kay Jay. The Kay Jay field spans portions of Knox and Bell Counties in eastern Kentucky. Our interests in the field include drilling rights on approximately 11,500 acres acquired as a farmout in 1996, with an ongoing annual drilling commitment for four wells, and an additional 15,500 acres subsequently assembled under a leasing
program for this field. We have drilled 152 wells in Kay Jay, which produce natural gas from the Maxon sand, Big Lime, Borden, Devonian shale and Clinton formations at depths ranging from 2,200 to 3,200 feet. Oil is also produced from the Maxon sand. We operate all of our Kay Jay wells and own all of the field-wide gathering facilities for their production. Our gathering facilities are currently connected to their-party pipeline systems. We had a total of 193 wells in Kay Jay producing to sales at year end, with daily gross gas production of 2,767 Mcf. Estimated proved reserves from our interests in the Kay Jay field are 54% proved developed.
Fonde. The Fonde field spans portions of Bell County, Kentucky and Claiborne County, Tennessee, located just northeast of the Days Chapel field, formerly one of the most prolific oil fields in the region. We acquired our initial position on approximately 4,900 acres during 1996. Since that time, we have assembled approximately 44,000 additional acres in this field under a series of farmouts and leases. The Fonde field produces natural gas from the Big Lime and Devonian shale formations at depths up to 4,500 feet and crude oil from the Big Lime. We have drilled a total of 53 Fonde wells for several sponsored programs, including 22 wells in 2006. Our gathering facilities for Fonde wells are connected to a third-party pipeline system, and our production has historically been limited by pipeline capacity constraints to 700 Mcf per day. We are currently adding new facilities to provide deliverability for Fonde production into the NGAS Gathering system through a 17-mile, six-inch steel line scheduled for completion in the third quarter of 2007. Estimated proved reserves from our interests in Fonde are 44% proved developed.
Gold and Silver Properties
We own rights to gold and silver properties located on Unga Island, one of the Shumagin Islands on the easterly island group in the Aleutian Chain, 579 miles southwest of Anchorage, Alaska. The mining properties cover approximately 381 acres situated six miles from Sand Point, Alaska. Our interests in these properties are comprised of various federal patented lode and mill site claims covering approximately 280 acres and several State of Alaska mining claims covering approximately 101 acres. There are inferred but no defined mineral reserves for either of these claims. While we continue to expend required funds for maintaining our interests in these claims, we stopped all exploratory work on the properties in 1996 and elected to write off their remaining carrying value for accounting purposes in 2000.
We have no plans for developing our gold and silver properties internally. Any efforts to develop the properties would require substantial expenditures for surface and underground diamond drilling, rehabilitation and equipping of existing mine shafts and workings, level rehabilitation and geologic sampling and mapping. Our objective is to monetize our interests in these properties by seeking a joint venture partner to either provide funds for developing the prospects or to acquire them from us. Our ability to implement this strategy will depend on price expectations for gold and silver as well as a variety of other geological and market factors beyond our control.
Office Facilities
We lease 13,852 square feet of commercial space for our principal and administrative offices in Lexington, Kentucky at monthly rents ranging from $20,931 to $21,008 through the end of the lease term in February 2008. This reflects expansion of our offices under lease modifications we implemented during the last several years.
Item 3.
Item 3. Legal Proceedings
We are involved in several legal proceedings incidental to our business, none of which is considered to be material to our consolidated financial position, results of operations or liquidity.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No proposals were submitted for approval by our shareholders during the fourth quarter of 2006.
Part II
Item 5.
Item 5. Market for Common Stock and Related Security Holder Matters
Trading Market
Since January 2006, our common stock has traded on the Nasdaq National Market in the United States under the symbol NGAS. Our common stock was previously traded on the Nasdaq SmallCap Market under the same symbol. The following table shows the range of high and low bid prices for our common stock for the periods indicated, together with the average daily trading volume, as reported by Nasdaq. These quotations represent inter-dealer prices, without mark-ups or commissions, and they may not necessarily correspond to actual sales prices.
Security Holders
As of March 5, 2007, there were 2,836 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.
Item 6.
Item 6. Selected Financial Data
Our consolidated financial statements included in this report have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). All of our oil and gas operations are conducted within the continental United States, and all amounts reported in the consolidated financial statements are in U.S. dollars. We are organized at the parent company level under the laws of British Columbia, and we previously prepared our consolidated financial statements in accordance with accounting principles generally accepted in Canada (Canadian GAAP). The laws of British Columbia were changed in 2005 to permit publicly held U.S. reporting companies organized in that jurisdiction to elect U.S. GAAP and engage U.S. auditors. We made this election at the beginning of 2006. 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, 2006. The financial data is derived from our audited consolidated financial statements, which have been audited by Hall, Kistler & Company LLP for 2006 under U.S. GAAP and by Kraft Berger LLP for prior years under Canadian GAAP. The summary selected consolidated financial data set forth below as of December 31, 2006 and 2005 and for the three years ended December 31, 2006 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 energy company focused on generating and developing natural gas prospects in Appalachia and other unconventional basins with similar geologic characteristics. We develop our prospects through our operating subsidiaries and our interests in sponsored drilling programs. All of our direct and indirect subsidiaries are wholly owned. We maintain a combined interest as both general partner and an investor in our drilling programs ranging from 12.5% to 75%, 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. Through our operating subsidiaries, we also control the gas gathering and transmission 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.
