UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2007
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File No. 0-16203
DELTA PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Delaware | 84-1060803 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
370 17th Street, Suite 4300 | ||
Denver, Colorado | 80202 | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code:(303) 293-9133
Securities registered under Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common Stock, $0.01 par value | The NASDAQ Stock Market, LLC |
Securities registered under to Section 12(g) of the Act:None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x | Accelerated filer o | Non-accelerated filero | Smaller reporting companyo | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
As of June 30, 2007, the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $1.27 billion, based on the closing price of the Common Stock on the NASDAQ National Market of $20.08 per share. As of February 29, 2008, 102,829,856 shares of registrant’s Common Stock, $.01 par value, were issued and outstanding.
Documents incorporated by reference: The information required by Part III of this Form 10-K is incorporated by reference to the Company’s Definitive Proxy Statement for the Company’s 2008 Annual Meeting of Stockholders.
TABLE OF CONTENTS
PAGE | ||||||
PART I | ||||||
Item 1. | BUSINESS | 4 | ||||
Item 1A. | RISK FACTORS | 11 | ||||
Item 1B. | UNRESOLVED STAFF COMMENTS | 22 | ||||
Item 2. | PROPERTIES | 22 | ||||
Item 3. | LEGAL PROCEEDINGS | 30 | ||||
Item 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS | 32 | ||||
Item 4A. | DIRECTORS AND EXECUTIVE OFFICERS | 33 | ||||
PART II | ||||||
Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | 36 | ||||
Item 6. | SELECTED FINANCIAL DATA | 37 | ||||
Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 37 | ||||
Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 58 | ||||
Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | 59 | ||||
Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | 59 | ||||
Item 9A. | CONTROLS AND PROCEDURES | 59 | ||||
Item 9B. | OTHER INFORMATION | 60 | ||||
PART III | ||||||
Item 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | 60 | ||||
Item 11. | EXECUTIVE COMPENSATION | 60 | ||||
Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | 60 | ||||
Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE | 60 | ||||
Item 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES | 60 | ||||
PART IV | ||||||
Item 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | 61 |
The terms “Delta,” “Company,” “we,” “our,” and “us” refer to Delta Petroleum Corporation and its subsidiaries unless the context suggests otherwise.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Except for statements of historical or present facts, all other statements contained in this Annual Report on Form 10-K are forward-looking statements. The forward-looking statements may appear in a number of places and include statements with respect to, among other things: business objectives and strategic plans; operating strategies; acquisition strategies; drilling wells; oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues); estimates of future production of oil and natural gas; expected results or benefits associated with recent acquisitions or drilling activities; marketing of oil and natural gas; expected future revenues and earnings, and results of operations; future capital, development and exploration expenditures (including the amount and nature thereof); our expectation that we will have adequate cash from operations and credit facility borrowings to meet future debt service, capital expenditure and working capital requirements in fiscal year 2008; nonpayment of dividends; expectations regarding competition and our competitive advantages; impact of the adoption of new accounting standards and our financial and accounting systems and analysis programs; and effectiveness of our internal control over financial reporting.
These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially. In some cases, information regarding certain important factors that could cause actual results to differ materially from any forward-looking statement appears together with such statement. In addition, the factors described under Critical Accounting Policies and Risk Factors, as well as other possible factors not listed, could cause actual results to differ materially from those expressed in forward-looking statements, including, without limitation, the following:
• | deviations in and volatility of the market prices of both crude oil and natural gas produced by us; | ||
• | the timing, effects and success of our acquisitions, dispositions and exploration and development activities; | ||
• | uncertainties in the estimation of proved reserves and in the projection of future rates of production; | ||
• | timing, amount, and marketability of production; | ||
• | third party curtailment, processing plant or pipeline capacity constraints beyond our control; | ||
• | our ability to find, acquire, market, develop and produce new properties; | ||
• | plans with respect to divestiture of oil and gas properties; | ||
• | effectiveness of management strategies and decisions; | ||
• | the strength and financial resources of our competitors; | ||
• | climatic conditions; | ||
• | changes in the legal and/or regulatory environment and/or changes in accounting standards policies and practices or related interpretations by auditors or regulatory entities; | ||
• | unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids; and | ||
• | our ability to fully utilize income tax operating loss and credit carry-forwards. |
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Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.
All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements above. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.
PART I
Item 1. Business
General
Delta Petroleum Corporation is an independent oil and gas company engaged primarily in the exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil. Our core areas of operation are the Rocky Mountain and onshore Gulf Coast Regions, which together comprise the majority of our proved reserves, production and long-term growth prospects. We have a significant development drilling inventory that consists of proved and unproved locations, the majority of which are located in our Rocky Mountain development projects.
We generally concentrate our exploration and development efforts in fields where we can apply our technical exploration and development expertise, and where we have accumulated significant operational control and experience. We also have an ownership interest in a drilling company, providing the benefit of priority access to 15 drilling rigs that operate primarily in the Rocky Mountain Region.
Delta was incorporated in Colorado in 1984. Effective January 31, 2006, Delta reincorporated in Delaware, thereby changing our state of incorporation from Colorado to Delaware. Our principal executive offices are located at 370 17th Street, Suite 4300, Denver, Colorado 80202. Our telephone number is (303) 293-9133. We also maintain a website at http://www.deltapetro.com which contains information about us. Our website is not part of this Form 10-K. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are accessible free of charge at our website.
Fiscal Year Change
On September 14, 2005, our Board of Directors approved the change of our fiscal year end from June 30 to December 31, effective December 31, 2005. This Form 10-K includes information for the years ended December 31, 2007 and 2006, the six-month transitional period ended December 31, 2005 and for the twelve-month period ended June 30, 2005. In this Form 10-K, when we refer to “fiscal 2008” we mean the twelve-month period ending December 31, 2008.
Overview and Strategy
Our focus is to increase stockholder value by pursuing our corporate strategy, as follows:
Pursue concurrent development of our core areas
We plan to spend $350.0-$370.0 million on our drilling program during 2008. We expect that approximately 88% of the 2008 drilling capital expenditures will be incurred in our Rocky Mountain development and exploration projects. Many of our targeted development drilling locations are in reservoirs that demonstrate predictable geologic attributes and consistent reservoir characteristics, which typically lead to reliable drilling results.
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Achieve consistent reserve growth through repeatable development
We have experienced significant reserve growth over the past four years through a combination of acquisitions and drilling successes. Although prior to 2006 the majority of our reserve and production growth came through acquisitions, in 2007 we achieved significant reserve and production increases as a result of our drilling program. We anticipate that the majority of our 2008 and future reserve and production growth will come through the execution of our drilling program on our large inventory of proved and unproved locations. Our development drilling inventory generally consists of locations in fields that demonstrate low variance in well performance, which leads to predictable and repeatable field development.
Our reserve estimates change continuously and we evaluate such reserve estimates on a quarterly basis, with independent engineering evaluation on an annual basis. Deviations in the market prices of both crude oil and natural gas and the effects of acquisitions, dispositions and exploratory development activities may have a significant effect on the quantities and future values of our reserves. Our reserves in the Rocky Mountain Region, where we plan to increasingly focus our drilling efforts and capital expenditures, are generally characterized as long-lived with low decline rates. We believe the balance of high-return Gulf Coast drilling and long-lived Rockies reserves will allow us to increase near term production rates and cash flow while building our reserve base and lengthening our average reserve life, which was 21.2 years as of December 31, 2007, based on 2007 production.
Maintain high percentage ownership and operational control over our asset base
As of December 31, 2007, we controlled approximately 871,000 net undeveloped acres, representing approximately 98% of our total net acreage position. We retain a high degree of operational control over our asset base, through a high average working interest or acting as the operator in our areas of significant activity. This provides us with controlling interests in a multi-year inventory of drilling locations, positioning us for continued reserve and production growth through our drilling operations. We plan to maintain this advantage to allow us to control the timing, level and allocation of our drilling capital expenditures and the technology and methods utilized in the planning, drilling and completion process. We believe this flexibility to opportunistically pursue exploration and development projects relating to our properties provides us with a meaningful competitive advantage. We also have a 50.0% interest in DHS Drilling Company (“DHS”), as well as a contractual right of priority access to DHS’ fifteen drilling rigs, which are deployed primarily in the Rocky Mountains.
Acquire and maintain acreage positions in high potential resource plays
We believe that our ongoing development of reserves in our core areas should be supplemented with exploratory efforts that may lead to new discoveries in the future. We continually evaluate our opportunities and pursue attractive potential opportunities that take advantage of our strengths. At December 31, 2007, we had significant undeveloped, unproved acreage positions in both the Columbia River Basin and the Central Utah Hingeline plays, each of which has gained substantial interest within the exploration and production sector due to their relatively unexplored nature and the potential for meaningful hydrocarbon recoveries. There are other mid-size and large independent exploration and production companies conducting drilling activities in these plays. We anticipate that meaningful drilling and completion results will become known in both areas during 2008.
Pursue a disciplined acquisition strategy in our core areas of operation
Historically we have been successful at growing through targeted acquisitions. Although our multi-year drilling inventory provides us with the opportunity to grow reserves and production organically without acquisitions, we continue to evaluate acquisition opportunities, primarily in our core areas of operation. In addition, we will continue to look to divest assets located in fully developed or non-core areas.
Maintain an active hedging program
We manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, typically costless collars. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy. We use hedges to limit the risk of fluctuating cash flows used to fund our capital expenditure program. We also typically use hedges in conjunction with acquisitions to achieve expected economic returns during the payout period. As of February 26, 2008 approximately 12.2 Bcfe of our anticipated production is hedged for 2008.
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Experienced management and operational team with advanced exploration and development technology
Our senior management team has over 25 years of experience in the oil and gas industry, and has a proven track record of creating value both organically and through strategic acquisitions. Our management team is supported by an active board of directors with extensive experience in the oil and gas industry. Our experienced technical staff utilizes sophisticated geologic and 3-D seismic models to enhance predictability and reproducibility over significantly larger areas than historically possible. We also utilize multi-zone, multi-stage artificial stimulation (“frac”) technology in completing our wells to substantially increase near-term production, resulting in faster payback periods and higher rates of return and present values. Our team has successfully applied these techniques, normally associated with completions in the most advanced Rocky Mountain natural gas fields, to our largest Gulf Coast field to improve initial and ultimate production and returns.
Recent Developments
On February 20, 2008, we consummated the sale of 36 million shares of our common stock to Tracinda Corporation (“Tracinda”) for $684.0 million. As a result of the transaction, Tracinda owns approximately 35% of our outstanding common stock and named two members to our Board of Directors, James J. Murren and Daniel J. Taylor, bringing the Board to 12 members. Tracinda has the right to proportional representation on our Board, and based on their current ownership may add up to three additional members at its discretion in the future. It also has a right to proportional representation on all of our Board committees.
Operations
During the year ended December 31, 2007, we were primarily engaged in two industry segments, namely the acquisition, exploration, development, and production of oil and natural gas properties and related business activities, and contract oil and natural gas drilling operations.
Oil and Gas Operations
The following table presents information regarding our primary oil and natural gas areas of operation as of December 31, 2007:
Proved | % | 2007 | ||||||||||||||
Reserves | Natural | % Proved | Production | |||||||||||||
Areas of Operations | (Bcfe)(1) | Gas | Developed | (MMcfe/d)(2) | ||||||||||||
Rocky Mountain Region | 288.8 | 90.3 | % | 25.8 | % | 19.3 | ||||||||||
Gulf Coast Region | 80.6 | 58.4 | % | 49.7 | % | 23.6 | ||||||||||
Offshore California | 2.0 | — | % | 100.0 | % | 2.4 | ||||||||||
Other | 4.2 | 37.9 | % | 72.7 | % | 3.4 | ||||||||||
Total | 375.6 | 82.4 | % | 31.8 | % | 48.7 | ||||||||||
(1) | Bcfe means billion cubic feet of gas equivalent | |
(2) | MMcfe/d means million cubic feet of gas equivalent per day |
We intend to focus our development on two of our primary areas of operation in the Rocky Mountain and onshore Gulf Coast Regions. For the year ending December 31, 2008, we estimate that our drilling capital budget will range between $350.0 — $370.0 million.
Our oil and gas operations have been comprised primarily of production of oil and natural gas, drilling exploratory and development wells and related operations and acquiring and selling oil and natural gas properties. Directly or through wholly-owned subsidiaries, and through Amber Resources Company of Colorado (“Amber”), our 91.68% owned subsidiary, CRB Partners, LLC (“CRBP”) and PGR Partners, LLC (“PGR”), we currently own producing and non-producing oil and natural gas interests, undeveloped leasehold interests and related assets in fifteen (15) states, interests in a producing Federal unit offshore California and undeveloped offshore Federal leases near Santa Barbara, California. We intend to continue our emphasis on the drilling of exploratory and development wells, primarily in Colorado, Utah, Texas and Wyoming.
We have oil and gas leases with governmental entities and other third parties who enter into oil and gas leases or assignments with us in the regular course of our business. We have no material patents, licenses, franchises or
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concessions that we consider significant to our oil and gas operations. The nature of our business is such that it is not seasonal, we do not engage in any research and development activities and we do not maintain or require a substantial amount of products, customer orders or inventory. Our oil and gas operations are not subject to renegotiations of profits or termination of contracts at the election of the federal government. We operate the majority of our properties and control the costs incurred. We have never been a debtor in any bankruptcy, receivership, reorganization or similar proceeding.
Contract Drilling Operations
Through a series of transactions in 2004 and 2005, we acquired and now own an interest in DHS, an affiliated Colorado corporation that is headquartered in Casper, Wyoming. During the second quarter of 2006, DHS engaged in a reorganization transaction pursuant to which it became a subsidiary of DHS Holding Company, a Delaware corporation, and the Company’s ownership interest became an interest in DHS Holding Company. References to DHS herein shall be deemed to include both DHS Holding Company and DHS, unless the context otherwise requires. DHS is a consolidated entity of Delta. Delta currently owns a 50.0% interest in DHS Holding Company, controls the board of directors of DHS and has priority access to all of DHS’ drilling rigs for Company use and operations.
At December 31, 2007, DHS owned 15 drilling rigs with depth ratings of approximately 10,000 to 20,000 feet. We have the right to use all of the rigs on a priority basis, although approximately half are currently working for third party operators.
The following table presents our average drilling revenue per day and rigs available for service for the years ended December 31, 2007 and 2006:
Years Ended December 31, | ||||||||
2007 | 2006 | |||||||
Average number of rigs owned during period | 16.7 | 12.3 | ||||||
Total rig days available1 | 5,020 | 4,482 | ||||||
Average drilling revenue per day | $ | 16,919 | $ | 16,747 |
1 Total rig days available includes the number of days each rig was either under contract or available for contract. |
DHS also owns 100% of Chapman Trucking, which was acquired in November 2005. Employing its 28 trucks and 38 trailers, Chapman ensures DHS rig mobility and provides moving services for third party drilling rigs. Chapman Trucking continues to market trucking services in the Casper, Wyoming area.
Contracts — Drilling
We earn our DHS contract drilling revenues under daywork or turnkey contracts which vary depending upon the rig employed, equipment and services supplied, geographic location, term of the contract, competitive conditions and other variables. Our contracts generally provide for a basic dayrate during drilling operations, with lower rates or no payment for periods of equipment breakdown. When a rig is mobilized or demobilizes from an operating area, a contract may provide for different dayrates during the mobilization or demobilization. Turnkey contracts are accounted for on a percentage-of-completion basis. Contracts to employ our drilling rigs have a term based on a specified period of time or the time required to drill a specified well or number of wells. The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal. Most contracts permit the customer to terminate the contract at the customer’s option without paying a termination fee.
Markets
The principal products produced by us are crude oil and natural gas. The products are generally sold at the wellhead to purchasers in the immediate area where the product is produced. The principal markets for oil and natural gas are refineries and transmission companies which have facilities near our producing properties.
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DHS’s principal market is the drilling of oil and natural gas wells for us and others in the Rocky Mountain and onshore Gulf Coast Regions. To the extent that DHS rigs are not fully utilized by us, DHS typically contracts with other oil and gas companies on a single-well basis, with extensions.
Distribution
Oil and natural gas produced from our wells are normally sold to various purchasers as discussed below. Oil is picked up and transported by the purchaser from the wellhead. In some instances we are charged a fee for the cost of transporting the oil which is deducted from or accounted for in the price paid for the oil. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges is usually included in the calculation of the price paid for the natural gas.
Competition
We encounter strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and the development and production of, natural gas and crude oil. Competition is particularly intense with respect to the acquisition of desirable undeveloped oil and gas leases. The principal competitive factors in the acquisition of undeveloped oil and gas leases include the availability and quality of staff and data necessary to identify, investigate and purchase such leases, and the financial resources necessary to acquire and develop such leases. Many of our competitors have substantially greater financial resources, and more fully developed staffs and facilities than ours. In addition, the producing, processing and marketing of natural gas and crude oil are affected by a number of factors which are beyond our control, the effect of which cannot be accurately predicted. See “Item 1A. Risk Factors.”
To the extent that the DHS drilling rigs are not fully utilized by us for any reason, DHS drills wells for our competitors in the oil and gas business in order to achieve revenues to sustain its operations. To a large degree, the success of DHS’s business is dependent upon the level of capital spending by oil and gas companies for exploration, development and production activities. A sustained increase or decrease in the price of natural gas or oil could have a material impact on exploration, development, and production activities by all of DHS’s customers, including us, and could also materially affect its financial position, results of operations and cash flows.
Raw Materials
The principal raw materials and resources necessary for the exploration and development of natural gas and crude oil are leasehold prospects under which natural gas and oil reserves may be discovered, drilling rigs and related equipment to drill for and produce such reserves and knowledgeable personnel to conduct all phases of gas and oil operations. Although equipment and supplies used in our business are usually available from multiple sources, there is currently a general shortage of drilling equipment and supplies. We believe that these shortages are likely to intensify. The costs and delivery times of equipment and supplies are substantially greater now than in prior periods and are currently escalating. In partial response to this trend, we engaged in a series of transactions during 2004 and 2005 which resulted in our current ownership interest in DHS which provides us with priority access to a fleet of 15 drilling rigs. We have also established arrangements via joint ventures to assure adequate availability of certain other necessary drilling equipment such as tubulars, pipe, frac tanks and supplies on satisfactory terms. There can be no assurance that these arrangements will prevent us from experiencing shortages of, or material price increases in, drilling equipment and supplies, including drill pipe, in the future. Any such shortages could delay and adversely affect our ability to complete or the economics of our planned drilling projects.
Major Customers
During the year ended December 31, 2007, we had two companies that individually accounted for 27% and 13% of our total oil and gas sales. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business as other customers or markets would be accessible to us. See Footnote 16 to our consolidated financial statements for additional information.
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During 2007, DHS had one major customer other than Delta. Absent a sustained decrease in the price of natural gas or oil as discussed above, we do not believe the loss of any one or several customers would have a material adverse effect on DHS.
Government Regulation of the Oil and Gas Industry
General
Our business is affected by numerous federal, state and local laws and regulations, including those relating to protection of the environment, public health, and worker safety. The technical requirements of these laws and regulations are becoming increasingly expensive, complex, and stringent. Non-compliance with these laws and regulations may result in imposition of substantial liabilities, including civil and criminal penalties. In addition, certain laws impose strict liability for environmental remediation and other costs. Changes in any of these laws and regulations could have a material adverse effect on our business. In light of the many uncertainties with respect to future laws and regulations, we cannot predict the overall effect of such laws and regulations on our future operations. Nevertheless, the trend in environmental regulation is to place more restrictions and controls on activities that may affect the environment, and future expenditures for environmental compliance or remediation may be substantially more than we expect.
We believe that our operations comply in all material respects with all applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. Accidental leaks and spills requiring cleanup may occur in the ordinary course of business, and the costs of preventing and responding to such releases are embedded in the normal costs of doing business. In addition to the costs of environmental protection associated with our ongoing operations, we may incur unforeseen investigation and remediation expenses at facilities we formerly owned and operated or at third-party owned waste disposal sites that we have used. Such expenses are difficult to predict and may arise at sites operated in compliance with past industry standards and procedures.
The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.
Environmental regulation
Our operations are subject to numerous federal, state, and local environmental laws and regulations concerning our oil and gas operations, products and other activities. In particular, these laws and regulations govern, among other things, the issuance of permits associated with exploration, drilling and production activities, the types of activities that may be conducted in environmentally protected areas such as wetlands and wildlife habitats, the release of emissions into the atmosphere, the discharge and disposal of regulated substances and waste materials, offshore oil and gas operations, the reclamation and abandonment of well and facility sites, and the remediation of contaminated sites.
Governmental approvals and permits are currently, and will likely in the future be, required in connection with our operations, and in the construction and operation of gathering systems, storage facilities, pipelines and transportation facilities (midstream operations). The success of obtaining, and the duration of, such approvals are contingent upon a significant number of variables, many of which are not within our control, or those of others involved in midstream operations. To the extent such approvals are required and not granted, operations may be delayed or curtailed, or we may be prohibited from proceeding with planned exploration or operation of facilities.
Environmental laws and regulations are expected to have an increasing impact on our operations, although it is impossible to predict accurately the effect of future developments in such laws and regulations on our future earnings and operations. Some risk of environmental costs and liabilities is inherent in our operations and products, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred; however, we do not currently expect any material adverse effect upon our results of operations or financial position as a result of compliance with such laws and regulations.
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Although future environmental obligations are not expected to have a material adverse effect on our results of operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur substantial environmental liabilities or costs.
Because we are engaged in acquiring, operating, exploring for and developing natural resources, in addition to federal laws we are subject to various state and local provisions regarding environmental and ecological matters. Compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. At the present time, these laws do not have a material adverse effect on our business. However, during 2007, the state of Colorado, in which we conduct a significant portion of our business and have the majority of our drilling capital budgeted for 2008, passed legislation which requires the Colorado Oil and Gas Conservation Commission (“COGCC”) to promulgate new regulations to facilitate the inclusion of certain other public agencies, including the Colorado Department of Public Health and the Environment, and the Colorado Division of Wildlife, in the COGCC decision making processes related to oil and gas development which includes the permitting of new wells and establishing regulations to prevent or mitigate environmental impacts of oil and gas development. Although we do not anticipate that expenditures to comply with existing environmental laws in any of the areas that we operate will change materially during 2008, we cannot be certain as to the nature and impact any new statutes implemented in Colorado or in other states in which we conduct our business may have on our operations.
Hazardous substances and waste disposal
We currently own or lease interests in numerous properties that have been used for many years for natural gas and crude oil production. Although the operator of such properties may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us. In addition, some disposal sites that we have used have been operated by third parties over whom we had no control. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict joint and several liability on current and former owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the management and disposal of wastes. Although CERCLA currently excludes petroleum from cleanup liability, many state laws affecting our operations impose clean-up liability regarding petroleum and petroleum-related products.
In addition, although RCRA currently classifies certain exploration and production wastes as “non-hazardous,” such wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements. If such a change were to occur, it could have a significant impact on our operating costs, as well as on the oil and gas industry in general.
Oil spills
The federal Clean Water Act (“CWA”) and the federal Oil Pollution Act of 1990, as amended (“OPA”), impose significant penalties and other liabilities with respect to oil spills that damage or threaten navigable waters of the United States. Under the OPA, (i) owners and operators of onshore facilities and pipelines, (ii) lessees or permittees of an area in which an offshore facility is located and (iii) owners and operators of tank vessels (“Responsible Parties”) are strictly liable on a joint and several basis for removal costs and damages that result from a discharge of oil into the navigable waters of the United States. These damages include, for example, natural resource damages, real and personal property damages and economic losses. OPA limits the strict liability of Responsible Parties for removal costs and damages that result from a discharge of oil to $350.0 million in the case of onshore facilities, $75.0 million plus removal costs in the case of offshore facilities, and in the case of tank vessels, an amount based on gross tonnage of the vessel; however, these limits do not apply if the discharge was caused by gross negligence or willful misconduct, or by the violation of an applicable Federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor or in certain other circumstances. To date, we have not had any such material spills.
In addition, with respect to certain offshore facilities, OPA requires evidence of financial responsibility in an amount of up to $150.0 million. Tank vessels must provide such evidence in an amount based on the gross tonnage of the
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vessel. Failure to comply with these requirements or failure to cooperate during a spill event may subject a Responsible Party to civil or criminal enforcement actions and penalties.
Under our various agreements, we have primary liability for oil spills that occur on properties for which we act as operator. With respect to properties for which we do not act as operator, we are generally liable for oil spills to the extent of our interest as a non-operating working interest owner.
Offshore production
Offshore oil and gas operations in U.S. waters are subject to regulations of the United States Department of the Interior, Mineral Management Service (“MMS”), which currently impose strict liability upon the lessee under a federal lease for the cost of clean-up of pollution resulting from the lessee’s operations. As a result, such a lessee could be subject to possible liability for pollution damages. In the event of a serious incident of pollution, the Department of the Interior may require a lessee under federal leases to suspend or cease operations in the affected areas.
We do not act as operator for any of our offshore California properties. The operators of our offshore California properties are primarily liable for oil spills and are required by MMS to carry certain types of insurance and to post bonds in that regard. There is no assurance that applicable insurance coverage is adequate to protect us.
Abandonment Obligations
We are responsible for costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on our oil and natural gas properties according to our pro rata ownership. We follow the accounting required by the Statement of Financial Accounting Standard (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. We had a discounted asset retirement obligation of approximately $5.2 million at December 31, 2007. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates and changes to environmental laws and regulations. Estimated asset retirement obligations are added to net unamortized historical oil and gas property costs for purposes of computing depreciation, depletion and amortization expense charges.
Employees
At December 31, 2007 we had approximately 128 full-time employees. Additionally, certain operators, engineers, geologists, geophysicists, landmen, pumpers, draftsmen, title attorneys and others necessary for our operations are retained on a contract or fee basis as their services are required.
Item 1A. Risk Factors.
An investment in our securities involves a high degree of risk. You should carefully read and consider the risks described below before deciding to invest in our securities. The occurrence of any such risks may materially harm our business, financial condition, results of operations or cash flows. In any such case, the trading price of our common stock and other securities could decline, and you could lose all or part of your investment. When determining whether to invest in our securities, you should also refer to the other information contained or incorporated by reference in this Annual Report onForm 10-K, including our consolidated financial statements and the related notes.
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Risks Related To Our Business And Industries.
Oil and natural gas prices are volatile, and a decrease could adversely affect our revenues, cash flows, profitability, access to capital and ability to grow.
Our revenues, profitability and future rate of growth depend substantially upon the prices we receive for the oil and natural gas we sell, which fluctuate widely. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow under our credit facility is subject to periodic re-determinations or our reserves based on prices specified by our bank group at the time of re-determination. Sustained declines in oil and gas prices may adversely affect our financial condition, liquidity and results of operations. Factors that can cause market prices of oil and natural gas to fluctuate include:
• | relatively minor changes in the supply of and demand for oil and natural gas; | |
• | market uncertainty; | |
• | the level of consumer product demand; | |
• | weather conditions; | |
• | the proximity and capacity of natural gas pipelines and other transportation facilities; | |
• | U.S. and foreign governmental regulations; | |
• | the price and availability of alternative fuels; | |
• | political and economic conditions in oil producing countries, particularly those in the Middle East, including actions by the Organization of Petroleum Exporting Countries; | |
• | the foreign supply of oil and natural gas; and | |
• | the price of oil and natural gas imports, consumer preferences and overall U.S. and foreign economic conditions. |
We are not able to predict future oil and natural gas prices. At various times, excess domestic and imported supplies have depressed oil and natural gas prices. Lower prices may reduce the amount of oil and natural gas that we can produce economically and may also require us to write down the carrying value of our oil and gas properties. Additionally, the location of our producing wells may limit our ability to take advantage of spikes in regional demand and the resulting increase in price. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices, not long-term fixed price contracts. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, results of operations and ability to grow.
We may not be able to fund our planned capital expenditures or acquisition activities.
We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and natural gas reserves. Our drilling capital budget is expected to range between $350.0 and $370.0 million for the year ending December 31, 2008. We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, borrowings under bank credit facilities, the issuance of equity and debt securities and the sale of non-core assets. We received $684.0 million in gross proceeds from the issuance of 36 million shares to Tracinda Corporation in February 2008 which provides us significant flexibility to execute our plans. Without adequate financing, we may not be able to fully execute our operating and acquisition strategy in the timetable desired or pursue other opportunities. We continually examine the following sources of capital to supplement cash flow from operations, existing availability under our credit facility, and cash on hand:
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• | bank borrowings or the issuance of debt securities; | |
• | the issuance of common stock, preferred stock or other equity securities; | |
• | divestiture of non-core properties; and | |
• | joint ventures and similar arrangements. |
The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices and our market value, the success of our exploration and development activities and operating performance. We may be unable to execute our operating strategy if we cannot obtain adequate capital if low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program. In addition, if our borrowing base under our credit facility is re-determined to a lower amount, this could adversely affect our ability to fund our planned capital expenditures through borrowings under our credit facility. After utilizing such sources of financing, we may be forced to raise additional capital through the issuance of equity or debt securities to fund such expenditures. Additional equity or debt financing may not be available to meet our capital expenditure requirements or may only be available on terms dilutive to our existing investors.
Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our senior unsecured notes.
As of December 31, 2007, our total outstanding long term liabilities were $426.1 million, with $73.6 million of outstanding borrowings drawn under our credit facility. Our long term indebtedness represented 45% of our total book capitalization at December 31, 2007. As of December 31, 2007, we had $49.9 million additional availability under our credit facility. However, using a portion of the proceeds from our February 2008 equity issuance, we paid down our credit facility to zero. Our 7% senior notes indenture currently limits our incurrence of secured borrowings to $130.0 million. Our degree of leverage could have important consequences, including the following:
• | it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes; | |
• | a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities; | |
• | the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations; | |
• | certain of our borrowings, including borrowings under our senior credit facility, are at variable rates of interest, exposing us to the risk of increased interest rates; | |
• | as we have pledged most of our oil and natural gas properties and the related equipment, inventory, accounts and proceeds as collateral for the borrowings under our senior credit facility, they may not be pledged as collateral for other borrowings and would be at risk in the event of a default thereunder; | |
• | it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that have less debt; | |
• | we may be vulnerable in a downturn in general economic conditions or in our business, or we may be unable to carry out capital spending and exploration activities that are important to our growth; and | |
• | we may from time to time fail to be in compliance with covenants under our credit facility, which will require us to seek waivers from our banks. |
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We may, under certain circumstances described in the indenture governing our 7% senior notes and our senior credit facility, be able to incur substantially more debt in the future, which may intensify the risks described herein.
Information concerning our reserves is uncertain.
There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of oil and natural gas reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and natural gas prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities, oil and natural gas prices and regulatory changes. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from our assumptions and estimates. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data.
The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2007 and 2006, the six months ended December 31, 2005 and the fiscal year ended June 30, 2005 included in our periodic reports filed with the SEC were prepared by our independent reserve engineers in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. As required by the SEC, the estimated discounted present value of future net cash flows from proved reserves is generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. In addition, the 10% discount factor, which the SEC requires to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general. Based on our proved reserves at December 31, 2007, a 10% increase or decrease in oil and gas price used would increase or decrease our proved reserve quantities at that date by approximately +/- 2% and our PV10 by approximately +/- 20%.
We may not be able to replace production with new reserves.
Our reserves will decline significantly as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves that are economically feasible and developing existing proved reserves. During the year ended December 31, 2007, our proved reserve replacement rate was 512% (calculated by dividing our total proved reserve changes for the period by our total production for the same period as detailed in Footnote 17 to the accompanying financial statements). These reserve additions were primarily the result of successful developmental and exploratory drilling during 2007 which resulted primarily in proved undeveloped reserve additions mainly in the Rocky Mountain Region.
Exploration and development drilling may not result in commercially productive reserves.
We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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• | increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment; | |
• | unexpected drilling conditions; | |
• | title problems; | |
• | pressure or irregularities in formations; | |
• | equipment failures or accidents; | |
• | adverse weather conditions; and | |
• | compliance with environmental and other governmental requirements. |
If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, we may be required to take writedowns.
In the past, we have been required to write down the carrying value of our oil and gas properties. There is a risk that we will be required to take additional writedowns in the future, which would reduce our earnings and stockholders’ equity. A writedown could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration and development results.
We account for our crude oil and natural gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. If the carrying amount of our oil and gas properties exceeds the estimated undiscounted future net cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value.
We review our oil and gas properties for impairment quarterly or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a writedown of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded carrying values associated with our oil and gas properties.
During the year ended December 31, 2007, impairments of $58.4 million were recorded primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 million and $10.3 million, respectively), and the South Angleton field in Texas ($9.7 million), primarily due to lower Rocky Mountain natural gas prices and marginally economic deep zones on the Howard Ranch Prospect.
During the year ended December 31, 2006, an impairment of $10.4 million was recorded on certain of the Company’s eastern Colorado properties primarily due to lower Rocky Mountain natural gas prices. In addition, an impairment of $1.0 million was recorded on certain Oklahoma properties. For 2008, we are continuing to develop and evaluate certain properties on which favorable or unfavorable results or commodity prices may cause us to revise in future years our estimates of those properties’ future cash flows. Such revisions of estimates could require us to record an impairment in the period of such revisions.
During 2007, we recorded dry hole costs for three wells located in Texas, two wells in Wyoming, one well in Colorado and one well in Utah totaling approximately $26.7 million. During 2006, we recorded a dry hole for our first Hingeline well in Central Utah ($2.4 million) and for several other unsuccessful non-operated projects ($1.9 million).
At December 31, 2007, we had $44.1 million classified as work in process related to exploratory projects. During 2008, these costs will be capitalized as successful wells if proved reserves are found or expensed as dry holes based on final drilling results.
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The exploration, development and operation of oil and gas properties involve substantial risks that may result in a total loss of investment.
The business of exploring for and, to a lesser extent, developing and operating oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
• | unexpected drilling conditions; | |
• | pressure or irregularities in formations; | |
• | equipment failures or accidents; | |
• | adverse changes in prices; | |
• | weather conditions; | |
• | shortages in experienced labor; and | |
• | shortages or delays in the delivery of equipment. |
The cost to develop our proved reserves as of December 31, 2007 is estimated to be approximately $585.6 million. We may drill wells that are unproductive or, although productive, do not produce oil and/or natural gas in economic quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.
The marketability of our production depends mostly upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities, which are owned by third parties.
The marketability of our production depends upon the availability, operation and capacity of gas gathering systems, pipelines and processing facilities, which are owned by third parties. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. We currently own several wells that are capable of producing but are currently shut-in pending the construction of gas gathering systems, pipelines and processing facilities. United States federal, state and foreign regulation of oil and gas production and transportation, tax and energy policies, damage to or destruction of pipelines, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors changed dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.
Prices may be affected by regional factors.
The prices to be received for the natural gas production from our Rocky Mountain Region properties, where we are conducting a substantial portion of our development activities, will be determined to a significant extent by factors affecting the regional supply of and demand for natural gas, which include the degree to which pipeline and processing infrastructure exists in the region. Those factors result in basis differentials between the published indices
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generally used to establish the price received for regional natural gas production and the actual (frequently lower) price we receive for our production.