Results of Operations - 2006 and 2005
Revenues. The following table shows the components of our revenues for 2006 and 2005, together with their percentages of total revenue in 2006 and percentage change on a year-over-year basis.
Our revenue mix for 2006 reflects our ongoing strategy for transitioning to a production based business, with oil and gas sales accounting for 30% of total revenues, compared to 26% of total revenues in 2005. We expect this trend to continue as we execute our initiatives for long term production growth by expanding our infrastructure and acreage position in core fields, and accelerating our development of these properties through sponsored drilling programs.
Contract drilling revenues reflect both the size and the timing of our drilling program financings. Although we receive the proceeds of these financings as customers’ drilling deposits under drilling contracts with our programs, we recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. We participated in 46 gross (16.8258 net) wells in the fourth quarter of 2006, and a total of 226 gross (65.4577 net) wells for the year as a whole. During the first quarter of 2006, most of the wells were drilled under our turnkey contracts with programs sponsored late in 2005. For our 2006 programs, we implemented a cost-plus structure as part of our strategy for reducing exposure to price volatility in drilling services and supplies. We also tailored these programs for tiered participation on a field-wide basis, retaining program interests of 75% in Leatherwood development and from 12.5% to 60% for program initiatives in other fields. Two programs for development of our core Appalachian fields were sponsored in the second half of the year, contributing to a significant ramp up in revenues from this sector. With all of our turnkey obligations from prior programs fulfilled, we expect margins for this sector to stabilize from our ongoing cost-plus drilling operations.
Our growth in production revenues reflects an increase of 57% in production volumes to 2,868 Mmcfe in 2006, with a 9% decline in our average sales price of natural gas (before certain transportation charges) to $8.23 per Mcf. Our volumetric growth reflects added production from our interests in Arkoma-CDX wells acquired late in 2005 and from new wells brought on line in all our operating areas during 2006, including 144 wells connected in our Leatherwood field during the year. We anticipate ongoing volumetric growth as we continue to upgrade our infrastructure and bring our new wells in Leatherwood and other key fields on stream. Principal purchasers of our production are gas marketers and customers with transmission facilities near our producing properties. Approximately 35% of our natural gas production in 2006 was sold under fixed-price contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices.
Gas transmission and compression revenues were driven by fees totaling $2,754,498 for moving third-party gas through our NGAS Gathering system, which we acquired in March 2006. This component of revenues also reflects additional gas gathering and compression fees for moving third-party Leatherwood production through field-wide facilities we completed late in 2005, together with contributions of $273,180 in 2006 from gas utility sales and $311,127 from our minority interest in a limited liability company that owns and operates the gathering system servicing the Arkoma-CDX field.
Expenses. The following table shows the components of our direct and other expenses in 2006 and 2005. 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 substantial level and complexity of our drilling initiatives. In 2006, these expenses were 78% of contract drilling revenues, compared to 79% in 2005. The margins for this sector reflect our transition from turnkey to cost-plus pricing for our new drilling programs, which we implemented in 2006 with a view to reducing our exposure to price volatility for drilling services, equipment and steel casing requirements. We began to realize slight improvements in our margins for this sector in the second half of 2006 as we completed the transition to our-plus pricing structure. We expect these margins to stabilize from ongoing cost-plus drilling program operations.
Production expenses in 2006 were driven by our substantial growth in production volumes. In addition to lifting costs, production expenses include field operating and maintenance costs, related overhead, third-party transportation fees and lease operating expenses. The increase in our production expenses was significantly offset by cost savings realized from ownership of the NGAS Gathering system acquired in March 2006, eliminating transportation fees during the balance of the year for our share of Leatherwood, Straight Creek and SME production delivered through the system. As a percentage of oil and gas production revenues, our production expenses increased to 28% in 2006 from 25% in the prior year, primarily reflecting lower margins for non-operated properties, lower gas sales prices and higher filed service costs.
Gas transmission and compression expenses in 2006 were 56% of associated revenues, compared to 75% in 2005. The improvement in margins for this part of our business reflects substantial revenue growth from third-party fees generated by the NGAS Gathering system acquired in March 2006. Our gas transmission and compression expenses do not reflect our acquisition costs for that system or capitalized costs for extensions of our field-wide gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.
In the fourth quarter of 2006, we expensed part of our capitalized exploratory well costs for a project we began late in 2005 to test the New Albany shale formation on acquired tracts in the Illinois basin, with an impairment charge of $178,700 in the carrying value of our position. We also recognized a fourth quarter writedown of $168,018 for impairment of non-operated properties in Polk County, Texas.
Selling, general and administrative (SG&A) expenses primarily reflect the timing and extent of our selling and promotional costs for sponsored drilling programs. On a year-over-year basis, SG&A expenses also reflect higher costs for supporting expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased salary and other employee related expenses.
Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options, which we adopted in 2004. 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 $583,208 for deferred compensation cost.
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, including our acquisition of the NGAS Gathering transmission system for $18 million in March 2006. It also reflects a fourth quarter adjustment to reflect a substantial increase in our depletion rate for 2006.
Interest expense in 2006 increased from the addition of $37 million in convertible debt at the end of 2005 and higher overall bank borrowings, primarily to support our acquisition costs of $11.4 million for CBM assets in the Arkoma at the end of 2005, $18 million for the purchase of our NGAS Gathering system early in 2006 and capitalized costs of approximately $6.5 million for extensions and enhancements of our field-wide gas gathering systems throughout the year.