Our industry experiences numerous operating hazards that could result in substantial losses.
The exploration, development and operation of oil and gas properties also involve a variety of operating risks including the risk of fire, explosions, blowouts, cratering, pipe failure, abnormally pressured formations, natural disasters, acts of terrorism or vandalism, and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. These industry-operating risks can result in injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial losses.
We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. Terrorist attacks and certain potential natural disasters may change our ability to obtain adequate insurance coverage. The occurrence of a significant event that is not fully insured or indemnified against could materially and adversely affect our financial condition and operations.
Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of evaluating recoverable reserves and potential liabilities.
We could be subject to significant liabilities related to acquisitions by us. The successful acquisition of producing and non-producing properties requires an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. Further, even a detailed review of all properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed. We cannot assure you that our recent and/or future acquisition activity will not result in disappointing results.
In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing or regulatory approvals.
Acquisitions often pose integration risks and difficulties. In connection with recent and future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.
We depend on key personnel.
We currently have only four employees that serve in senior management roles. In particular, Roger A. Parker and John R. Wallace are responsible for the operation of our oil and gas business, Kevin K. Nanke is our Treasurer and Chief Financial Officer, and Stanley F. Freedman is our Executive Vice President, General Counsel and Secretary. The loss of any one of these employees could severely harm our business. We do not have key man insurance on the lives of any of these individuals. Furthermore, competition for experienced personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.
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We may not be permitted to develop some of our offshore California properties or, if we are permitted, the substantial cost to develop these properties could result in a reduction of our interest in these properties or cause us to incur penalties.
Certain of our offshore California undeveloped properties, in which we have ownership interests ranging from 2.49% to 100.00%, are attributable to our interests in four of our five federal units (plus one additional lease) located offshore of California near Santa Barbara. These properties had a cost basis of approximately $14.8 million at December 31, 2007. The development of these properties is subject to extensive regulation and is currently the subject of litigation. Further actions to develop these properties have been delayed pending the outcome of a lawsuit that was filed in the United States Court of Federal Claims in Washington, D.C. by us, our 92%-owned subsidiary, Amber Resources Company of Colorado, and ten other property owners alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. None of these leases is currently impaired, but in the event that they are found not to be valid for some reason, in the future it would appear that they would become impaired. For example, if there is a future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and we decide not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear our appeal of any such ruling or ultimately makes an adverse determination, it is likely that some or all of these leases would become impaired and written off at that time. It is also possible that other events could occur that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur.
In addition, the cost to develop these properties will be substantial. The cost to develop all of the offshore California properties in which we own an interest, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated to be in excess of $3.0 billion. Our share of such costs, based on our current ownership interest, is estimated to be over $200.0 million. Operating expenses for the same properties over the same period of time, including platform operating costs, well maintenance and repair costs, oil, gas and water treating costs, lifting costs and pipeline transportation costs, are estimated to be approximately $3.5 billion, with our share, based on our current ownership interest, estimated to be approximately $300.0 million. There will be additional costs of a currently undetermined amount to develop the Rocky Point Unit. Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. If we are unable to fund our share of these costs or otherwise cover them through farm-outs or other arrangements, then we could either forfeit our interest in certain wells or properties or suffer other penalties in the form of delayed or reduced revenues under our various unit operating agreements, which could impact the ultimate realization of this investment. The estimates discussed above may differ significantly from actual results.
We are exposed to additional risks through our drilling business.
We currently have a 50.0% ownership interest in and management control of a drilling business. The operations of that entity are subject to many additional hazards that are inherent to the drilling business, including, for example, blowouts, cratering, fires, explosions, loss of well control, loss of hole, damaged or lost drill strings and damage or loss from inclement weather. No assurance can be given that the insurance coverage maintained by that entity will be sufficient to protect it against liability for all consequences of well disasters, personal injury, extensive fire damage or damage to the environment. No assurance can be given that the drilling business will be able to maintain adequate insurance in the future at rates it considers reasonable or that any particular types of coverage will be available. The occurrence of events, including any of the above-mentioned risks and hazards that are not fully insured, could subject the drilling business to significant liability. It is also possible that we might sustain significant losses through the operation of the drilling business even if none of such events occurs.
Hedging transactions may limit our potential gains or cause us to lose money.
In order to manage our exposure to price risks in the marketing of oil and gas, we periodically enter into oil and gas price hedging arrangements, typically costless collars. While intended to reduce the effects of volatile oil and gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
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• | production is substantially less than expected; | |
• | the counterparties to our futures contracts fail to perform under the contracts; or | |
• | a sudden, unexpected event materially impacts gas or oil prices. |
The net gains (losses) from effective hedging activities recognized in our statements of operations were $12.9 million, ($4.7 million), ($3.4 million), and ($630,000) for the years ended December 31, 2007, 2006, six months ended December 31, 2005 and year ended June 30, 2005, respectively. These gains and losses are recorded as an increase or decrease in revenues. At December 31, 2007, we had a hedging loss liability of $3.4 million reflected in our consolidated balance sheet based on market prices in effect on December 31, 2007. Our actual hedging results may differ materially from the amount recorded at December 31, 2007.
We may not receive payment for a portion of our future production.
Our revenues are derived principally from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. We do not attempt to obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict, however, what impact the financial difficulties of any of our purchasers may have on our future results of operations and liquidity.
We have no long-term contracts to sell oil and gas.
We do not have any long-term supply or similar agreements with governments or other authorities or entities for which we act as a producer. We are therefore dependent upon our ability to sell oil and gas at the prevailing wellhead market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable.
There is currently a shortage of available drilling rigs and equipment which could cause us to experience higher costs and delays that could adversely affect our operations.
Although equipment and supplies used in our business are usually available from multiple sources, there is currently a general shortage of drilling equipment and supplies. We believe that these shortages are likely to intensify. The costs and delivery times of equipment and supplies are substantially greater now than in prior periods and are currently escalating. In partial response to this trend, during 2004 and 2005 we acquired a controlling interest in a drilling company. Our ownership interest in the drilling company allows us to have priority access to drilling rigs. We have also established arrangements via joint ventures to assure adequate availability of certain other necessary drilling equipment such as tubulars, pipe, frac tanks and supplies on satisfactory terms. There can be no assurance that these arrangements will prevent us from experiencing shortages of, or material price increases in, drilling equipment and supplies, including drill pipe, in the future. Any such shortages could delay and adversely affect our ability to complete or the economics of our planned drilling projects.
Our industry is highly competitive, making our results uncertain.
We operate in the highly competitive areas of oil and gas exploration, development and production. We compete for the purchase of leases from the U.S. government and from other oil and gas companies. These leases include exploration prospects as well as properties with proved reserves. We face competition in every aspect of our business, including, but not limited to:
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• | acquiring reserves and leases; | |
• | obtaining goods, services and employees needed to operate and manage our business; | |
• | access to the capital necessary to drill wells and acquire properties; and | |
• | marketing oil and natural gas. |
Competitors include multinational oil companies, independent production companies and individual producers and operators. Many of our competitors have greater financial, technological and other resources than we do.
New technologies may cause our current exploration and drilling methods to become obsolete, resulting in an adverse effect on our production.
The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete, and we may be adversely affected.
Terrorist attacks aimed at our facilities could adversely affect our business.
The United States has been the target of terrorist attacks of unprecedented scale. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our business.
We own properties in the Gulf Coast Region that could be susceptible to damage by severe weather.
Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our properties in the Gulf Coast Region are located in areas that could cause them to be susceptible to damage by these storms. Damage caused by high winds and flooding could potentially cause us to curtail operations and/or exploration and development activities on such properties for significant periods of time until damage can be repaired. Moreover, even if our properties are not directly damaged by such storms, we may experience disruptions in our ability to sell our production due to damage to pipelines, roads and other transportation and refining facilities in the area.
We may incur substantial costs to comply with the various federal, state and local laws and regulations that affect our oil and gas operations.
Our oil and gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to health and safety, land use, environmental protection or the oil and gas industry generally. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Compliance with such laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory or remedial obligations, or issuance of cease and desist orders.
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The environmental laws and regulations to which we are subject may:
• | require applying for and receiving a permit before drilling commences; | |
• | restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; | |
• | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and | |
• | impose substantial liabilities for pollution resulting from our operations. |
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Over the years, we have owned or leased numerous properties for oil and gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA and analogous state laws, we could be held strictly liable for the removal or remediation of previously released materials or property contamination at such locations regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.
Risks Related To Our Stock.
Our largest stockholder has the power to significantly influence the future of our Company.
As of February 20, 2008, our largest stockholder, Tracinda Corporation, beneficially owned 36,128,000 shares of our common stock, or approximately 35% of the outstanding shares of our common stock. Pursuant to the Company Stock Purchase Agreement that we entered into with Tracinda Corporation on December 29, 2007, Tracinda Corporation has certain rights, including the right to designate five members (33%) of our Board of Directors (which number will increase if, after February 20, 2009, Tracinda Corporation increases its percentage ownership of Delta), preemptive rights in connection with future equity issuances by us, and consent rights over certain types of actions. Further, while Tracinda Corporation may not acquire more than 49% of our outstanding common stock until February 20, 2009, after such date there are no limitations as to the number of our outstanding shares of common stock that Tracinda Corporation may acquire. Consequently, Tracinda Corporation has the power to significantly influence matters requiring approval by our stockholders, including the election of directors, and the approval of mergers and other significant corporate transactions. This concentration of ownership may make it more difficult for other stockholders to effect substantial changes in our Company and may also have the effect of delaying, preventing or expediting, as the case may be, a change in control of our Company.
Sales of a substantial number of shares of our common stock, or the perception that such sales might occur, could have an adverse effect on the price of our common stock.
Following the closing of the Tracinda investment, approximately 65% of our common stock is held by institutional investors who now each have ownership of greater than 5% of our common stock. Sales by Tracinda Corporation, or other of our large institutional investors, of a substantial number of shares of our common stock into the public market, or the perception that such sales might occur, could have an adverse effect on the price of our common stock.
We may issue shares of preferred stock with greater rights than our common stock.
Although we have no current plans, arrangements, understandings or agreements to issue any preferred stock, our certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights.
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There may be future dilution of our common stock.
To the extent options to purchase common stock under our employee and director stock option plans or outstanding warrants to purchase common stock are exercised or the price vesting triggers under the performance shares granted to our executive officers are satisfied, holders of our common stock will experience dilution. As of December 31, 2007, we had outstanding options to purchase 2,157,000 shares of common stock at a weighted average exercise price of $9.04. Further, if we sell additional equity or convertible debt securities, such sales could result in increased dilution to our stockholders.
We do not expect to pay dividends on our common stock.
We have never paid dividends with respect to our common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, the credit agreement relating to our credit facility prohibits us from paying any dividends and the indenture governing our senior notes restricts our ability to pay dividends. In the future, we may agree to further restrictions.
The common stock is an unsecured equity interest in our Company.
As an equity interest, the common stock will not be secured by any of our assets. Therefore, in the event we are liquidated, the holders of the common stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of the common stock.
Our stockholders do not have cumulative voting rights.
Holders of our common stock are not entitled to accumulate their votes for the election of directors or otherwise. Accordingly, a plurality of holders of our outstanding common stock will be able to elect all of our directors. As of December 31, 2007, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 7.1% of our outstanding common stock.
Anti-takeover provisions in our certificate of incorporation, Delaware law and certain of our contracts may have provisions that discourage corporate takeovers and could prevent stockholders from realizing a premium on their investment.
Certain provisions of our Certificate of Incorporation, the provisions of the Delaware General Corporation Law and certain of our contracts may discourage persons from considering unsolicited tender offers or other unilateral takeover proposals or require that such persons negotiate with our board of directors rather than pursue non-negotiated takeover attempts. These provisions may discourage acquisition proposals or delay or prevent a change in control. As a result, these provisions could have the effect of preventing stockholders from realizing a premium on their investment.
Our Certificate of Incorporation authorizes our board of directors to issue preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as the board of directors may determine. In addition, our Certificate of Incorporation authorizes a substantial number of shares of common stock in excess of the shares outstanding. These provisions may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.
Under our credit facility, a change in control is an event of default. Under the indenture governing our senior notes, upon the occurrence of a change in control, the holders of our senior notes will have the right, subject to certain conditions, to require us to repurchase their notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest to the date of the repurchase.
Item 1B. Unresolved Staff Comments.
On December 3, 2007, we received written comments from the Commission staff regarding reserve and accounting information contained in our 2006 report on Form 10-K. We have responded to the comments and are still in the process of providing supplemental information to the Commission staff. While we are not aware of any
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disagreements with the staff and do not believe that any material adjustments will be necessary, the comments are still in the process of being resolved and the outcome of the staff’s review cannot be predicted with certainty.
Item 2. Properties.
Our primary areas of activity are in the Rocky Mountain and Gulf Coast Regions with additional strategic exploration projects in the Columbia River Basin in southeastern Washington and the Hingeline area of Central Utah. Total oil and gas leasehold in these areas comprises approximately 1.8 million acres.
Rocky Mountain Region
The Rocky Mountain Region comprises approximately 77% of our estimated proved reserves as of December 31, 2007. The majority of our undeveloped acreage and drilling inventory is located in this region, where our drilling efforts and capital expenditures will be increasingly focused.
In the Rocky Mountains, our core development activities are centered on four basins that provide a multi-year inventory of development drilling locations. Our exploration ventures are located in two additional basins as well as those four basins that contain our development activity.
Piceance Basin.We are currently focusing our development efforts on the Vega Unit and surrounding leasehold in Mesa County, Colorado, which in combination is referred to as the Vega Area. We also have a non-operated working interest in the Garden Gulch Field in Garfield County, Colorado. These fields are consistent with our strategy of targeting reservoirs that demonstrate predictable geology over large areas. The Williams Fork member of the Mesaverde formation is the primary producing interval and has been successfully developed throughout the Piceance Basin.
Vega Area.The Vega Area includes the Vega Unit and the North Vega leasehold. We have a 100% working interest in the Vega Unit and in March of 2007 we entered into an earn-in agreement with another company that allows us to earn up to an additional 12,000 net acres with an average 50% working interest by drilling 128 wells over a 36 month period. This is referred to as the North Vega leasehold. During fiscal 2007 the Company increased proved reserves in the Vega Area almost 90% to 182.5 Bcfe. During 2007 production increased from approximately 3 Mmcf/d at the beginning of the year to approximately 30 Mmcf/d at the end of 2007. The new Collbran Valley natural gas pipeline was completed in late 2006 and provides the Company with 60 Mmcf/d of pipeline takeaway capacity. The increased takeaway capacity has allowed the Company to increase its drilling activity to four rigs running full time at year-end 2007 with the probability of further increases during 2008. We believe that the leasehold position will allow for the drilling of 1,500 – 2,000 locations, which is in excess of a ten year inventory based on our current rate of activity.
In February 2008, we closed a transaction in which we acquired over 1,700 drilling locations on 10-acre spacing and a 95% working interest in 18,250 net acres in the Vega Area. This transaction includes the remaining 50% working interest that we did not own in the North Vega leasehold and a 95% working interest in lands in the Buzzard Creek Federal Unit and acreage north of the Buzzard Creek Unit. Subsequent to this transaction the Company will have an approximate 95-100% working interest in over 20,000 net acres of leasehold in an almost contiguous block covering most of two townships. With the significantly increased acreage position, we have increased our drilling capital budget for the Vega Area to $210 — $215 million for the year ending December 31, 2008.
Garden Gulch.We have an interest in approximately 6,000 gross/2,000 net acres with a 31.1% non-operated working interest. The operator of the project currently has three drilling rigs running full time and has communicated plans to increase activity in 2008. Our drilling capital budget for the year ending December 31, 2008 is approximately $40 — $45 million. At the current pace, this property has in excess of a 5 year drilling inventory.
Paradox Basin.In the Paradox Basin we have five prospect areas: Greentown, Salt Valley, Fisher Valley, Gypsum Valley and Cocklebur Draw. Two of the prospects, the Greentown and Salt Valley in Grand County, Utah, have been drilled with successful exploratory wells.
Greentown.The Greentown project area has three exploratory wells that encountered economic recoverable reserves as of December 31, 2007. The wells flow tested at rates between 2.0 Mmcf/d with 40 Bo/d and 4.0 Mmcf/d with 800 Bo/d. The wells were drilled across our acreage position and are located as far as seven miles apart. Even though
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these wells are widely spaced, they exhibited very consistent electric log characteristics and appear analogous and mapable over a large area. We are developing and delineating the field with a two-rig drilling program. The Greentown project also exhibits and supports the Company’s strategy of targeting reservoirs that demonstrate consistent geologic attributes and are present over large areas. The Company has a 70% working interest in 43,700 gross acres, 30,400 net acres. Assuming continued success at the Greentown project we anticipate accelerating Greentown development with additional rigs in 2008. We have budgeted approximately $40 million for drilling capital expenditures for the year ending December 31, 2008.
Subsequent to year-end we obtained permit approval for a 25 mile natural gas pipeline and processing plant that will service both the Greentown and Salt Valley project areas. Construction on the pipeline has begun and initial operations are projected to begin in mid-year 2008. We estimate the total cost of the pipeline to be $30 — $40 million.
Salt Valley.The Salt Valley project area has had one exploratory well drilled. Additional drilling plans are not expected in 2008 due to the increased effort at Greentown. We have a 70% working interest in 7,100 gross acres, 4,900 net acres. We have not budgeted any significant amount for drilling capital expenditures for the year ending December 31, 2008.
Fisher Valley, Gypsum Valley and Cocklebur Draw. We have three remaining prospects in the Paradox Basin located in San Miguel and Dolores Counties, Colorado and Grand County, Utah. The prospects are based on similar geology as that we used in the discovery of the Greentown Field. We have a 70% working interest in 46,500 gross acres, 32,800 net acres, all of which were undeveloped at December 31, 2007.
Wind River Basin.The Wind River Basin is characterized by a depositional environment that resulted in thick packages of tight gas sands producing at depths that range from 7,000 to 20,000 feet. We will be focusing our efforts on the shallower Lower Fort Union Formation which produces in numerous fields throughout the Wind River Basin and will limit our activities to under 11,000 feet.
Howard Ranch. During 2007 we commenced our Lower Fort Union evaluation program which included new drilling and the recompletion of two of our deeper wells to the Lower Fort Union with commercially economic production results. We drilled a total of five wells targeting the Lower Fort Union in 2007 with varying results. The Lower Fort Union has a conventional gas component as well as an unconventional gas component, and the wells that experience better economics rely on gas contribution from both reservoirs. Less economic wells were encountered where only one of the reservoirs was present. We have revised our geologic model with the intention of focusing our drilling activity on areas where both conventional and unconventional gas is trapped. At year end we owned an interest in 47,100 net acres with an average working interest of 50%. Our 2008 drilling capital budget for the Howard Ranch is approximately $7- $8 million.
Denver-Julesburg (“D-J”) Basin.Our leasehold in the Denver Julesburg Basin focuses on the “J” sand formation at depths of between 7,000 feet and 8,000 feet. In 2007 we drilled an exploratory well, the Cowboy 35-21 well, which was a discovery that began production at a rate of 200 Bo/d. Subsequent development of the Cowboy field included ten additional wells which allowed production to peak at about 1,100 barrels of oil per day. We have since acquired and interpreted a 3D seismic survey to further delineate the field and plan to resume development at the end of the first quarter of 2008. Seismic data appears to have identified additional prospects on our acreage position that are similar in size to the Cowboy field. We have acquired a leasehold position of 21,800 net acres on six prospects, and anticipate testing three of these in 2008. We have an interest in 21,800 net acres with a 100% working interest. Our 2008 drilling capital budget for the D-J Basin is approximately $6 - $7 million.
Gulf Coast Region
The Gulf Coast Region comprises approximately 21% of our estimated proved reserves as of December 31, 2007. In the Gulf Coast Region, our primary activities include developing the Newton, Midway Loop and Opossum Hollow Fields.
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Development Projects – Newton, Midway Loop and Opossum Hollow Fields
Newton Field.The Newton Field is located in Newton County, Texas and represents an important asset for the Company in the Gulf Coast Region. We have an interest in 21,000 net acres with a 92% working interest. The wells in the Newton Field produce from 13 different sands in the Wilcox formation. The field is a large structural anticline that is defined by extensive well and seismic control. Currently, the Company is injecting water into a pilot waterflood that involves a small portion of the field. If the waterflood is successful the Newton Field could experience a significant increase in proven reserves. At year end, proved reserves in the Newton Field were 34.0 Bcfe.
We have also experienced successful exploratory drilling on seismically defined anomalies in the shallower Yegua and Frio formations and plan further drilling activities. Our 2008 capital budget is expected to be $9 — $10 million.
Midway Loop Field. The Midway Loop Field is located in Polk and Tyler Counties, Texas. We have an interest in 21,400 gross acres, with an average 28% working interest. The wells in this field produce from the Austin Chalk and are drilled horizontally with either dual or single laterals that reach up to 8,000 feet of displacement in each lateral. As of December 31, 2007 our proved reserves totaled 23.8 Bcfe. The capital budget for the field in the year ending December 31, 2008 is $6 — $7 million.
Opossum Hollow Field.The Opossum Hollow Field is located in McMullen County, Texas, and the Company has an average working interest of 98%. The field currently produces from the Wilcox Formation. In 2007, the Company acquired a 3D seismic survey on its adjacent 74 Ranch leasehold and plans to drill the initial test wells in early 2008. As of December 31, 2007 we had proved reserves of 6.4 Bcfe.
Other Areas
Central Utah Hingeline.The central Utah Hingeline Region is an overthrust belt located in central Utah. We have an average 65% working interest in approximately 119,000 net acres. The Company has drilled two wells, the Joseph #1 and the Federal 23-44, to date. The Joseph #1 was drilled to a total depth of 13,500 feet and was plugged and abandoned as a dry hole. The Federal 23-44 reached total depth of 12,094 feet after drilling through its second primary objective. Operations have been suspended due to BLM-mandated restrictions for raptor nesting. The Federal 23-44 has been classified as a dry hole in the accompanying financial statements as there were no significant hydrocarbon shows encountered in the Navajo Sandstone or Kaibab Formation; however, drilling results confirmed the presence of a large structure. The Federal 23-44 did exhibit oil shows in the Twin Creek Limestone, a secondary objective above the Navajo, and wireline logs suggest the possibility of hydrocarbon saturation in this interval. Oil recovered from the sample cuttings from this limestone has been laboratory tested and typed as Mississippian-aged, which is the same age as the oil that produces from the original Hingeline discovery, the Covenant Field. We believe that the confirmation of Mississippian-aged oil validates our geologic model for hydrocarbon source and migration in the Central Utah Hingeline. We anticipate that the well will be production tested in the third quarter of 2008 after the raptor nesting restrictions have been lifted.
We and our partners control approximately 190,000 gross acres (123,500 net acres) within this play and numerous structural features have been identified on our leasehold. Delta’s recently acquired 110-mile seismic program covering previously generated prospects is currently being interpreted, and preliminary review appears to confirm and enhance original expectations. Final interpretation and drill site selection is expected in early 2008, and permitting of the next well should be underway by the second quarter of 2008. We plan to drill a third well in the third or fourth quarter of 2008. Our drilling capital budget is expected to be $7 — $8 million. The Central Utah Hingeline project is an exploratory area for the Company and does not account for any of our proved reserves at December 31, 2007.
Columbia River Basin. The Columbia River Basin is located in southeast Washington and northeast Oregon. The basin is characterized by over-pressured, tight sand gas formations. Based upon log evaluation of older wells, well testing and core analysis there appear to be multiple potentially productive hydrocarbon bearing sands which lie below a layer of volcanic basalt. We have an interest in 508,000 net acres in the basin, all of which are undeveloped. We plan to commence drilling operations on the Gray 31-23 which will be our first operated well in the basin during the second quarter of 2008. The Columbia River Basin is an exploration project area and does not account for any of our proved reserves as of December 31, 2007.
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Other Operations
Offshore California producing properties
Point Arguello Unit.We own the equivalent of a 6.07% working interest in the Point Arguello Unit and related facilities located Offshore California in the Santa Barbara Channel. Within this unit there are three producing platforms (Hidalgo, Harvest and Hermosa). No capital expenditures are in the Company’s 2008 fiscal budget.
Rocky Point Unit.We own a 6.25% working interest in the development of the east half of OCS Block 451 in the Rocky Point Unit.
Unproved Undeveloped Offshore California Properties
We have direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $14.8 million and $12.5 million at December 31, 2007 and December 31, 2006, respectively. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of our investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.
We and our 92% owned subsidiary, Amber, are among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 19, 2006, the government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by us (“Lease 452”). In its motion for reconsideration, the government has asserted that we should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and post-trial briefing is currently in process. We believe that the government’s assertion is without merit, but we cannot predict with certainty the ultimate outcome of this matter.
On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty five of the forty lawsuit leases. Under this order we are entitled to receive a gross amount of approximately $58.5 million and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. No payments will be made until all appeals have either been waived or exhausted. In the event that we ultimately receive any proceeds as the result of this litigation, we will be obligated to pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.
Other Fields
We derive meaningful oil and gas production from fields in non-core regions that will not constitute a significant portion of our capital budget in the future. Our interest in these fields had approximately 4.2 Bcfe in proved reserves as of December 31, 2007.
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DHS Drilling Company Rigs
The Company owns 50.0% of DHS, which as of December 31, 2007 owned fifteen rigs with depth ratings of 10,000 to 20,000 feet. The following table shows property information and location for the DHS rigs.
Year | ||||||||||||||||
Operating | Built or | Depth | ||||||||||||||
Region | Refurbished | Horsepower | Capacity | |||||||||||||
Rig No. 1 | WY | 2005 | 1,500 | 18,000 | ||||||||||||
Rig No. 4 | WY | 2007 | 700 | 12,000 | ||||||||||||
Rig No. 5 | CO | 2005 | 700 | 12,000 | ||||||||||||
Rig No. 6 | CO | 2005 | 700 | 12,000 | ||||||||||||
Rig No. 7 | WY | 2005 | 1,500 | 20,000 | ||||||||||||
Rig No. 8 | WY | 2005 | 800 | 12,500 | ||||||||||||
Rig No. 9 | TX | 2006 | 1,000 | 15,000 | ||||||||||||
Rig No. 10 | TX | 2006 | 1,000 | 15,000 | ||||||||||||
Rig No. 11 | UT | 2006 | 750 | 11,000 | ||||||||||||
Rig No. 12 | UT | 2006 | 1,000 | 15,000 | ||||||||||||
Rig No. 14 | NV | 2006 | 800 | 12,500 | ||||||||||||
Rig No. 15 | CO | 2006 | 700 | 10,000 | ||||||||||||
Rig No. 16 | WY | 2006 | 700 | 10,000 | ||||||||||||
Rig No. 17 | WY | 2006 | 1,000 | 12,500 | ||||||||||||
Rig No. 18 | CO | 2007 | 700 | 10,500 |
(i) | Rigs No. 2 and No. 3 were sold during the fourth quarter 2007. |
Office Facilities
Our offices are located at 370 Seventeenth Street, Suite 4300, Denver, Colorado 80202. We lease approximately 74,000 square feet of office space. Our current payment approximates $135,000 per month and our lease will expire in December 2014.
Production
During the years ended December 31, 2007, 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005 we have not had, nor do we now have, any long-term supply or similar agreements with governments or authorities under which we acted as producer.
Impairment of Long Lived Assets
On a quarterly basis, we compare our historical cost basis of each proved developed and undeveloped oil and gas property to its expected future undiscounted cash flow from each property (on a field by field basis). Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the property, no impairment is recognized. If the carrying value of the property exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset.
During the year ended December 31, 2007 the Company recorded an impairment provision of approximately $58.4 million to developed properties primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 million and $10.3 million, respectively), and the South Angleton field in Texas ($9.7 million), primarily due to lower Rocky Mountain natural gas prices and marginally economic deep zones on the Howard Ranch Prospect.
During the year ended December 31, 2006, an impairment of $10.4 million was recorded on certain of our eastern Colorado properties primarily due to lower Rocky Mountain natural gas prices. In addition, an impairment of $1.0 million was recorded on certain Oklahoma properties.
During the six months ended December 31, 2005, a dry hole was drilled on a prospect located in Orange County, California. We determined that we would not pursue development in the prospect and accordingly an impairment of $1.3 million was recorded for the full impairment of the remaining leasehold costs related to the prospect.
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Any impairment provisions recognized for developed and undeveloped properties are permanent and may not be restored in future periods. We had no impairment provision attributed to producing properties during the fiscal year ended June 30, 2005.
Reserves Reported to Other Agencies
We did not file any reports during the year ended December 31, 2007 with any federal authority or agency with respect to our estimates of oil and natural gas reserves.
Production Volumes, Unit Prices and Costs
The following table sets forth certain information regarding our volumes of production sold and average prices received associated with our production and sales of natural gas and crude oil for the years ended December 31, 2007 and December 31, 2006, six months ended December 31, 2005 and the fiscal year ended June 30, 2005.
Six Months Ended | Year Ended | |||||||||||||||||||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||||
2007 | 2006(1) | 2005(1) | 2005(1) | |||||||||||||||||||||||||||||
Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||||||||||||||
Production volume – | ||||||||||||||||||||||||||||||||
Total production (MMcfe) | 16,888 | 875 | 15,172 | 975 | 6,285 | 485 | 13,073 | 934 | ||||||||||||||||||||||||
Production from continuing operations: | ||||||||||||||||||||||||||||||||
Oil (MBbls) | 703 | 146 | 856 | 162 | 264 | 81 | 404 | 156 | ||||||||||||||||||||||||
Natural Gas (MMcf) | 8,601 | — | 5,438 | — | 2,634 | — | 4,963 | — | ||||||||||||||||||||||||
Total (MMcfe) | 12,818 | 875 | 10,576 | 975 | 4,701 | 485 | 7,387 | 934 | ||||||||||||||||||||||||
Net average daily production- continuing operations: | ||||||||||||||||||||||||||||||||
Oil (Bbl) | 1,926 | 399 | 2,346 | 445 | 1,433 | 439 | 1,107 | 427 | ||||||||||||||||||||||||
Natural Gas (Mcf) | 23,563 | — | 14,899 | — | 14,314 | — | 13,597 | — | ||||||||||||||||||||||||
Average sales price: | ||||||||||||||||||||||||||||||||
Oil (per barrel) | $ | 68.85 | $ | 52.96 | $ | 64.37 | $ | 46.75 | $ | 59.62 | $ | 47.12 | $ | 47.92 | $ | 33.37 | ||||||||||||||||
Natural Gas (per Mcf) | $ | 4.47 | $ | — | $ | 5.79 | $ | — | $ | 8.78 | $ | — | $ | 5.62 | $ | — | ||||||||||||||||
Hedge gain (loss) (per Mcfe) | $ | 1.00 | $ | — | $ | (.45 | ) | $ | — | $ | (.81 | ) | $ | — | $ | (.09 | ) | $ | — | |||||||||||||
Lease operating costs - (per Mcfe) | $ | 1.29 | $ | 4.09 | $ | 1.32 | $ | 3.75 | $ | 1.01 | $ | 4.62 | $ | .76 | $ | 3.90 |
(1) | Revised for operations discontinued in 2007. |
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Productive Wells and Acreage
The table below shows, as of December 31, 2007, the approximate number of gross and net producing oil and gas wells by state and their related developed acres owned by us. Calculations include 100% of wells and acreage owned by us and our subsidiaries. Productive wells are producing wells capable of production, including shut-in wells. Developed acreage consists of acres spaced or assignable to productive wells.
Oil(1) | Gas | Developed Acres | ||||||||||||||||||||||
Location | Gross(2) | Net(3) | Gross(2) | Net(3) | Gross(2) | Net(3) | ||||||||||||||||||
Alabama | — | — | 15 | .1 | 400 | 100 | ||||||||||||||||||
California: | ||||||||||||||||||||||||
Offshore | 34 | 2.1 | — | — | 11,000 | 700 | ||||||||||||||||||
Onshore | 2 | .1 | 15 | 4.1 | 2,900 | 600 | ||||||||||||||||||
Colorado | 357 | 11.6 | 121 | 78.8 | 1,800 | 1,500 | ||||||||||||||||||
Kansas | 5 | 2.0 | 1 | .6 | — | — | ||||||||||||||||||
Louisiana | 12 | 2.5 | 3 | — | 1,400 | 600 | ||||||||||||||||||
Michigan | 1 | — | — | — | — | — | ||||||||||||||||||
Mississippi | 2 | — | 1 | .4 | 600 | 100 | ||||||||||||||||||
New Mexico | 2 | — | 1 | .1 | 200 | — | ||||||||||||||||||
North Dakota | 7 | 1.0 | — | — | 5,800 | 1,100 | ||||||||||||||||||
Oklahoma | 205 | 2.0 | 9 | .5 | 2,900 | 600 | ||||||||||||||||||
Texas(4) | 260 | 56.1 | 51 | 15.6 | 21,100 | 12,000 | ||||||||||||||||||
Utah | — | — | — | — | 200 | 100 | ||||||||||||||||||
Wyoming | 13 | 11.5 | 24 | 19.1 | 3,100 | 2,300 | ||||||||||||||||||
900 | 88.9 | 241 | 119.3 | 51,400 | 19,700 | |||||||||||||||||||
(1) | All of the wells classified as “oil” wells also produce various amounts of natural gas. | ||
(2) | A “gross well” or “gross acre” is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned. | ||
(3) | A “net well” or “net acre” is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof. | ||
(4) | This does not include varying very small interests in approximately 666 gross wells (5.2 net) located primarily in Texas which are owned by our subsidiary, Piper Petroleum Company. |
Undeveloped Acreage
At December 31, 2007, we held undeveloped acreage by state as set forth below:
Undeveloped Acres(1) (2) | ||||||||
Location | Gross | Net | ||||||
California, onshore | 500 | 200 | ||||||
California, offshore | 64,900 | 15,800 | ||||||
Colorado | 79,500 | 54,800 | ||||||
Kansas | 200 | 200 | ||||||
Montana | 6,100 | 3,700 | ||||||
North Dakota | 3,200 | 500 | ||||||
Oklahoma | 100 | — | ||||||
Oregon | 419,400 | 97,000 | ||||||
Texas | 44,500 | 29,100 | ||||||
Utah | 318,600 | 185,500 | ||||||
Washington | 834,500 | 411,300 | ||||||
Wyoming | 145,300 | 72,500 | ||||||
Total | 1,916,800 | 870,600 | ||||||
(1) | Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves. | ||
(2) | Includes acreage owned by Amber. |
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Drilling Activity
During the years indicated, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells:
Six Months Ended | Year Ended | |||||||||||||||||||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
Exploratory Wells(1): | ||||||||||||||||||||||||||||||||
Productive: | ||||||||||||||||||||||||||||||||
Oil | 5 | 4.75 | 4 | 3.15 | 2 | 1.42 | 5 | 3.94 | ||||||||||||||||||||||||
Gas | 4 | 3.09 | 4 | 4.00 | — | — | 3 | 1.15 | ||||||||||||||||||||||||
Nonproductive | 5 | 4.16 | 4 | 3.50 | 6 | 3.83 | 8 | 7.15 | ||||||||||||||||||||||||
Total | 14 | 12.00 | 12 | 10.65 | 8 | 5.25 | 16 | 12.24 | ||||||||||||||||||||||||
Development Wells(1): | ||||||||||||||||||||||||||||||||
Productive: | ||||||||||||||||||||||||||||||||
Oil | 10 | 9.55 | 14 | 11.83 | 11 | 9.90 | 6 | 4.90 | ||||||||||||||||||||||||
Gas | 89 | 58.48 | 37 | 20.12 | 5 | 5.00 | 82 | 68.80 | ||||||||||||||||||||||||
Nonproductive | 2 | 1.13 | 1 | 1.00 | 2 | 1.50 | 7 | 7.00 | ||||||||||||||||||||||||
Total | 101 | 69.16 | 52 | 32.95 | 18 | 16.40 | 95 | 80.70 | ||||||||||||||||||||||||
Total Wells(1): | ||||||||||||||||||||||||||||||||
Productive: | ||||||||||||||||||||||||||||||||
Oil | 15 | 14.30 | 18 | 14.98 | 13 | 11.32 | 11 | 8.84 | ||||||||||||||||||||||||
Gas | 93 | 61.57 | 41 | 24.12 | 5 | 5.00 | 85 | 69.95 | ||||||||||||||||||||||||
Nonproductive | 7 | 5.29 | 5 | 4.50 | 8 | 5.33 | 15 | 14.15 | ||||||||||||||||||||||||
Total Wells | 115 | 81.16 | 64 | 43.60 | 26 | 21.65 | 111 | 92.94 | ||||||||||||||||||||||||
(1) | Does not include wells in which we had only a royalty interest. |
Present Drilling Activity
The following represents our planned exploration and development activities for the year ending December 31, 2008:
Gross Drilling | Drilling | |||||||
Areas of Operations | Locations | Budget | ||||||
(In millions) | ||||||||
Rocky Mountain Region | 174 - 196 | $ | 310 - $323 | |||||
Gulf Coast Region | 10 - 12 | $ | 24 - $ 27 | |||||
Other | 1 - 2 | $ | 16 - $ 20 | |||||
Total | 185 - 210 | $ | 350 - $370 | |||||
Item 3. Legal Proceedings
Offshore Litigation
We and our 92% owned subsidiary, Amber, are among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 19, 2006, the
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government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by us (“Lease 452”). In its motion for reconsideration, the government has asserted that we should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and post-trial briefing is currently in process. We believe that the government’s assertion is without merit, but we cannot predict with certainty the ultimate outcome of this matter.