The gain of $3,197,834 on the sale of assets in 2006 was generated primarily from two strategic transactions. The first transaction was a sale of our overriding royalty interests under a farmout for properties we operate in Harlan County, Kentucky and Lee County, Virginia. We had acquired these interests, together with related participation and pipeline capacity rights, for $1.5 million earlier in the year, and received $2.0 million for the sale of the royalty interests. In the second transaction, completed in the fourth quarter, we sold our oil and gas lease position in the Williston basin for $4.8 million, resulting in a gain of approximately $2.7 million. We had assembled the position under a leasing program we initiated in 2005. At the time of the sale, our Williston position aggregated 18,411 gross (14,864 net) areas.
Income tax expense recognized in 2006 represents future tax liability at the operating company level. We have no current tax liability due to the utilization of intangible drilling costs (IDC) allocated from our active drilling programs.
Net Income and EPS. We realized net income of $1,992,438 in 2006, compared to $952,756 in the prior year, reflecting the foregoing factors. Basic EPS was $0.09 based on 21,510,594 weighted average common shares outstanding in 2006 compared to $0.05 in 2005 based on 17,350,550 weighted average common shares outstanding. On a fully diluted basis, EPS for 2006 was $0.09 on 22,922,615 weighted average common shares.
Results of Operations - 2005 and 2004
Revenues. The following table shows the components of our revenues for 2005 and 2004, together with their percentages of total revenue in 2005 and percentage change on a year-over-year basis.
Contract drilling revenues were $43,787,075 for 2005, up 8% from 2004. This reflects both the size and the timing of drilling program financings, from which we derive most of our contract drilling revenues. During 2005, we participated in 155 gross (44.3040 net) natural gas wells. Most of the wells were drilled under turnkey contracts with drilling programs we sponsored prior to our transition to a cost-plus pricing structure.
The growth in production revenues for 2005 reflects an increase of 112% in our production volumes to 1,824 Mmcfe in 2005 from 861 Mmcfe in 2004. Part of our growth in production volumes resulted from our
acquisitions of producing properties during 2005 and the fourth quarter of 2004. It also reflects added production from new wells brought on line in 2005, including 51 wells connected in our Leatherwood field during the year. In addition to higher volumes, the growth in production revenues reflects a 35% increase in our average sales price of natural gas (before certain transportation charges) to $9.02 per Mcf in 2005 from $6.70 per Mcf in the prior year. During 2005, approximately 30% of our natural gas production was sold under fixed-price contracts and the balance primarily at prices determined monthly under formulas based on prevailing market indices.
Gas transmission and compression revenues increased 35% to $2,123,870 in 2005. This reflects continued reliance by sponsored drilling programs on our field-wide gathering systems. During 2005, we extended these systems for new wells by over 140 miles. Our gas transmission and compression revenues also reflect contributions of $323,159 from gas utility sales in 2005 and $320,162 in the prior year.
Expenses. The following table shows the components of our direct and other expenses for 2005 and 2004. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.
Total direct expenses increased by 22% to $40,477,412 in 2005, compared to $33,046,624 in 2004. Our direct expense mix for 2005 was 86% contract drilling, 10% oil and gas production and 4% natural gas transmission and compression. For 2004, our total direct expenses were incurred 90% in contract drilling, 7% in oil and gas production and 3% in natural gas transmission and compression.
Contract drilling expenses in 2005 were $34,731,234 or 79% of contract drilling revenues, compared to $29,620,335 or 73% of contract drilling revenues in 2004. This primarily reflects the substantial level and complexity of drilling activities under drilling contracts with sponsored drilling programs. It also reflects substantial costs for downhole problems on several wells during 2005 and costs incurred to add lifting equipment and surface facilities for handling oil produced from a number of wells completed during the year, primarily in our Straight Creek field.
Production expenses were $4,157,356 in 2005, compared to $2,413,375 in 2004, reflecting our substantial growth in production volumes. As a percentage of oil and gas production revenues, production expenses decreased to 25% in 2005 from 42% in 2004.
Gas transmission and compression expenses in 2005 were $1,588,822, compared to $1,012,914 in 2004. Gas transmission and compression expenses do not reflect capitalized costs of $12,796,342 in 2005 for extensions of our field-wide gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.
SG&A expenses were $11,251,759 in 2005, an increase of 14% from $9,848,139 in 2004. The increase primarily reflects the timing and extent of our selling and promotional costs for sponsored drilling programs. Our higher SG&A expenses for 2005 also reflect costs for supporting expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased compensation and other employee related expenses. As a percentage of total revenues, SG&A expenses decreased to 18% in 2005 compared to 21% in the prior year.
Beginning in 2004, we adopted 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. In addition to accruals for deferred compensation costs of $467,633 in 2005 and $368,935 in 2004, we recognized non-cash charges of $806,423 in 2005 from fair value accounting for employee stock options, compared to $374,161 recognized in 2004.
DD&A increased 152% to $4,750,134 in 2005, compared to $1,886,965 in 2004. The increase in DD&A reflects substantial additions to our oil and gas properties and gas gathering systems during 2005, as well as our SME acquisition in October 2004.
Interest expense for 2005 was $1,725,250, up 153% from $682,235 in 2004. This reflects increased overall debt to support ongoing drilling and gas gathering initiatives. We also had higher variable rates for our bank debt in 2005. See Liquidity and Capital Resources below.
Net income before income tax expense was $2,819,191 in 2005, compared to $3,505,456 in 2004. We recognized income tax expense of $1,866,435 in 2005, most of which was recorded as a future tax liability, reflecting application of a 15% allocation of IDC from our 2005 development drilling programs at the U.S. operating company level.
Net Income and EPS. We realized net income of $952,756 in 2005, compared to $1,611,701 in 2004, reflecting the foregoing factors. Basic earnings per share (EPS) was $0.05 based on 17,350,550 weighted average common shares outstanding in 2005, compared to $0.12 based on 13,994,283 weighted average common shares outstanding in 2004. On a fully diluted basis, EPS was $0.05 on 19,126,555 weighted average common shares outstanding in 2005, compared to $0.10 on 16,467,584 weighted average common shares outstanding in 2004.
Liquidity and Capital Resources
Liquidity. Net cash of $2,256,429 was provided by operating activities in 2006. During the year, we used $43,812,946 in investing activities, most of which reflects net additions to our oil and gas properties and gathering systems, including our $18 million acquisition of NGAS Gathering system and related midstream assets in March 2006. These investments were funded in part with net cash of $32,044,242 from financing activities. As a result of these activities, net cash decreased from $23,944,252 at December 31, 2005 to $14,431,977 at the end of 2006.
Net cash of $19,499,092 was provided by our operating activities in 2005. Our cash position during the year was decreased by the use of $43,318,271 in investing activities, reflecting net additions of $41,661,586 to our oil and gas properties. These investments were funded in part with net cash of $35,914,059 from financing activities, comprised primarily of proceeds from convertible note financings of $6,168,696 in the first quarter and $37,000,000 in the fourth quarter of 2005, as well as the exercise of outstanding warrants and options throughout the year. Financing activities also reflect the repayment of our credit facility during the fourth quarter of 2005. As a result of these activities, net cash increased to $23,944,252 at December 31, 2005 from $11,849,372 at December 31, 2004.
As of December 31, 2006, we had a working capital deficit of $827,300. This reflects wide fluctuations in our current assets and liabilities from the timing of customers’ deposits and expenditures under drilling contracts with our sponsored programs. Since these fluctuations are normalized over relatively short time periods, we generally do not consider working capital to be a reliable measure of liquidity. The working capital deficit at the end of 2006 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. Our long term performance and profitability is dependent not only on developing existing oil and gas reserves, but also on our ability to find or acquire additional reserves on terms that are economically and operationally advantageous. To fund our ongoing reserve development and acquisition activities, we have relied on a combination of cash flows from operations, bank borrowings and private placements of our convertible notes and equity securities, as well as participation by outside investors in our sponsored drilling programs.
In December 2005, we completed an institutional private placement of our 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. We also issued warrants in the transaction, which expired unexercised in August 2006. At December 31, 2006, all of the notes remained outstanding but were recorded at $35,603,926, reflecting an initial allocation of $2,394,913 for their equity components, which was ratably accreted by $432,893 in 2006, along with $565,946 reallocated to debt upon expiration of the warrants.
The notes are convertible by their holders into our common stock at a conversion price of $14.34 per share, subject to adjustments for certain dilutive issuances of common stock. If a holder elects to convert a note before the second anniversary of the issuance date, unless the prevailing market price of our common stock exceeds 160% of the conversion price, the holder will be entitled to a payment equal to the difference between two years’ interest on the converted note and the interest already paid on the note, payable at our option in cash or in common shares. After that date, if the prevailing market price of our common stock exceeds 160% of the conversion price, we may redeem any unconverted notes at a redemption price equal to their principal amount plus accrued and unpaid interest. Upon any event of default or any change of control, the notes are redeemable at the option of the holders in cash 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 110% of the consideration that would be received by the holder 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. Any common shares issued for interest payments on converted notes or upon redemption at their maturity will generally be valued for that purpose at 92.5% of their prevailing market price.
In September 2006, we entered into a credit agreement with KeyBank National Association, as agent and primary lender. The credit agreement provides us with a senior secured revolving credit facility that replaces our prior credit facility with KeyBank, which had a scheduled maturity date of July 31, 2007 and a borrowing base of $35 million. The new facility has a five-year maturity for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a current borrowing base of $50 million. The facility is secured by liens on our interests in most of our Appalachian wells. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from 1.5% to 2.5% above quoted LIBOR rates, depending on the amount of borrowing base utilization, plus commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. As of December 31, our outstanding borrowings under the facility aggregated $31 million, and the interest rate amounted to 8.5%.
Our ability to repay our bank debt and convertible notes will be subject to our future performance and prospects as well as market and general economic conditions. We will likely be dependent on additional financings to repay our outstanding long term debt at maturity.
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 continue attracting investment capital for drilling programs. The market price for natural gas is subject to wide fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of other factors that are beyond our control.
We expect our cash reserves, cash flows from operations and anticipated borrowing base availability under our credit facility to provide adequate working capital to meet our short-term capital expenditure objectives. To fully realize our financial goals for growth in revenues and reserves, we will continue to be dependent on the capital markets or other financing alternatives as well as continued participation by investors in future drilling programs.