On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty five of the forty lawsuit leases. Under this order we are entitled to receive a gross amount of approximately $58.5 million and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. No payments will be made until all appeals have either been waived or exhausted. In the event that we ultimately receive any proceeds as the result of this litigation, we will be obligated to pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.
Shareholder Derivative Suit
Within the past two years, there has been significant focus on corporate governance and accounting practices in the grant of equity based awards to executives and employees of publicly traded companies, including the use of market hindsight to select award dates to favor award recipients. After being identified in a third-party report as statistically being at risk for possibly backdating option grants, in May 2006 our Board of Directors created a special committee comprised of outside directors. The special committee, which was advised by independent legal counsel and advisors, undertook a comprehensive review of our historical stock option practices and related accounting treatment. In June 2006 we received a subpoena from the U.S. Attorney for the Southern District of New York and an inquiry from the staff of the Securities and Exchange Commission (“SEC”) related to our stock option grants and related practices. The special committee of our Board of Directors reported to the Board that, while its review revealed deficiencies in the documentation of our option grants in prior years, there was no evidence of option backdating or other misconduct by our executives or directors in the timing or selection of our option grant dates, or that would cause us to conclude that our prior accounting for stock option grants was incorrect in any material respect. We provided the results of the internal investigation to the U.S. Attorney and to the SEC in August of 2006, and were subsequently informed by both agencies that the matter had been closed.
During September and October of 2006, three separate shareholder derivative actions were filed on our behalf in U.S. District Court for the District of Colorado relating to the options backdating issue, all of which were consolidated into a single action. The consolidated complaint alleged that certain of our executive officers and directors engaged in various types of misconduct in connection with certain stock option grants. Specifically, the plaintiffs alleged that the defendant directors, in their capacity as members of our Board of Directors and our Audit or Compensation Committee, at the behest of the defendants who are or were officers and to benefit themselves, backdated our stock option grants to make it appear as though they were granted on a prior date when our stock price was lower. They alleged that these backdated options unduly benefited the defendants who are or were officers and/or directors, resulted in our issuing materially inaccurate and misleading financial statements and caused us to incur substantial damages. The action also sought to have the current and former officers and directors who are defendants disgorge to us certain options they received, including the proceeds of options exercised, as well as certain equitable relief and attorneys’ fees and costs. On September 26, 2007, the Court entered an Order dismissing the action for failing to plead sufficient facts to support the claims that were made in the complaint, and stayed the dismissal for ten days to allow the Plaintiffs to file a motion for leave to file an amended complaint. Extensions were granted and the Plaintiffs filed such a motion on October 29, 2007. The stay will remain in effect until the Court rules on the motion.
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Castle/Longs Trust Litigation
As a result of the acquisition of Castle Energy in April 2006, our wholly-owned subsidiary, DPCA LLC, as successor to Castle, became party to Castle’s ongoing litigation with the Longs Trust in District Court in Rusk County, Texas. The Longs Trust litigation, which was originally the subject of a jury trial in November 2000, has been separated into two pending suits, one in which the Longs Trust is seeking relief on contract claims regarding oil and gas sales and gas balancing under joint operating agreements with various Castle entities, and the other in which Castle’s claims for unpaid joint interest billings and attorneys’ fees in the amount of $964,000, plus prejudgment interest, have been granted by the trial court and upheld on appeal. We intend to vigorously defend the Longs Trust breach of contract claims. We have not accrued any recoveries associated with the judgment against the Longs Trust, but will do so when and if they are ultimately collected.
Management does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flows.
Item 4. Submission of Matters To a Vote of Security Holders
None.
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Item 4A. Directors and Executive Officers
Our executive officers and members of our Board of Directors, and their respective ages, are as follows:
Name | Age | Positions | Period of Service | |||||
Roger A. Parker | 46 | Chairman, Chief Executive Officer and a Director | May 1987 to Present | |||||
John R. Wallace | 48 | President, Chief Operating Officer and a Director | October 2003 to Present | |||||
Kevin K. Nanke | 43 | Treasurer and Chief Financial Officer | December 1999 to Present | |||||
Stanley F. Freedman | 59 | Executive Vice President, General Counsel and Secretary | January 2006 to Present | |||||
Hank Brown | 68 | Director | June 2007 to Present | |||||
Kevin R. Collins | 51 | Director | March 2005 to Present | |||||
Jerrie F. Eckelberger | 63 | Director | September 1996 to Present | |||||
Aleron H. Larson, Jr. | 62 | Director | May 1987 to Present | |||||
Russell S. Lewis | 53 | Director | June 2002 to Present | |||||
James J. Murren | 46 | Director | February 2008 to Present | |||||
Jordan R. Smith | 73 | Director | October 2004 to Present | |||||
Neal A. Stanley | 60 | Director | October 2004 to Present | |||||
Daniel J. Taylor | 51 | Director | February 2008 to Present | |||||
James B. Wallace | 78 | Director | November 2001 to Present |
The following is biographical information as to the business experience of each of our current executive officers and directors.
Roger A. Parker has been a Director since May 1987 and Chief Executive Officer since April 2002. He served as our President from May 1987 until February 2006 when he resigned to accommodate the appointment of John R. Wallace to that position. He was named Chairman of the Board on July 1, 2005. Since April 1, 2005, he has also served as Executive Vice President and Director of DHS. Mr. Parker also serves as President, Chief Executive Officer and Director of Amber Resources. He received a Bachelor of Science degree in Mineral Land Management from the University of Colorado in 1983. He is a board member of the Independent Petroleum Association of the Mountain States (IPAMS). He also serves on other boards, including Community Banks of Colorado.
John R. Wallace, President and Chief Operating Officer, joined Delta in October 2003 as Executive Vice President of Operations and was appointed President in February 2006 and a Director in June 2007. Since April 1, 2005, he has also served as Executive Vice President and Director of DHS. Mr. Wallace was Vice President of Exploration and Acquisitions for United States Exploration, Inc. (“UXP”), a Denver-based publicly-held oil and gas exploration
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company, from May 1998 to October 2003. Prior to UXP, Mr. Wallace served as president of various privately held oil and gas companies engaged in producing property acquisitions and exploration ventures. He received a Bachelor of Science degree in Geology from Montana State University in 1981. He is a member of the American Association of Petroleum Geologists and the Independent Petroleum Association of the Mountain States. Mr. Wallace is the son of James B. Wallace, a Director of the Company.
Kevin K. Nanke, Treasurer and Chief Financial Officer, joined Delta in April 1995 as our Controller and has served as the Treasurer and Chief Financial Officer of Delta and Amber Resources since 1999. Since April 1, 2005 he has also served as Chief Financial Officer, Treasurer and Director of DHS. Since 1989, he has been involved in public and private accounting with the oil and gas industry. Mr. Nanke received a Bachelor of Arts degree in Accounting from the University of Northern Iowa in 1989. Prior to working with us, he was employed by KPMG LLP. He is a member of the Colorado Society of CPA’s and the Council of Petroleum Accounting Society.
Stanley F. (“Ted”) Freedman has served as Executive Vice President, General Counsel and Secretary since January 1, 2006 and has also served in those same capacities for DHS since that same date. He also serves as Executive Vice President and Secretary of Amber Resources. He graduated from the University of Wyoming with a Bachelor of Arts degree in 1970 and a Juris Doctor degree in 1975. From 1975 to 1978, Mr. Freedman was a staff attorney with the United States Securities and Exchange Commission. From 1978 to December 31, 2005, he was engaged in the private practice of law, and was a shareholder and director of the law firm of Krys Boyle, P.C. in Denver, Colorado.
Hank Brown currently serves as the President of the University of Colorado. Prior to joining CU in June 2005 he was President and CEO of the Daniels Fund and served as the President of the University of Northern Colorado from 1998 to 2002. He served Colorado in the United States Senate (elected in 1990) and served five consecutive terms in the U.S. House representing Colorado’s 4th Congressional District (1980-1988). He also served in the Colorado Senate from 1972 to 1976. Mr. Brown was a Vice President of Monfort of Colorado from 1969 to 1980. He is both an attorney and a C.P.A. He earned a Bachelor’s degree in Accounting from the University of Colorado in 1961 and received his Juris Doctorate degree from the University of Colorado Law School in 1969. While in Washington, D.C., Mr. Brown earned a Master of Law degree in 1986 from George Washington University.
Kevin R. Collins currently serves as President, Chief Executive Officer and a Director of Evergreen Energy Inc. Prior to his current position, Mr. Collins served as Evergreen’s Executive Vice President — Finance and Strategy from September 2005 to September 2006, and acting Chief Financial Officer from November 2005 until March 31, 2006. Mr. Collins also serves as a director of Quest Midstream Partners, L.P. From 1995 until 2004, Mr. Collins was an executive officer of Evergreen Resources, Inc., serving as Executive Vice President and Chief Financial Officer until Evergreen Resources merged with Pioneer Natural Resources Co. in September 2004. Mr. Collins became a Certified Public Accountant in 1983 and has over 13 years’ public accounting experience. He has served as Vice President and a board member of the Colorado Oil and Gas Association, President of the Denver Chapter of the Institute of Management Accountants, and board member and Chairman of the Finance Committee of the Independent Petroleum Association of Mountain States. Mr. Collins received his Bachelor of Science degree in Business Administration and Accounting from the University of Arizona.
Jerrie F. Eckelberger is an investor, real estate developer and attorney who has practiced law in the State of Colorado since 1971. He graduated from Northwestern University with a Bachelor of Arts degree in 1966 and received his Juris Doctor degree in 1971 from the University of Colorado School of Law. From 1972 to 1975, Mr. Eckelberger was a staff attorney with the Eighteenth Judicial District Attorney’s Office in Colorado. From 1975 to the present, Mr. Eckelberger has been engaged in the private practice of law in the Denver area. Mr. Eckelberger previously served as an officer, director and corporate counsel for Roxborough Development Corporation. Since March, 1996, Mr. Eckelberger has engaged in the investment and development of Colorado real estate through several private companies in which he is a principal.
Aleron H. Larson, Jr. has operated as an independent in the oil and gas industry individually and through public and private ventures since 1978. Mr. Larson served as Chairman of the Board, Secretary and Director of Delta, as well as Amber Resources, until his retirement on July 1, 2005, at which time he resigned as Chairman of the Board and as an executive officer of the Company. He ceased to be an officer or director of Amber Resources on January 3, 2006. Mr. Larson practiced law in Breckenridge, Colorado from 1971 until 1974. During this time he was a member of a law firm, Larson & Batchellor, engaged primarily in real estate law, land use litigation, land planning and municipal law.
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In 1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of law relating to securities, real estate, and oil and gas until 1978. Mr. Larson received a Bachelor of Arts degree in Business Administration from the University of Texas at El Paso in 1967 and a Juris Doctor degree from the University of Colorado in 1970.
Russell S. Lewis is President and CEO of Lewis Capital, LLC, located in Harrisburg, Pennsylvania, which makes private investments in, and provides general business and M&A consulting services to, growth-oriented firms. He has been a member of the Board of Delta since June 2002. From February 2002 until January 2005 Mr. Lewis served as Executive Vice President and General Manager of VeriSign Name and Directory Services (VRSN) Group, which managed a significant portion of the internet’s critical .com and .net addressing infrastructure. For the preceding 15 years Mr. Lewis managed a wireless transportation systems integration company. Prior to that, Mr. Lewis managed an oil and gas exploration subsidiary of a publicly traded utility and was Vice President of EF Hutton in its Municipal Finance group. Mr. Lewis also served on the Boards of Directors of Castle Energy Corporation prior to its merger with the Company in April 2006, and Advanced Aerations Systems, a privately held firm engaged in subsurface soil treatment. Mr. Lewis has a Bachelor of Arts degree in Economics from Haverford College and an MBA from the Harvard School of Business.
James J. Murren is the President and Chief Operating Officer of MGM Mirage. He is also a member of the Board of Directors and the Executive Committee. Mr. Murren has also served as the Chief Financial Officer of the MGM Mirage from January 1998 to August 2007 and Treasurer of MGM Mirage from November 2001 to August 2007. Prior to the MGM Mirage, Mr. Murren spent 14 years on Wall Street as a top-ranked equity analyst and was appointed to Director of Research and Managing Director of Deutsche Bank. Mr. Murren received a Bachelor of Arts degree in Art History and Urban Studies from Trinity College in 1983.
Jordan R. Smith is President of Ramshorn Investments, Inc., a wholly owned subsidiary of Nabors Drilling USA LP that is located in Houston, Texas, where he is responsible for drilling and development projects in a number of producing basins in the United States. He has served in such capacity for more than the past five years. Mr. Smith has served on the Board of the University of Wyoming Foundation and the Board of the Domestic Petroleum Council, and is also Founder and Chairman of the American Junior Golf Association. Mr. Smith received Bachelor and Master degrees in Geology from the University of Wyoming in 1956 and 1957, respectively.
Neal A. Stanley founded Teton Oil & Gas Corporation in Denver, Colorado and has served as President and sole shareholder since 1991. From 1996 to June 2003, he was Senior Vice President – Western Region for Forest Oil Corporation, Denver, Colorado. Since December 2005, Mr. Stanley has served as a member of the Board of Directors and Compensation Committee for Calgary based Pure Energy Services Ltd., which is listed on the Toronto Stock Exchange under the symbol PSV. Mr. Stanley has over thirty years of experience in the oil and gas business. Since 1995, he has been a member of the Executive Committee of the Independent Petroleum Association of Mountain States, and served as its President from 1999 to 2001. Mr. Stanley received a Bachelor of Science degree in Mechanical Engineering from the University of Oklahoma in 1975.
Daniel J. Taylor has been an executive of Tracinda Corporation since February 2007 and has served as a Director of the MGM Mirage since March 2007. Mr. Taylor previously was the President of Metro-Goldwyn-Mayer Inc. (“MGM Studios”) from April 2005 to January 2006 and Senior Executive Vice President and Chief Financial Officer of MGM Studios from June 1998 to April 2005. Mr. Taylor received a Bachelor of Science degree in Business Administration with an emphasis in Accounting from Central Michigan University in 1978.
James B. Wallace has been involved in the oil and gas business for over 40 years and has been a partner of Brownlie, Wallace, Armstrong and Bander Exploration in Denver, Colorado since 1992. From 1980 to 1992 he was Chairman of the Board and Chief Executive Officer of BWAB Incorporated. Mr. Wallace formerly served as a member of the Board of Directors of Ellora Energy, Inc., a public oil and gas exploration company listed on the NASDAQ. He received a Bachelor of Science degree in Business Administration from the University of Southern California in 1951. James B. Wallace is the father of John R. Wallace, the President, Chief Operating Officer and a Director of Delta.
At the present time Messrs. Collins, Eckelberger, Lewis, Smith and Stanley serve as the Audit Committee; Messrs. Eckelberger, Collins, Lewis, Smith and Stanley serve as the Compensation Committee; and Messrs. Smith, Collins, Eckelberger, Lewis and Stanley serve as the Nominating & Governance Committee.
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In conjunction with the February 2008 equity issuance to Tracinda Corporation, and in accordance with the related Company Stock Purchase Agreement, Tracinda designated Messrs. Murren and Taylor to our Board of Directors.