Forward Looking Statements
Some statements made by us in this report are prospective and constitute forward-looking statements with in the meaning of Private Litigation Reform Act of 1995. 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;
•
increases in the cost of drilling, completion and gas collection or other costs of developing our reserves;
•
unavailability of drilling rigs and services;
•
uncertainty of production costs and estimates of required capital expenditures;
•
drilling, operational and environmental risks;
•
commodity price fluctuations;
•
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.
Financial Market Risk
Interest Rate Risk. Borrowing 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 borrowing 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.
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, 2006 under these instruments.
Related Party Transactions
Because we operate through 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 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 make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, management evaluates its estimates, including evaluations of any allowance for doubtful accounts and impairment of long-lived assets. Management bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. The results of these evaluations form a basis for making judgments 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 its estimates are reasonable and that actual results will not vary significantly from the estimated amounts. The following critical accounting policies relate to the more significant judgments and estimates used in the preparation of our consolidated financial statements.
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.
Impairment of Long-Lived Assets. Our long-lived assets include property and 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. We recognized impartment charges totaling $346,718 in the fourth quarter of 2006 for suspended exploratory well costs of $178,700 charged to expense and for abandonment of non-operated properties with a carrying value of $168,018.
Item 7A
Item 7A Quantitative Disclosure About Market Risk
None
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
Our management, with the participation or under the supervision of our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining disclosure controls and procedures and internal control over financial reporting for the Company in accordance with the requirements of the Exchange Act. Our disclosure controls and procedures are intended to provide a framework for making sure that all information required to be disclosed in our current and periodic reports under the Exchange Act is processed and publicly reported by us within the prescribed time periods for our filing of those reports. Our internal controls over financial reporting are designed to ensure the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. They include policies and procedures for maintaining reasonably detailed records that accurately and fairly reflect all our business transactions and dispositions of assets, for ensuring that receipts and expenditures are made only in accordance with management authorizations and for preventing or timely detecting any unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of our disclosure controls and procedures and our internal control over financial reporting as of December 31, 2006 Based on their evaluation, they 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 period required under the Exchange Act. They have also concluded that our internal controls over financial reporting are effective to ensure the reliability of our financial reporting and the preparation of our publicly reported financial statements in accordance with generally accepted accounting principles. Our independent registered public accounting firm, Hall, Kistler & Company LLP, has audited our assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, as stated in their report appearing on page.
There were no changes in our controls or procedures during 2006 that have materially affected or are reasonably likely to materially affect our internal control of 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 President of Daugherty Petroleum, Inc., our direct operating subsidiary (DPI), between 1984 and 2005 and as Chairman of the Board of DPI since September 2005. 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 is a past president of 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 the Company since 2004 and as a Vice President of DPI between 1993 and September 2005, when he was appointed as Chief Executive Officer of DPI. Mr. Barr has more than 30 years’ experience in the corporate and legal sectors of the oil and gas industry, having served in senior management positions in oil and gas exploration and production companies and as an attorney with 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-Elect of KOGA and as a member of its Board of Directors and Chairman of its Legislative Committee, as well as Vice Chairman of the Kentucky Gas Pipeline Authority. Mr. Barr received his Juris Doctorate from the University of Kentucky.
D. Michael Wallen has served as a Vice President of the Company since 1997 and as a Vice President of DPI between 1995 and September 2005, when he was appointed as President of DPI. For six years before joining DPI, he served as the Director of the Kentucky Division of Oil and Gas. Mr. Wallen has more than 25 years’ experience as a drilling and completion engineer for various exploration and production companies. He recently served as President of KOGA and currently serves on 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 from Morehead State University, Morehead, Kentucky.
Michael P. Windisch has served as our Chief Financial Officer since September 2002. Prior to that time, Mr. Windisch was employed by PricewaterhouseCoopers LLP, participating for five years in the firm’s audit practice. He is a member of the American Institute of Certified Public Accountants and holds a B.S. Degree from Miami University, Oxford, Ohio.
Incorporation of Information by Reference
The balance of Part III to this report is incorporated by reference to the proxy statement for our 2007 annual meeting of shareholders to be filed with the Securities and Exchange Commission on or before May 1, 2007.
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 13, 2007.
NGAS RESOURCES, INC.
By:
/s/ William S. Daugherty
William S. Daugherty,
By:
Michael P. Windisch
Michael P. Windisch,
President and Chief Executive Officer
Chief Financial Officer
(Principal executive officer)
(Principal financial and accounting officer)
In accordance with the Exchange Act, this report has been signed as of the date set forth below by the following persons in their capacity as directors of the NGAS Resources, Inc.
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, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment, management has concluded that, as of December 31, 2006, 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 our assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, as stated in their report appearing on page.
/s/ William S. Daugherty
William S. Daugherty,
/s/ Michael P. Windisch
Michael P. Windisch,
President and Chief Executive Officer
Chief Financial Officer
March 13, 2007
March 13, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
NGAS RESOURCES, INC.
We have audited management’s assessment, included in the accompanying Report of Management under the caption Management’s Report on Internal Control over Financial Reporting, that NGAS Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO criteria). Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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 included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control and performing such other procedures as we considered necessary in the circumstances. We believe 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 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, management’s assessment that NGAS Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, NGAS Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of NGAS Resources, Inc. and subsidiaries as of December 31, 2006 and the related consolidated statements of operations, shareholders’ equity and cash flows for the year ended December 31, 2006, and our report dated March 9, 2007 expressed an unqualified opinion thereon.
/s/ Hall, Kistler & Company LLP
Hall, Kistler & Company LLP
Canton, Ohio
March 9, 2007
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, 2006, and the related consolidated statements of operations, shareholders’ equity and cash flows for the year ended December 31, 2006. 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 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 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 provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of NGAS Resources, Inc. and subsidiaries as of December 31, 2006, and the consolidated results of its operations and its cash flows for the year ended December 31, 2006, 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, 2006, 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 9, 2007 expressed an unqualified opinion thereon.
/s/ Hall, Kistler & Company LLP
Hall, Kistler & Company LLP
Canton, Ohio
March 9, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of
NGAS RESOURCES, INC.
We have audited the consolidated balance sheet of NGAS RESOURCES, INC. as at December 31, 2005 and the consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and with generally accepted auditing standards in Canada. Those standards require that we plan and perform an audit to obtain reasonable assurance 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 that our audits provide a reasonable basis for our opinion.
In our opinion, these consolidated financial statements present fairly, in all material respects, the consolidated financial position of the company as at December 31, 2005 and the results of its operations, changes in shareholders’ equity and its cash flows for each of the years in the two-year period ended December 31, 2005 in conformity with accounting principles generally accepted in Canada.
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, 2005, 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 6, 2006 expressed an unqualified opinion thereon.
KRAFT BERGER LLP
Chartered Accountants
(Formerly Kraft, Berger, Grall, Schwartz, Cohen & March LLP)
Toronto, Ontario
March 12, 2007
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
December 31, 2006, 2005 and 2004
Note 1. Summary of Significant Accounting Policies
(a) General. The accompanying consolidated financial statements of NGAS Resources, Inc. (NGAS) 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 previously prepared our consolidated financial statements in accordance with accounting principles generally accepted in Canada (Canadian GAAP). The laws of British Columbia were recently changed to permit publicly held U.S. reporting companies organized in that jurisdiction to elect U.S. GAAP and engage U.S. auditors. We made this election at the beginning of 2006. 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.
(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 operates a gas transmission 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 by DPI. The consolidated financial statements also reflect DPI’s interests in a total of 34 drilling programs that it has sponsored to participate in its drilling operations. DPI maintains a combined interest as both general partner and an investor in the drilling program 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 its 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 basis, including passed 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, 2006, 2005 and 2004, gas transmission and compression revenue includes gas utility sales from Sentra’s regulated operations aggregating $273,180, $323,159 and $320,162, respectively. As of December 31, 2006, Sentra did not have any unrecovered purchased gas costs. If we stopped applying SFAS No. 71 to Sentra’s regulated operations, we would be required to write off its regulatory assets and adjust the carrying amount of any property and equipment used in those operations that we deemed unrecoverable.
(ii) NGAS Securities. NGAS Securities is a registered broker-dealer and member of the National Association of Securities Dealers, Inc. 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 one-eighth of its aggregate indebtedness. At December 31, 2006, NGAS Securities had a net capital deficit of $41,033, which was remedied after year end, and aggregate indebtedness of $50,922.
(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 note private placements and secured credit facility are initially capitalized and amortized at rates based on the stated 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, if the fair value of goodwill or other reporting unit is less than its carrying value, the implied fair value of the reporting unit must be compared with its carrying value to determine possible impairment.
(j) Customer Drilling Deposits. Net proceeds from under DPI’s drilling contracts with sponsored drilling programs are recorded as customers’ 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 have long term incentive agreements with five senior executive officers. The agreements entitle the officers to incentive awards equal to one year’s compensation if they continue to serve in their positions until February 25, 2009 or until their employment is terminated prior to that date without cause or they resign for good reason following a change of control. Accruals for deferred compensation under these agreements are recorded ratably based on estimated future payments dates and forfeiture rates.
(n) Reclassifications and Adjustments. Certain amounts included in the 2005 consolidated financial statements have been reclassified to conform to the 2006 presentation.
Note 2. Oil and Gas Properties
(a) Property Acquisitions and Divestitures.
(i) Acquisition of CBM Assets. In November 2005, we acquired coalbed methane interests in approximately 14,000 gross (3,500 net) acres within the Arkoma basin for $11.4 million. The acquired assets include a 25% interest in 48 producing wells. As part of the transaction, NGAS Gathering also acquired a 25% interest in a limited liability company that owns and operates the gathering system servicing the project area.
(ii) 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. The acquired system is open access, and the acquisition includes existing contracts for moving third-party gas. As of December 31, 2006, most of our Appalachian production is delivered through the system, with daily throughput of over 19,000 Dth of controlled and third-party gas directly from the wellhead to interstate pipelines.
(iii) 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.
(iv) 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, 2006 and 2005.
(c) Suspended Well Costs. We adopted FSP No. 19-1, Accounting for Suspended Well Costs, effective January 1, 2005. Based on our evaluation at the time of adoption, we had found proved reserves for all our exploratory wells within one-year after completion of drilling. We added suspended well costs late in 2005 and during 2006 for an exploratory program we sponsored to test the New Albany shale formation on acquired tracts in the Illinois basin spanning approximately 15,500 acres in western Kentucky. Based on the criteria of FSP No. 19-1, we expensed the suspended well costs for three wells in that program during 2006. The following table reflects the net changes in capitalized exploratory well costs during 2006, 2005 and 2004:
The following table provides an aging of capitalized exploratory well costs at December 31, 2006, 2005 and 2004, based on the date the drilling was completed. As of those dates, we had no wells for which exploratory wells costs had been capitalized for a period of greater 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, 2006 and 2005.