All directors will hold office until the next annual meeting of stockholders. All of our officers will hold office until our next annual meeting of our Board of Directors. There is no arrangement or understanding among or between any such officers or any persons pursuant to which such officer is to be selected as one of our officers.
PART II
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities |
Market Information; Dividends
Delta’s common stock currently trades under the symbol “DPTR” on the NASDAQ Global Market. The following quotations reflect inter-dealer high and low sales prices, without retail mark-up, mark-down or commission and may not represent actual transactions.
Quarter Ended | High | Low | ||||||
September 30, 2005 | $ | 20.82 | $ | 14.01 | ||||
December 31, 2005 | 22.31 | 15.07 | ||||||
March 31, 2006 | $ | 24.95 | $ | 17.82 | ||||
June 30, 2006 | 22.71 | 13.79 | ||||||
September 30, 2006 | 23.27 | 15.02 | ||||||
December 31, 2006 | 30.68 | 20.81 | ||||||
March 31, 2007 | $ | 17.57 | $ | 23.12 | ||||
June 30, 2007 | 18.62 | 24.94 | ||||||
September 30, 2007 | 14.40 | 20.35 | ||||||
December 31, 2007 | 21.58 | 13.06 |
On February 28, 2008, the closing price of our common stock was $24.86. We have not paid dividends on our common stock, and we do not expect to do so in the foreseeable future. Our current debt agreements restrict the payment of dividends.
Approximate Number of Holders of Common Stock
The number of holders of record of our common stock at February 28, 2008 was approximately 1,500 which does not include an estimated 8,200 additional holders whose stock is held in “street name.”
Recent Sales of Unregistered Securities
During the year ended December 31, 2007, we did not have any sale of securities in transactions that were not registered under the Securities Act of 1933, as amended (“Securities Act”) that have not been reported in a Form 8-K or Form 10-Q.
Issuer Purchases of Equity Securities
We did not repurchase any of our shares of common stock during the quarter ended December 31, 2007.
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Item 6. Selected Financial Data
The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.
Six Months Ended | ||||||||||||||||||||||||
Years Ended December 31, | December 31, | Years Ended June 30, | ||||||||||||||||||||||
2007 | 2006 | 2005 | 2005 | 2004 | 2003 | |||||||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||||||||||
Total Revenues | $ | 164,190 | $ | 146,660 | $ | 48,326 | $ | 56,612 | $ | 9,799 | $ | 5,551 | ||||||||||||
Income (loss) from Continuing Operations | $ | (160,228 | ) | $ | (33,623 | ) | $ | (29,203 | ) | $ | (10,353 | ) | $ | (12,081 | ) | $ | (8,156 | ) | ||||||
Net Income (Loss) | $ | (149,347 | ) | $ | 435 | $ | (590 | ) | $ | 15,050 | $ | 5,056 | $ | 1,257 | ||||||||||
Income/(Loss) Per Common Share | ||||||||||||||||||||||||
Basic | $ | (2.44 | ) | $ | .01 | $ | (.01 | ) | $ | .37 | $ | .19 | $ | .05 | ||||||||||
Diluted | $ | (2.44 | ) | $ | .01 | $ | (.01 | ) | $ | .36 | $ | .17 | $ | .05 | ||||||||||
Total Assets | $ | 1,105,195 | $ | 929,323 | $ | 693,393 | $ | 512,983 | $ | 272,704 | $ | 86,847 | ||||||||||||
Total Liabilities | $ | 569,494 | $ | 473,700 | $ | 357,442 | $ | 276,746 | $ | 86,462 | $ | 38,944 | ||||||||||||
Minority Interest | $ | 27,296 | $ | 27,390 | $ | 15,496 | $ | 14,614 | $ | 245 | $ | — | ||||||||||||
Stockholders’ Equity | $ | 508,405 | $ | 428,233 | $ | 320,455 | $ | 221,623 | $ | 185,997 | $ | 47,903 | ||||||||||||
Total Long-Term Liabilities | $ | 426,298 | $ | 374,121 | $ | 257,743 | $ | 222,596 | $ | 72,172 | $ | 33,082 |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are a Denver, Colorado based independent oil and gas company engaged primarily in the exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil. Our core areas of operation are the Rocky Mountain and Gulf Coast Regions, which comprise the majority of our proved reserves, production and long-term growth prospects. We have a significant drilling inventory that consists of proved and unproved locations, the majority of which are located in our Rocky Mountain development projects. At December 31, 2007, we had estimated proved reserves that totaled 375.6 Bcfe, of which 31.8% were proved developed, with an after-tax PV-10 value of $701.9 million. As of December 31, 2007, we achieved net production of 48.7 Mmcfe per day and net continuing production of 37.5 Mmcfe per day.
As of December 31, 2007, our reserves were comprised of approximately 309.5 Bcf of natural gas and 11.0 Mmbbls of crude oil, or 82.4% gas on an equivalent basis. Approximately 21% of our proved reserves were located in the Gulf Coast, 77% in the Rocky Mountains, and 2% in other locations. We expect that our drilling efforts and capital expenditures will focus increasingly on the Rockies, where approximately 87-89% of our fiscal 2008 drilling budget is allocated and more than one-half of our undeveloped acreage is located. As of December 31, 2007, we controlled approximately 871,000 net undeveloped acres, representing approximately 98% of our total acreage position. We retain a high degree of operational control over our asset base, with an average working interest in excess of 85% (excluding CRB properties) as of December 31, 2007. This provides us with controlling interests in a multi-year inventory of drilling locations, positioning us for continued reserve and production growth through our drilling operations. We also have a controlling ownership interest in a drilling company, providing the benefit of access to 15 drilling rigs primarily located in the Rocky Mountain Region. We concentrate our exploration and development efforts in fields where we can apply our technical exploration and development expertise, and where we have accumulated significant operational control and experience.
2008 Outlook
We expect our 2008 oil and gas production to increase 45% to 60% due to the expected results of our budgeted drilling program. For calendar year 2008, we have preliminarily established a drilling budget of approximately $350.0 to $370.0 million. We are concentrating a substantial portion of this budget on the development of our Paradox, Piceance and Wind River Basin assets in the Rockies, and to a lesser extent, our Newton and Midway Loop fields in the Gulf Coast. State of the art geologic and seismic geophysical modeling indicates that these fields have targeted geologic formations containing substantial hydrocarbon deposits that can be economically developed. Recently completed successful wells in several of our Rocky Mountain development programs have found multiple
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accumulations of tight sand reservoirs at various depths, characterized by low permeability and high pressure. These types of reservoirs possess predictable geologic attributes and consistent reservoir characteristics which typically result in a higher drilling success rate and lower per well cost and risk.
The exploration for and the acquisition, development, production, and sale of, natural gas and crude oil are highly competitive and capital intensive. As in any commodity business, the market price of the commodity produced and the costs associated with finding, acquiring, extracting, and financing the operation are critical to profitability and long-term value creation for stockholders. Generating reserve and production growth represents an ongoing focus for management, and is made particularly important in our business by the natural production and reserve decline associated with oil and gas properties. In addition to developing new reserves, we compete to acquire additional reserves, which involves judgments regarding recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. During periods of historically high oil and gas prices, third party contractor and material cost increases are more prevalent due to increased competition for goods and services. Other challenges we face include attracting and retaining qualified personnel, gaining access to equipment and supplies and maintaining access to capital on sufficiently favorable terms.
We have taken the following steps to mitigate the challenges we face. We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, typically costless collars. The level of our hedging activity and the duration of the instruments employed depend upon our review of market conditions, available hedge prices and our operating strategy. As of February 26, 2008, our derivative contracts cover approximately 12.2 Bcfe of our estimated 2008 oil and gas production. Our interest in a drilling and trucking company allows us to mitigate the increasing challenge for rig availability in the Rocky Mountains and also helps to control third party contractor and material costs. Our business strengths include a multi-year inventory of attractive drilling locations and a diverse balance of high return Gulf Coast properties and long lived Rockies reserves, which we believe will allow us to grow reserves and replace and expand production organically without having to rely solely on acquisitions.
Recent developments
During the year ended December 31, 2007, we achieved the following:
• | Increased proved reserves to 375.6 Bcfe at December 31, 2007, an increase of 24.2%, or 31.2% after considering current year sales and purchases, compared to proved reserves as of December 31, 2006 of 302.4 Bcfe. | |
• | Our total production for the year ended December 31, 2007 was 17.8 Bcfe. Adjusted for asset dispositions, our production from continuing operations increased 19% to 13.7 Bcfe, compared to 11.6 Bcfe for the prior year period, primarily as a result of successful exploratory and development drilling during 2007. |
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Results of Operations
The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2007, 2006 and 2005, six months ended December 31, 2005 and 2004, and the fiscal year ended June 30, 2005. During 2005, we changed our fiscal year end from June 30 to December 31, effective December 31, 2005. Accordingly, we have presented below for comparative purposes unaudited historical statements of operations for the year ended December 31, 2005 and six months ended December 31, 2004. The following table sets forth (in thousands), for the periods presented, selected historical statements of operations data. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Annual Report on Form 10-K.
Six Months Ended | Year Ended | |||||||||||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||||||||||
2007 | 2006 | 2005 | 2005 | 2004 | 2005 | |||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||
Revenue: | ||||||||||||||||||||||||
Oil and gas sales | $ | 94,559 | $ | 94,223 | $ | 75,176 | $ | 42,643 | $ | 19,913 | $ | 52,446 | ||||||||||||
Contract drilling and trucking fees | 56,777 | 57,149 | 13,592 | 9,096 | 300 | 4,796 | ||||||||||||||||||
Gain (loss) on effective derivative instruments, net | 12,854 | (4,712 | ) | (3,950 | ) | (3,413 | ) | (93 | ) | (630 | ) | |||||||||||||
Total Revenue | 164,190 | 146,660 | 84,818 | 48,326 | 20,120 | 56,612 | ||||||||||||||||||
Operating Expenses: | ||||||||||||||||||||||||
Lease operating expense | 20,142 | 17,655 | 12,606 | 6,507 | 3,193 | 9,291 | ||||||||||||||||||
Transportation expense | 3,684 | 978 | 994 | 680 | 81 | 394 | ||||||||||||||||||
Production taxes | 5,559 | 4,784 | 4,307 | 2,455 | 1,563 | 3,415 | ||||||||||||||||||
Depreciation, depletion and amortization — oil and gas | 63,373 | 53,980 | 21,594 | 12,411 | 4,862 | 14,055 | ||||||||||||||||||
Depreciation and amortization — drilling and trucking | 22,052 | 16,404 | 3,987 | 2,847 | 386 | 1,525 | ||||||||||||||||||
Exploration expense | 9,062 | 4,690 | 6,933 | 2,061 | 1,283 | 6,155 | ||||||||||||||||||
Dry hole costs and impairments | 85,084 | 15,682 | 5,521 | 5,423 | 2,673 | 2,771 | ||||||||||||||||||
Drilling and trucking operations | 36,954 | 34,163 | 9,413 | 5,821 | 1,074 | 4,666 | ||||||||||||||||||
General and administrative | 49,621 | 35,696 | 26,470 | 16,491 | 6,951 | 16,930 | ||||||||||||||||||
Gain on sale of oil and gas properties | — | (20,034 | ) | — | — | — | — | |||||||||||||||||
Total operating expenses | 295,531 | 163,998 | 91,825 | 54,696 | 22,066 | 59,202 | ||||||||||||||||||
Operating loss | (131,341 | ) | (17,338 | ) | (7,007 | ) | (6,370 | ) | (1,946 | ) | (2,590 | ) | ||||||||||||
Other income and (expense): | ||||||||||||||||||||||||
Other income (expense) | 376 | (154 | ) | (427 | ) | (36 | ) | (179 | ) | (570 | ) | |||||||||||||
Gain on sale of marketable securities | — | — | 1,194 | 1,194 | — | — | ||||||||||||||||||
Gain on sale of investment in LNG | — | 1,058 | — | — | — | — | ||||||||||||||||||
Gain (loss) on ineffective derivative instruments, net | (2,902 | ) | 11,722 | (14,767 | ) | (14,437 | ) | — | (330 | ) | ||||||||||||||
Minority interest | 1,231 | (2,595 | ) | 14 | (688 | ) | 315 | 1,017 | ||||||||||||||||
Losses from unconsolidated affiliates | (393 | ) | — | — | — | — | — | |||||||||||||||||
Interest and financing costs | (27,199 | ) | (26,316 | ) | (14,540 | ) | (8,866 | ) | (2,206 | ) | (7,880 | ) | ||||||||||||
Total other expense | (28,887 | ) | (16,285 | ) | (28,526 | ) | (22,833 | ) | (2,070 | ) | (7,763 | ) | ||||||||||||
Loss from continuing operations before income taxes and discontinued operations | (160,228 | ) | (33,623 | ) | (35,533 | ) | (29,203 | ) | (4,016 | ) | (10,353 | ) | ||||||||||||
Income tax benefit (expense) | (2,677 | ) | 12,623 | 17,485 | 10,873 | — | 11,969 | |||||||||||||||||
Net income (loss) from continuing operations | (162,905 | ) | (21,000 | ) | (18,048 | ) | (18,330 | ) | (4,016 | ) | 1,616 | |||||||||||||
Income from discontinued operations of properties sold, net of tax | 17,556 | 9,163 | 11,966 | 5,952 | 12,770 | 13,434 | ||||||||||||||||||
Gain (loss) on sale of oil and gas properties, net of tax | (3,998 | ) | 6,712 | 11,788 | 11,788 | — | — | |||||||||||||||||
Extraordinary gain, net of tax | — | 5,560 | — | — | — | — | ||||||||||||||||||
Net income (loss) | $ | (149,347 | ) | $ | 435 | $ | 5,706 | $ | (590 | ) | $ | 8,754 | $ | 15,050 | ||||||||||
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Net Income (Loss).Net loss was $149.3 million, or $2.44 per diluted common share, for the year ended December 31, 2007, compared to net income of $435,000 or $.01 per diluted common share, for the year ended December 31, 2006. Loss from continuing operations increased from $21.0 million for the year ended December 31, 2006 to a loss of $162.9 million for the year ended December 31, 2007, due primarily to dry hole costs and impairments, first half 2006 gains on undeveloped property sales and gains on ineffective derivative instruments that did not occur during 2007, and due to higher depreciation, depletion, and amortization expense, and increased general and administrative expense in 2007. Net loss increased significantly due to the valuation allowance required to be recorded against the Company’s deferred tax assets during the second quarter of 2007.
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Oil and Gas Sales. During the year ended December 31, 2007, oil and gas sales from continuing operations were $94.6 million, as compared to $94.2 million for the comparable period a year earlier. During the year ended December 31, 2007, production from continuing operations increased by 19%, however, this was offset by a 23% decrease in the average gas price. The average onshore gas price received during the year ended December 31, 2007 was $4.47 per Mcf compared to $5.79 per Mcf for the year earlier period, primarily due to the increase in the basis differential applicable to Rocky Mountain natural gas. The average onshore oil price received during the year ended December 31, 2007 increased to $68.85 per Bbl compared to $64.37 per Bbl for the year earlier period and the offshore oil price increased to $52.96 per Bbl during the year ended December 31, 2007 compared to $46.75 for the year earlier period.
Net gains (losses) from effective hedging activities were a $12.9 million gain and a $4.7 million loss for the year ended December 31, 2007 and 2006, respectively. The gain in 2007 realized hedges is primarily due to lower oil and gas prices. These gains (losses) are recorded as an increase or decrease in revenues.
Contract Drilling and Trucking Fees. At December 31, 2007 DHS owned 15 drilling rigs with depth ratings of approximately 10,000 to 20,000 feet. We have the right to use all of the rigs on a priority basis, although approximately half are currently working for third party operators.
Drilling revenues for the year ended December 31, 2007 remained flat at $50.5 million compared to $50.0 million for the prior year period. Drilling revenue is earned under daywork or turnkey contracts where we provide a drilling rig with required personnel to our third party customers who supervise the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is in use or on a negotiated fixed rate for drilling to a certain depth. During the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate set in the contract. Drilling revenues earned on wells drilled for Delta have been eliminated through consolidation.
Trucking revenues for the year ended December 31, 2007 were $6.3 million compared to $7.1 million for the prior year period. Trucking revenues decreased in 2007 due to fewer rigs being transported in Wyoming where C&L Drilling operates.
Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the years ended December 31, 2007 and 2006 are as follows:
Years Ended December 31, | ||||||||||||||||
2007 | 2006(1) | |||||||||||||||
Onshore | Offshore | Onshore | Offshore | |||||||||||||
Production – Continuing Operations: | ||||||||||||||||
Oil (MBbl) | 703 | 146 | 856 | 162 | ||||||||||||
Gas (MMcf) | 8,600 | — | 5,438 | — | ||||||||||||
Production – Discontinued Operations: | ||||||||||||||||
Oil (MBbl) | 236 | — | 335 | — | ||||||||||||
Gas (MMcf) | 2,652 | — | 2,585 | — | ||||||||||||
Total Production (MMcfe) | 16,888 | 875 | 15,173 | 975 | ||||||||||||
Average Price – Continuing Operations: | ||||||||||||||||
Oil (per barrel) | $ | 68.85 | $ | 52.96 | $ | 64.37 | $ | 46.75 | ||||||||
Gas (per Mcf) | $ | 4.47 | $ | — | $ | 5.79 | $ | — | ||||||||
Costs per Mcfe – Continuing Operations: | ||||||||||||||||
Hedge gain (loss) | $ | 1.00 | $ | — | $ | (.45 | ) | $ | — | |||||||
Lease operating expense | $ | 1.29 | $ | 4.09 | $ | 1.32 | $ | 3.75 | ||||||||
Production taxes | $ | .43 | $ | .07 | $ | .45 | $ | .05 | ||||||||
Transportation costs | $ | .29 | $ | — | $ | .09 | $ | — | ||||||||
Depletion expense | $ | 4.69 | $ | 1.47 | $ | 4.85 | $ | 1.08 |
(1) | Revised for operations discontinued in 2007. |
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Lease Operating Expense.Lease operating expenses for the year ended December 31, 2007 were $20.1 million compared to $17.7 million for the year earlier period. Lease operating expense from continuing operations for onshore properties for the year ended December 31, 2007 was $1.29 per Mcfe as compared to $1.32 per Mcfe for the year earlier period.