Note 4. Loans to Related Parties
Loans to related parties represent loans receivable from certain shareholders and officers. The loans are payable monthly from production revenues for periods ranging from five to ten years, with a balloon payment at maturity. The loans receivable from shareholders aggregated $93,148 at December 31, 2006 and $119,183 at December 31, 2005. They bear interest at 6% per annum and are collateralized by the related parties’ ownership interest in our drilling programs. The loans receivable from officers totaled $171,429 at December 31, 2006 and 2005. These loans are non-interest bearing and unsecured.
Note 5. Deferred Financing Costs
Financing costs for our convertible note private placements and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. These costs include $354,819 incurred in 2006 for our new credit facility. 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 $2,264,022 at December 31, 2006 and $2,377,791 at December 31, 2005, net of accumulated amortization totaling $922,324 and $378,736, respectively.
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, 2006 and 2005, with unamortized goodwill of $313,177.
Note 7. Customer Drilling Deposits
We sponsor and manage drilling programs to participate in our drilling initiatives, in which we maintain non-promoted interests ranging from 12.5% to 75%. Historically, we conducted drilling operations under turnkey contracts with our sponsored drilling programs, requiring us to drill and complete wells at specified prices and entitling us to any surplus if the contract price exceeded our costs. In 2006, we changed the structure of our new drilling programs from turnkey pricing to cost plus, with a view to reducing our exposure to price volatility for drilling services, equipment and steel casing requirements. Under both structures, net proceeds received under drilling contracts with sponsored programs are recorded as customers’ 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 aggregating $12,173,905 at December 31, 2006 and $23,627,975 at December 31, 2005 represent 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 issued several series of convertible notes in private placements to finance part of our drilling and acquisition activities. During 2005, the notes of all prior series were converted by their holders, either voluntarily or in response to our redemption calls, resulting in our issuance of 3,439,478 common shares during the year. In December 2005, we completed an institutional private placement of a new series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million, all of which remained outstanding at December 31, 2006, with a conversion price of $14.34, subject to adjustment for certain dilutive issuances of common stock. We also issued warrants in the transaction, which expired unexercised in August 2006. See Note 9 - Capital Stock.
The purchase agreement for our outstanding 6% notes provides holders with certain participation rights in future financing transactions. It also provides for a holder electing to convert a note before the second anniversary of the issuance date to a payment equal to the difference between two years’ interest on the converted note and the interest already paid on the note, unless the prevailing market price of our common stock exceeds 160% of the conversion price, payable at our option in cash or in common shares. After that date, if the prevailing market price of the common stock exceeds 160% of the conversion price, we may redeem any unconverted notes at a redemption price equal to their principal amount plus accrued and unpaid interest. Any notes that are neither redeemed nor converted prior to maturity will be repayable in cash or in common shares. Any common shares issued for interest payments on converted notes or upon redemption at their maturity will generally be valued for that purpose at 92.5% of their prevailing market price.
(b) Credit Facility. In September 2006, we entered into a credit agreement with KeyBank National Association, as agent and primary lender. The credit agreement provides DPI with a senior secured revolving credit facility that replaces its prior credit facility with KeyBank, which had a scheduled maturity date of July 31, 2007 and a borrowing base of $35 million. The new facility has a five-year maturity for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a borrowing base of $50 million at December 31, 2006. Under the terms of the credit agreement, outstanding borrowings bear interest at fluctuating rates ranging from the agent’s prime rate to 0.75% above that rate, depending on the amount of borrowing base utilization. Alternatively, we may elect Eurodollar based pricing from 1.5% to 2.5% above quoted LIBOR rates, depending on our borrowing base utilization. The credit agreement also provides for commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. As of December 31, 2006, outstanding borrowings under the facility aggregated $31 million, with $2 million in letters of credit. The facility is secured by liens on our interests in most of our producing wells. Obligations under the facility are guaranteed by NGAS.
(c) 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 net smelter returns or other production revenues, the property has remained inactive. The remaining acquisition debt was $342,818 at December 31, 2006 and $366,818 at December 31, 2005.
(d) Total Long Term Debt and Maturities. The following tables summarize our total long term debt at December 31, 2006 and 2005 and the principal payments due each year through 2010 and thereafter.
Maturities of Debt
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, 2006 or 2005.
(b) Common Shares. The following tables reflect transactions involving our common stock during the periods presented.
(c) Stock Options and Awards. We maintain three stock plans for the benefit of our directors, officers, employees and, in the case of the second and third plans, 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 2006 and 2005, stock awards and option grants were made under the third plan for a total of 65,945 shares and 834,415 shares, respectively. The following table shows transactions in stock options during 2006 and 2005.
At December 31, 2006, the exercise prices of options outstanding under our stock option plans ranged from $1.02 to $7.04 per share, and their weighted average remaining contractual life was 2.89 years. The following table provides additional information on the terms of stock options outstanding at December 31, 2006.
In accounting for stock options, we apply the fair value recognition provisions of SFAS No. 123(R), Share-Based Payment, which we adopted retroactively under its Canadian GAAP equivalent 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 4.5% to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from six months to five years based on the option’s vesting provisions. This resulted in non-cash charges for options and warrants of $975,468 in 2006 and $806,423 in 2005.