Depreciation, Depletion and Amortization – oil and gas.Depreciation, depletion and amortization expense increased 17% to $63.4 million for the year ended December 31, 2007, as compared to $54.0 million for the year earlier period. Depletion expense for the year ended December 31, 2007 was $61.5 million compared to $52.4 million for the year ended December 31, 2006. The 17% increase in depletion expense was due to a 19% increase in production from continuing operations, slightly offset by a 3% decrease in the onshore depletion rate. Our onshore depletion rate decreased to $4.69 per Mcfe for the year ended December 31, 2007 from $4.85 per Mcfe for the year earlier period. The decrease is partially due to lower finding costs per Mcfe on the Company’s extensive 2007 Rockies drilling program. Based on impairments recorded in 2007 and the Company’s continued focus in the Rockies which continues to result in better well economics, the Company anticipates its depletion rate will continue to decrease in 2008.
Depreciation and Amortization – drilling and trucking.Depreciation and amortization expense – drilling and trucking increased to $22.1 million for the year ended December 31, 2007 as compared to $16.4 million for the prior year period. This increase can be attributed to a greater average number of rigs that DHS owned in 2007 compared to the prior year.
Exploration Expense.Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the year ended December 31, 2007 were $9.1 million compared to $4.7 million for the year earlier period. Current year exploration activities increased and included the acquisition and processing of the seismic program related to acreage in Opossum Hollow, Texas, processing for 2D seismic costs in the central Utah Hingeline, and 3D seismic costs to evaluate leasehold positions for additional drilling locations in Wyoming.
Dry Hole Costs and Impairments.We incurred dry hole costs of approximately $26.7 million for the year ended December 31, 2007 compared to $4.3 million for the comparable period a year ago. For the year ended December 31, 2007, our dry hole costs related primarily to seven exploratory projects, three in Texas, two in Wyoming, one well in Colorado and one in Utah. For the year ended December 31, 2006, the dry hole costs related primarily to exploratory projects in Texas and Utah.
During the year ended December 31, 2007, the Company recorded impairments totaling approximately $58.4 million primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 million and $10.3 million, respectively), and the South Angleton field in Texas ($9.7 million), primarily due to lower Rocky Mountain natural gas prices and marginally economic deep zones on the Howard Ranch Prospect.
During the year ended December 31, 2006, an impairment of $10.4 million was recorded on certain of the Company’s eastern Colorado properties primarily due to lower Rocky Mountain natural gas prices. In addition, an impairment of $1.0 million was recorded on certain Oklahoma properties that are held for sale at December 31, 2007.
Drilling and Trucking Operations. We had drilling and trucking operations expense of $37.0 million during the year ended December 31, 2007 compared to $34.2 million during the year ended December 31, 2006. The significant increase in expenses was due to the greater average overall number of rigs in operation for DHS in 2007 than in the prior year.
General and Administrative Expense.General and administrative expense increased 39% to $49.6 million for the year ended December 31, 2007, as compared to $35.7 million for the comparable prior year period. The increase in general and administrative expenses is primarily attributed to an increase in non-cash equity compensation of $10.7 million and a 23% increase in technical and administrative staff and related personnel costs.
Gain on Sale of Oil and Gas Properties.In January and March 2006, Delta sold a combined 44% minority interest in CRBP. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, we recorded a $13.0 million gain ($8.1 million net of tax), and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction.
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In November 2006, we sold certain undeveloped property interests in the Columbia River Basin for proceeds of $2.0 million. We recorded a gain on the transaction of $1.1 million.
In March 2006, we sold approximately 26% of PGR. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain could be recognized as all of the unproved cost basis was not yet recovered. We recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million offset to property during the first quarter of 2006 as a result of the transaction. We retained a 74% interest in, and are the manager of, PGR.
Gain on Sale of Investment in LNG Project.On March 30, 2006, we sold our long-term minority interest investment in an LNG project for total proceeds of $2.1 million. We recorded a gain on sale of $1.1 million ($657,000 net of tax).
Gain (Loss) on Ineffective Derivative Instruments, Net. Effective July 1, 2007, we discontinued cash flow hedge accounting. Beginning July 1, 2007, we recognize mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income for the contracts that qualify as cash flow hedges. As a result, we recognized in our statements of operations a loss of $2.9 million for the year ended December 31, 2007 and a gain of $11.7 million for the year ended December 31, 2006.
Minority Interest.Minority interest represents the minority investors’ percentage of their share of income or losses from DHS in which they hold an interest. During the year ended December 31, 2007 DHS generated a loss resulting in decreased minority interest expense.
Interest and Financing Costs, Net.Interest and financing costs increased 3% to $27.2 million for the year ended December 31, 2007, as compared to $26.3 million for the comparable year earlier period. The increase is primarily related to higher average debt balances on DHS’ credit facility during the year and costs related to the refinancing of DHS credit facilities in May and December, offset by lower average balances outstanding on Delta’s credit facility.
Income Tax Expense.Due to our continued losses, we were required by the “more likely than not” provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”), to record a valuation allowance on our deferred tax assets beginning with the second quarter of 2007. As a result, our income tax expense for the year ended December 31, 2007 of $2.7 million includes a valuation allowance of $57.4 million. During the year ended December 31, 2006, an income tax benefit of $12.6 million was recorded for continuing operations at an effective tax rate of 37.5%.
Discontinued Operations.Discontinued operations include the Frisco field in Pointe Coupee Parish, Louisiana, which was sold in June 2006, the Panola and Rusk County, Texas properties, which were sold in August 2006, the East Texas and Pennsylvania properties, which were sold in August 2006, the Kansas field, which was sold in January 2007, the Australia field and the New Mexico and East Texas properties, which were sold in March 2007, the North Dakota properties sold in September 2007, the Washington County, Colorado properties sold in October 2007, and the Midway Loop, Texas properties held for sale at December 31, 2007. The results of operations on these assets, net of tax, during the years ended December 31, 2007 and 2006 were $17.6 million and $9.2 million, respectively. The significant increase in 2007 was primarily due to new wells in 2007 from the Company’s Midway Loop drilling program or wells drilled in 2006 impacting sales for the full year in 2007.
Gain (Loss) on Sale of Discontinued Operations.During the year ended December 31, 2007, we sold non-core properties in Colorado, Kansas, Texas, New Mexico, Australia and North Dakota for combined proceeds of $46.4 million and a combined net loss of $4.0 million. During the year ended December 31, 2006, we sold certain non-core properties located in Louisiana and East Texas for combined proceeds of $23.8 million and an after-tax gain of $6.7 million.
Extraordinary Gain.On August 21, 2006, the Company completed the sale of the properties acquired with the Castle acquisition in April 2006. During the year ended December 31, 2006 the Company recorded a $5.6 million extraordinary gain, net of tax in accordance with SFAS No. 141 “Business Combinations” (“SFAS 141”).
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Year Ended December 31, 2006 Compared to Year Ended December 31, 2005 (Unaudited)
Net Income.Net income decreased $5.3 million to $435,000, or $.01 per diluted common share, for the year ended December 31, 2006, as compared to net income of $5.7 million, or $.13 per diluted common share, for the year ended December 31, 2005. This decrease was primarily due to an $10.3 million increase in operating losses resulting from higher revenue and a $20.0 million gain on the sale of oil and gas properties, offset by higher depreciation, depletion, and amortization expense, higher exploration, dry hole and abandonment costs, and increased general and administrative expenses.
Oil and Gas Sales.During the year ended December 31, 2006, oil and natural gas revenue from continuing operations increased 25% to $94.2 million, as compared to $75.2 million for the year ended December 31, 2005. The increase was the result of a 19% increase in average daily production from continuing operations over the year ended December 31, 2005, an increase in average onshore oil price received in the year ended December 31, 2006 of $64.37 per Bbl compared to $54.77 per Bbl during the same period in 2005, and an increase in offshore oil price received of $46.75 per Bbl during the year ended December 31, 2006 compared to $41.46 during the year ended December 31, 2005, partially offset by a decrease in the average onshore gas price received during the year ended December 31, 2006 of $5.79 per Mcf compared to $7.09 per Mcf received in the year ended December 31, 2005.
Net realized losses from effective hedging activities were $4.7 million and $4.0 million for the years ended December 31, 2006 and 2005, respectively. The increase in 2006 in realized hedging losses is primarily due to higher oil prices. These losses are recorded as a decrease in total revenues.
Contract Drilling and Trucking Fees.At December 31, 2006 DHS owned 16 drilling rigs with depth ratings of approximately 7,500 to 20,000 feet. We have the right to use all of the rigs on a priority basis, although approximately three-fourths were working for third party operators at December 31, 2006.
Drilling revenues for the year ended December 31, 2006 increased to $50.0 million compared to $13.0 million for the prior year period. Drilling revenue is earned under daywork contracts where we provide a drilling rig with required personnel to our third party customers who supervise the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is in use. During the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate set in the contract. Drilling revenues earned on wells drilled for Delta have been eliminated through consolidation. At December 31, 2006 there were 16 DHS rigs in operation compared to eight rigs in operation at December 31, 2005.
Trucking revenues for the year ended December 31, 2006 were $7.1 million compared to $630,000 for the prior year period. Trucking revenues were insignificant during the year ended December 31, 2005 as the acquisition of Chapman Trucking Company was completed in November, 2005.
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Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the years ended December 31, 2006 and 2005 are as follows:
Year Ended December 31, | ||||||||||||||||
2006(1) | 2005(1) | |||||||||||||||
Onshore | Offshore | Onshore | Offshore | |||||||||||||
Production – Continuing Operations: | ||||||||||||||||
Oil (MBbl) | 856 | 162 | 508 | 162 | ||||||||||||
Gas (MMcf) | 5,438 | — | 5,727 | — | ||||||||||||
Production – Discontinued Operations: | ||||||||||||||||
Oil (MBbl) | 335 | — | 387 | — | ||||||||||||
Gas (MMcf) | 2,585 | — | 2,371 | — | ||||||||||||
Total Production (MMcfe) | 15,173 | 975 | 13,474 | 972 | ||||||||||||
Average Price – Continuing Operations: | ||||||||||||||||
Oil (per barrel) | $ | 64.37 | $ | 46.75 | $ | 54.77 | $ | 41.46 | ||||||||
Gas (per Mcf) | $ | 5.79 | $ | — | $ | 7.09 | $ | — | ||||||||
Costs per Mcfe – Continuing Operations: | ||||||||||||||||
Hedge gain (loss) | $ | (.45 | ) | $ | — | $ | (.45 | ) | $ | — | ||||||
Lease operating expense | $ | 1.32 | $ | 3.75 | $ | .95 | $ | 4.42 | ||||||||
Production taxes | $ | .45 | $ | .05 | $ | .48 | $ | .06 | ||||||||
Transportation costs | $ | .09 | $ | — | $ | .11 | $ | — | ||||||||
Depletion expense | $ | 4.85 | $ | 1.08 | $ | 2.27 | $ | .79 |
(1) | Revised for operations discontinued in 2007. |
Lease Operating Expense.Lease operating expenses for the year ended December 31, 2006 were $17.7 million compared to $12.6 million for the same period a year earlier. Lease operating expense increased due to our 19% increase in production and due to increased per unit costs. Lease operating expense from continuing operations for onshore properties for the year ended December 31, 2006 was $1.32 per Mcfe as compared to $.95 per Mcfe for the same period a year earlier. Lease operating expense from continuing operations for offshore properties was $3.75 per Mcfe for the year ended December 31, 2006 and $4.42 per Mcfe for the same period a year earlier. The increase in onshore per unit lease operating expenses is a result of generally rising field costs due to increased demand for services, and is also affected by overall infrastructure costs for some properties that were still experiencing limited production due to pipeline constraints.
Depreciation, Depletion and Amortization – oil and gas.Depreciation, depletion and amortization expense increased 130% to $54.0 million in the year ended December 31, 2006, as compared to $21.6 million for the year ended December 31, 2005. Depletion expenses for our onshore properties increased to $4.85 per Mcfe during the year ended December 31, 2006 from $2.27 per Mcfe for the year ended December 31, 2005. The depletion rate increase is partially due to certain deep, multi-stage completion projects in which the majority of our well costs are depleted over completed zones that have not met initial expectations. Also, during the year ended December 31, 2006, a $3.0 million developmental dry hole in South Angleton was added to the depletion pool.
Depreciation and Amortization – drilling and trucking.Depreciation and amortization expense – drilling and trucking increased to $16.4 million for the year ended December 31, 2006 as compared to $4.0 million for the prior year period. This increase can be attributed to additional rigs acquired by DHS Drilling Company.
Exploration Expense.Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the year ended December 31, 2006 were $4.7 million compared to $6.9 million for the year ended December 31, 2005. Activities in the year ended December 31, 2006 included activities in our Columbia River Basin, Washington, Grand County, Utah and Newton County, Texas projects. During the year ended December 31, 2005, our most significant exploration cost was related to the $1.4 million Newton 3D seismic shoot covering 58 square miles which was completed and processed during 2005. In addition, we acquired 2D data in the Gulf Coast Region and also began acquiring geophysical data on the Columbia River Basin properties in the state of Washington.
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Dry Hole Costs and Impairments.We incurred dry hole costs of approximately $4.3 million for the year ended December 31, 2006 compared to $4.2 million for the same period in the prior year. During 2005, a significant portion of these costs were related to dry holes that were drilled in Utah and California. For the year ended December 31, 2006, the dry hole costs related primarily to exploratory projects in Texas and Utah.
During the year ended December 31, 2006, an impairment of $10.4 million was recorded on certain of the Company’s eastern Colorado properties primarily due to lower Rocky Mountain natural gas prices. In addition, an impairment of $1.0 million was recorded on certain Oklahoma properties that were held for sale at December 31, 2006. During 2007, we are continuing to develop and evaluate certain properties on which favorable or unfavorable results or commodity prices may cause us to revise in future quarters our estimates of those properties’ future cash flows. Such revisions of estimates could require us to record an impairment in the period of such revisions.
During the year ended December 31, 2005, a dry hole was drilled on a prospect located in California. Based on drilling results and evaluation of the prospect, we determined that we would not pursue development and accordingly an impairment of $1.3 million was recorded for the full impairment of the remaining leasehold costs related to the prospect.
Drilling and Trucking Operations. We had drilling and trucking operations expense of $34.2 million during the year ended December 31, 2006 compared to $9.4 million during the year ended December 31, 2005. The significant increase in expenses was due to an increase in the number of rigs in operation, 16 rigs as of December 31, 2006 compared to eight rigs at December 31, 2005.
General and Administrative Expense.General and administrative expense increased 35% to $35.7 million for the year ended December 31, 2006 as compared to $26.5 million for the year ended December 31, 2005. The increase in general and administrative expenses is primarily attributed to an increase in non-cash equity compensation of $2.1 million, a 45% increase in technical and administrative staff and related personnel costs, and the expansion of our office facility. In addition, $2.1 million of the increase is related to DHS general and administrative expense. DHS general and administrative expense increased with added headcount for DHS growth during the year ended December 31, 2006 and a full year of operations in 2006 compared to nine months of operations in 2005.
Gain on Sale of Oil and Gas Properties.During December 2005, Delta transferred its ownership in approximately 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin to CRBP. In January and March 2006, Delta sold a combined 44% minority interest in CRBP. Accordingly, the Company recorded a $13.0 million gain ($8.1 million, net of tax) and a $11.2 million reduction to property during the first quarter of 2006 as a result of the closing of the transaction.
In November 2006, the Company sold certain undeveloped property interests in the Columbia River Basin for proceeds of $2.0 million. The Company recorded a gain on the transaction of $1.1 million.
In March 2006, the Company sold approximately 26% of PGR. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain could be recognized as all of the unproved cost basis was not yet recovered. The Company recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million offset to property during the first quarter of 2006 as a result of the transaction. The Company retained a 74% interest in, and is the manager of, PGR.
Gain on Sale of Marketable Security.During the year ended December 31, 2005, the Company sold investment securities classified as available-for-sale securities resulting in a realized gain of $1.2 million.
Gain on Sale of Investment in LNG Project.On March 30, 2006, the Company sold its long-term minority interest investment in an LNG project for total proceeds of $2.1 million. The Company recorded a gain on sale of $1.1 million ($657,000 net of tax).
Gain (Loss) on Ineffective Derivative Instruments, Net.During the year ended December 31, 2005, our gas derivative contracts became ineffective and no longer qualified for hedge accounting. Hedge ineffectiveness results from different changes in the NYMEX contract terms and the physical location, grade and quality of our oil and gas production. The change in fair value of our NYMEX gas contracts is reflected in earnings, as opposed to being
45
recorded in other comprehensive income (loss), a component of stockholders’ equity. As a result, we recognized an $11.7 million gain and a $14.8 million loss in our statements of operations for the years ended December 31, 2006 and 2005, respectively. As commodity prices fluctuate, we will record our NYMEX gas derivative contracts at market value with any changes in market value recorded through unrealized gain (loss) on derivative contracts in our statement of operations.
Minority Interest.Minority interest represents the minority investors’ percentage of their share of income or losses from DHS in which they hold an interest. During the year ended December 31, 2006 DHS generated a greater profit, resulting in increased minority interest expense.