(d) Common Stock Purchase Warrants. We have issued common stock purchase warrants in various financing transactions. At December 31, 2006, we had outstanding warrants for the purchase of 10,000 common shares at $4.03 per share, all expiring on February 25, 2009. The following table shows transactions in common stock purchase warrants during 2006 and 2005.
Note 10. Income Taxes
The following table sets forth the components of income tax expense for each of the years presented in the consolidated financial statements.
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.
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.
As of December 31, 2006, we had net operating losses of $16,900,000 at the parent company level. Since no revenues are generated at that level for utilization of the related net operating loss carryforwards, we have provided a valuation allowance in the full amount of the net operating losses. The following table summarizes those net operating loss carryforwards by year of expiry.
Note 11. Income 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 $123,596 in 2006, $61,765 in 2005 and $61,407 in 2004.
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 partnership interest. DPI also maintains a 1% interest as general partner in each drilling program, resulting in a combined interest 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 for all wells to be drilled by that program. The portion of the profit on drilling contracts attributable to DPI’s ownership interest in the programs is eliminated on consolidation. The following table sets forth the total revenues recognized from the performance of these contracts with sponsored drilling programs for each of the years presented.
(c) Office Lease. During the first quarter of 2006, the building in Lexington, Kentucky that houses our principal and administrative offices was acquired by a company formed for that purpose by our four senior executive officers and a key employee. During the last several years prior to the sale, we had entered into several lease modifications for expansion of our offices, with additional expansion planned for 2006. 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, subject to annual escalations on the same terms as our existing lease. The lease modification was 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 new owner, and the terms for the additional office space 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, primarily located in the northeastern and central United States, during the normal course of business. We perform ongoing credit evaluations of customers’ financial condition and generally require no collateral. 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, 2006 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 two reportable segments based on management responsibility and key business operations. The summary of significant accounting policies in Note 1 applies to both reported segments. The following table presents summarized financial information for our business segments during each of the years presented in the consolidated financial statements.
Note 16. Commitments
We incurred lease rental expenses of $1,727,982 in 2006, $704,597 in 2005 and $475,060 in 2004. As of December 31, 2006, we have contractual obligations for periodic future payments under leases for field equipment and instruments governing its other commercial commitments in the amounts listed below.
(1)
Reflects obligations under a guaranty secured by a certificate of deposit provided for bank debt of Galax Energy Concepts, LLC, a limited liability company in which DPI previously held a minority interest.
(2)
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. 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 require 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
FSP No. 123(R)-4. In February 2006, the FASB issued FSP No. 123(R)-4, Classification of Options and Similar Instruments Issued as Employee Compensation that Allow for Cash Settlement upon the Occurrence of a Contingent Event. We do not have any stock options with a cash settlement feature, and our consolidated financial statements have not been affected by this guidance.
FIN No. 48. In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - Interpretation of FASB No. 109. FIN No. 48 requires us to recognize the impact of a tax position
on our financial statements if that position is more likely than not to be sustained on audit, based on the technical merits of the position. The provisions of FIN No. 48 are effective at the beginning of 2007, with the cumulative effect of any resulting change in accounting principle recorded as an adjustment to opening retained earnings. We are evaluating the impact of adoption FIN No. 48 and do not currently believe it will have a material affect on our consolidated financial statements.
SAB No. 108. In September 2006, the staff of the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year financial statement errors should be considered in quantifying a current year misstatement. For fiscal years ending after November 15, 2006, prior year errors must be quantified using both a balance sheet and income statement approach and evaluated based on relevant quantitative and qualitative factors in determining their materiality for disclosure purposes. Our application of this guidance has not had a material affect on our consolidated financial statements.
SFAS No. 157. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value and expands disclosure requirements about fair value measurements. The guidance in SFAS No. 157 applies to fair value measurements for derivatives and other financial instruments at initial recognition and in all subsequent periods. SFAS No. 157 is generally effective for all reporting periods during fiscal years beginning after November 15, 2007. We do not expect any material impact on our consolidated financial position or results of operations from adoption of this new standard.
SFAS No. 158. In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. SFAS No. 158 requires the employer to recognize the overfunded or underfunded status of any defined benefit postretirement plan as an asset or liability on its balance sheet and to recognize changes in that status through adjustments to comprehensive income. It also requires an employer to measure the funded status of a plan as of the date of its year-end balance sheet. These requirements are effective for fiscal years ending after December 15, 2006. The adoption of SFAS No. 158 has not had a material impact on our consolidated financial position, results of operations or cash flows and is not expected to have a material impact in future periods.
FSP AUG AIR-1. In September 2006, the FASB issued FSP AUG AIR-1, Accounting for Planned Major Maintenance Activities. FSP AUG AIR-1 prohibits companies from accruing the future costs of periodic major overhauls and maintenance of plant and equipment as a liability. The provisions of FSP AUG AIR-1 are effective for fiscal years beginning after December 15, 2006. We do not expect the implementation of these provisions to have a material impact on our consolidated financial statements.
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. For each of the years presented in the consolidated financial statements, our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves are summarized below.
(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, 2006, 2005 and 2004 are calculated using weighted average prices in effect as of those dates. Those prices were $6.15, $12.39 and $6.89, respectively, per Mcf of natural gas and $56.88, $54.65 and $43.23, respectively, per barrel of oil. 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, 2006.
(In thousands, except per share amounts)