Interest and Financing Costs.Interest and financing costs increased 81% to $26.3 million for the year ended December 31, 2006, as compared to $14.5 million for the year ended December 31, 2005. The increase is primarily related to the increase in the average amount outstanding under our credit facility, higher interest rates and the increased long term debt balance related to the DHS credit facility. In addition, during 2006, DHS incurred a pre-payment penalty of $820,000 and wrote-off deferred financing costs of $431,000 to pay-off a term loan that was replaced with a lower interest rate term loan.
Income tax benefit.During the year ended December 31, 2006, an income tax benefit of $12.6 million was recorded for continuing operations at an effective tax rate of 37.5% compared to an income tax benefit of $17.5 million and an effective tax rate of 49.2% for the year ended December 31, 2005. The 2005 rate was significantly affected by the reversal of a valuation allowance related to the Company’s deferred tax assets.
Discontinued Operations.Discontinued operations include the Deerlick Creek Field in Tuscaloosa County, Alabama, which was sold in September 2005, the Frisco Field in Pointe Coupee Parish, Louisiana, which was sold in June 2006, the Panola and Rusk County, Texas properties, which were sold in August 2006, the East Texas and Pennsylvania properties, which were sold in August 2006, and the Kansas Field, which was sold in January 2007, the Australia field and the New Mexico and East Texas properties, which were sold in March 2007, the North Dakota properties sold in September 2007, the Washington County, Colorado properties sold in October 2007, and the Midway Loop, Texas properties held for sale at December 31, 2007. The results of operations on these assets, net of tax, during the years ended December 31, 2006 and 2005 were $9.2 million and $12.0 million, respectively.
Extraordinary Gain.An extraordinary gain was recorded during the year ended December 31, 2006 as required by SFAS 141. Due to the excess fair value of the assets compared to the purchase price of the transaction and the Company’s intention to sell the oil and gas properties, Delta recorded a $5.6 million extraordinary gain, net of tax, during the year ended December 31, 2006. The oil and gas properties acquired from Castle were in fact sold during August 2006.
Six Months Ended December 31, 2005 Compared to Six Months Ended December 31, 2004 (Unaudited)
Net Income.Net income decreased $9.5 million to a net loss of $590,000 or $.01 per diluted common share for the six months ended December 31, 2005, as compared to net income of $8.8 million or $.21 per diluted common share for the six months ended December 31, 2004. This decrease was primarily due to a $14.4 million loss for ineffective hedges, $3.4 million of realized losses on effective hedging contracts, higher exploration and dry hole costs, increased general and administrative expenses of $9.5 million due to the growth in the Company’s operations and activities, and increased interest and financing costs of $6.7 million due to higher average debt outstanding.
Revenue. During the six months ended December 31, 2005, oil and natural gas revenue from continuing operations increased 114% to $42.6 million, as compared to $19.9 million for the six months ended December 31, 2004. The increase was the result of an average onshore gas price received during the six months ended December 31, 2005 of $8.78 per Mcf compared to $5.56 per Mcf received in the six months ended December 31, 2004, an increase in average onshore oil price received in the six months ended December 31, 2005 of $59.62 per Bbl compared to $45.41 per Bbl during the same period in 2004, an increase in offshore oil price received of $47.12 per Bbl during the six months ended December 31, 2005 compared to $30.66 during the six months ended December 31, 2004, and a 44% increase in continuing average daily production over the six months ended December 31, 2004.
Cash payments required on our effective hedging activities impacted revenues during the six months ended December 31, 2005 and 2004. The cost of settling our effective hedging activities was $3.4 million and $93,000 during the six months ended December 31, 2005 and 2004, respectively.
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Contract Drilling and Trucking Fees.At December 31, 2005 DHS owned eleven drilling rigs with depth ratings of approximately 7,500 to 20,000 feet. In early 2006, two additional rigs were acquired. We have the right to use all of the rigs on a priority basis, although approximately half were working for third party operators at December 31, 2005.
Drilling revenues for the six months ended December 31, 2005 increased to $9.1 million compared to $300,000 for the prior year period. Drilling revenue is earned under daywork contracts where we provide a drilling rig with required personnel to our third party customers who supervise the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is in use. During the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate set in the contract. Drilling revenues earned on wells drilled for Delta have been eliminated through consolidation. At December 31, 2005 there were eight DHS rigs in operation compared to four rigs in operation at June 30, 2005.
Trucking revenues were insignificant during the six months ended December 31, 2005 as the Chapman acquisition was completed in November 2005.
Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the six months ended December 31, 2005 and 2004 are as follows:
Six Months Ended December 31, | ||||||||||||||||
2005(1) | 2004(1) | |||||||||||||||
Onshore | Offshore | Onshore | Offshore | |||||||||||||
Production – Continuing Operations: | ||||||||||||||||
Oil (MBbl) | 264 | 81 | 159 | 74 | ||||||||||||
Gas (MMcf) | 2,634 | — | 1,870 | — | ||||||||||||
Production – Discontinued Operations: | ||||||||||||||||
Oil (MBbl) | 164 | — | 272 | — | ||||||||||||
Gas (MMcf) | 931 | — | 1,427 | — | ||||||||||||
Total Production (MMcfe) | 6,285 | 485 | 5,884 | 444 | ||||||||||||
Average Price – Continuing Operations: | ||||||||||||||||
Oil (per barrel) | $ | 59.62 | $ | 47.12 | $ | 45.41 | $ | 30.66 | ||||||||
Gas (per Mcf) | $ | 8.78 | $ | — | $ | 5.56 | $ | — | ||||||||
Costs per Mcfe – Continuing Operations: | ||||||||||||||||
Hedge gain (loss) | $ | (.81 | ) | $ | — | $ | (.03 | ) | $ | — | ||||||
Lease operating expense | $ | 1.01 | $ | 4.62 | $ | 0.57 | $ | 3.56 | ||||||||
Production taxes (benefit) | $ | .61 | $ | (.23 | ) | $ | .54 | $ | .06 | |||||||
Transportation costs | $ | .16 | $ | — | $ | .03 | $ | — | ||||||||
Depletion expense | $ | 2.73 | $ | .79 | $ | 1.40 | $ | .75 |
(1) | Revised for operations discontinued in 2007. |
Lease Operating Expense.Lease operating expenses for the six months ended December 31, 2005 were $6.5 million compared to $3.2 million for the same period a year earlier. Lease operating expense from continuing operations for onshore properties for the six months ended December 31, 2005 was $1.01 per Mcfe as compared to $0.57 per Mcfe for the same period a year earlier. Lease operating expense from continuing operations for offshore properties was $4.62 per Mcfe for the six months ended December 31, 2005 and $3.56 per Mcfe for the same period a year earlier. This increase in lease operating costs from continuing operations per Mcfe can be primarily attributed to the increase in the percentage of wells owned in the Gulf Coast Region, largely due to the Manti acquisition in January 2005, as compared to our other regions. Our Gulf Coast properties typically have higher average lease operating costs. Newton also experienced substantial costs related to compression and salt water hauling and disposal.
Depreciation, Depletion and Amortization – oil and gas.Depreciation, depletion and amortization expense increased 155% to $12.4 million in the six months ended December 31, 2005, as compared to $4.9 million for the six months ended December 31, 2004. Depreciation expenses for our onshore properties increased to $2.73 per Mcfe during the six months ended December 31, 2005 from $1.40 per Mcfe for the six months ended December 31, 2004. Depletion rates have increased based on the higher amounts paid to acquire reserves in the ground and the increase in
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drilling costs relative to reserve additions. We also incurred higher depletion rates caused by lower proved developed producing reserves in our South Angleton field from unsuccessful drilling results.
Depreciation and Amortization – drilling and trucking.Depreciation and amortization expense – drilling and trucking increased to $2.8 million for the six months ended December 31, 2005 as compared to $386,000 for the prior year period. This increase can be attributed to additional rigs acquired by DHS Drilling Company.
Exploration Expense.Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the six months ended December 31, 2005 were $2.1 million compared to $1.3 million for the six months ended December 31, 2004. The increase in exploration costs was primarily related to seismic costs and impairment of prospect acquisition costs. During the six months ended December 31, 2005, our most significant exploration cost related to the $1.4 million Newton 3D seismic shoot covering 58 square miles which was completed and processed during 2005 and which assisted us in prioritizing our drilling locations and identifying target formations. In addition, we acquired 2D data in the Gulf Coast Region and also began acquiring geophysical data on the Columbia River Basin properties in the state of Washington.
Dry Hole Costs and Impairments.We incurred dry hole costs of approximately $4.1 million for the six months ended December 31, 2005 compared to $2.7 million for the same period a year ago. During 2004, a significant portion of these costs related to our Trail Blazer prospect in Laramie County, Wyoming and four non-Niobrara formation dry holes in Washington County, Colorado. During the six months ended December 31, 2005, four dry holes were drilled including two in Washington County, Colorado, one in Utah, and one in Orange County, California.
During the six months ended December 31, 2005, a dry hole was drilled on a prospect located in Orange County, California. Based on drilling results and evaluation of the prospect, we determined that we would not pursue development and accordingly, an impairment of $1.3 million was recorded for the full impairment of the remaining leasehold costs related to the prospect.
Drilling and Trucking Operations. We had drilling and trucking operations of $5.8 million during the six months ended December 31, 2005 compared to $1.1 million during the six months ended December 31, 2004. The significant increase in expenses was due to an increase in the number of rigs in operation, eight rigs as of December 31, 2005 compared to two rigs at December 31, 2004.
General and Administrative Expense.General and administrative expense increased 137% to $16.5 million for the six months ended December 31, 2005 as compared to $7.0 million for the six months ended December 31, 2004. The increase in general and administrative expenses is primarily attributed to $2.1 million of stock option compensation expense related to the adoption of SFAS No. 123 (Revised 2004), “Share Based Payment” (“SFAS 123R”), $1.4 million increase in professional fees attributed largely to compliance with the Sarbanes-Oxley Act, a 60% increase in technical and administrative staff and related personnel costs, the expansion of our office facility and $715,000 of vested restricted stock and option awards granted to officers, directors and management.
Gain on Sale of Marketable Security.During the six months ended December 31, 2005, the Company sold investment securities classified as available-for-sale securities resulting in a realized gain of $1.2 million.
Losses on Ineffective Derivative Instruments, Net.During the six months ended December 31, 2005, our gas derivative contracts became ineffective and no longer qualified for hedge accounting. Hedge ineffectiveness results from different changes in the NYMEX contract terms and the physical location, grade and quality of our oil and gas production. The change in fair value of our gas contracts in the six month period are reflected in earnings, as opposed to being recorded in other comprehensive income (loss), a component of stockholders’ equity. As a result, we recognized a $14.4 million loss in our statement of operations. As commodity prices fluctuate, we will record our gas derivative contracts at market value with any changes in market value recorded through unrealized gain (loss) on derivative contracts in our statement of operations. Our oil derivative contracts continue to qualify for hedge accounting.
Minority Interest.Minority interest represents the minority investors’ percentage of their share of income or losses from Big Dog, Shark or DHS in which they hold an interest. During the six months ended December 31, 2004, Big Dog and Shark incurred operating losses. During the six months ended December 31, 2005, DHS generated an operating profit.
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Interest and Financing Costs.Interest and financing costs increased 302% to $8.9 million for the six months ended December 31, 2005, as compared to $2.2 million for the six months ended December 31, 2004. The increase is primarily related to interest on the $150.0 million senior notes that were issued in March 2005, the increase in the average amount outstanding under our credit facility, primarily as a result of the Manti acquisition completed in January 2005, and our increased investment in the Columbia River Basin prospect in Washington completed in April 2005. In addition, borrowings of $35.0 million by DHS in 2005 also resulted in increased interest expense.
Income tax benefit.Prior to June 30, 2005, the Company recorded a full valuation allowance on its deferred tax assets and accordingly, during the six months ended December 31, 2004, no income tax provision was recorded.
During the six months ended December 31, 2005, an income tax benefit of $10.9 million was recorded for continuing operations at an effective tax rate of 37.2%.
Discontinued Operations.On September 2, 2005, we completed the sale of our Deerlick Creek field in Tuscaloosa County, Alabama for $30.0 million with an effective date of July 1, 2005. We recorded a gain on sale of oil and gas properties of $10.2 million on net proceeds of $28.9 million after normal closing adjustments. Income from discontinued operations of properties sold has been restated to include the Deerlick Field sold in September 2005, Frisco Field sold in June 2006, East Texas properties and Pennsylvania properties acquired in the Castle acquisition which were sold in August 2006, the Company’s Kansas field sold in January 2007, the Australia field and the New Mexico and East Texas properties, which were sold in March 2007, the North Dakota properties sold in September 2007, the Washington County, Colorado properties sold in October 2007, and the Midway Loop, Texas properties held for sale at December 31, 2007. The results of operations on these assets during the six months ended December 31, 2005 and 2004 were $6.0 million and $12.8 million, respectively.
Liquidity and Capital Resources
Liquidity is a measure of a company’s ability to access cash. In February 2008, we significantly improved our liquidity position with $684 million in gross proceeds from the sale of 36 million shares to Tracinda Corporation. As of December 31, 2007, our corporate rating and senior unsecured debt rating were Caa1 and Caa2, respectively, as issued by Moody’s Investors Service. Moody’s outlook is “stable.” As of December 31, 2007, our corporate credit and senior unsecured debt ratings were B- and CCC+, respectively, as issued by Standard and Poor’s (“S&P”). S&P’s outlook on the rating was “stable.” Subsequent to year end, S&P placed the ratings on CreditWatch with positive implications following the announced investment by Tracinda Corporation. We have completed several equity, debt, and property transactions in the past year as described below. On January 25, 2007, we completed a public offering of 2,768,000 shares of our common stock for net proceeds of $56.4 million. During the year ended December 31, 2007, we sold non-core properties in Kansas, Texas, New Mexico, Australia, and North Dakota for combined net proceeds of $46.4 million. On April 25, 2007, we issued 7,130,000 shares of common stock at $20.50 per share and issued $115.0 million aggregate principal amount of 33/4% Senior Convertible Notes due 2037 for total net proceeds of $251.9 million after underwriters’ discounts and commissions of $9.3 million.
Our cash requirements are largely dependent upon the number and timing of projects included in our capital development plan, most of which are discretionary. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities when market conditions permit, through cash provided by operating activities, sales of oil and gas properties, and through borrowings under our credit facility.
During the year ended December 31, 2007, we had an operating loss of $131.3 million, but generated cash from operating activities of $84.4 million and obtained cash from financing activities of $243.1 million. During this period we spent $286.3 million on oil and gas development (or $332.5 million, net of $46.2 million proceeds from dispositions), $4.5 million on oil and gas acquisitions, and $15.2 million on drilling and trucking capital expenditures (or $22.3 million, net of $7.1 million proceeds from dispositions). At December 31, 2007, we had $10.1 million in cash, total assets of $1.1 billion and a debt to capitalization ratio of 44.9%. Long-term debt at December 31, 2007 totaled $413.1 million, comprised of $148.6 million of bank debt, $149.5 million of senior subordinated notes and $115.0 million of senior convertible notes. In April 2007 and again in February 2008, our credit facility was paid down in full with proceeds from our debt and equity offerings. Available borrowing capacity under our bank credit facility at December 31, 2007 was approximately $140.0 million with a balance outstanding of $73.6 million. In December 2007, DHS closed a new $75.0 million credit facility with Lehman Brothers Commercial Paper, as administrative agent. DHS has no additional availability under its credit facility.
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At December 31, 2007, we were in compliance with our quarterly financial covenants. Our covenants require a minimum current ratio of 1 to 1, net of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 4.0 to 1 for the quarter ended December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. These financial covenant calculations only reflect wholly-owned subsidiaries.
The prices we receive for future oil and natural gas production and the level of production have a significant impact on our operating cash flows. We are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production and the success of our exploration and production activities in generating additions to production.
Although we believe that through cash on hand, availability on our credit facility, and cash flows from operations, we have access to adequate capital to fund our development plans, we continue to examine additional sources of long-term capital, including a restructured debt facility, the issuance of debt instruments, the sale of preferred and common stock, the sales of non-strategic assets, and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy, will depend upon a number of factors, many of which are beyond our control.
Company Acquisitions and Growth
We continue to evaluate potential acquisitions and property development opportunities. During the year ended December 31, 2007, we completed the following transactions:
On October 1, 2007, we completed an asset exchange transaction to acquire an additional 12.5% working interest in the Garden Gulch Field in the Piceance Basin, in exchange for our assets in Washington County, Colorado and $33.0 million in cash.
On June 8, 2007, we acquired a 50% non-controlling ownership interest in Delta Oilfield Tank Company, LLC (“Delta Oilfield”) for cash consideration of $4.0 million. Delta Oilfield will be accounted for using the equity method of accounting and is an unconsolidated affiliate of the Company.
On June 8, 2007, we issued 475,000 shares of common stock valued at approximately $9.9 million for additional interest in a well owned and operated by the Company, and additional interest in a non-operated well.
On March 9, 2007, we issued 754,000 shares of common stock valued at approximately $13.8 million for additional interests in two wells already owned and operated by us located in Polk County, Texas.
On March 5, 2007, DHS purchased a drilling rig (“Rig 18”) for $7.6 million. The rig is an 700 horsepower rig with a depth rating of 10,500 feet. The rig is currently operating in the Rocky Mountain Region.
On March 1, 2007, we paid $3.5 million for 39,000 net acres and interests in several wells in Fremont County, Wyoming.
Historical Cash Flow
Our cash flow from operating activities increased from $53.4 million for the year ended December 31, 2006 to $84.4 million for the year ended December 31, 2007, primarily as a result of changes in working capital. Our net cash used in investing activities increased to $325.0 million for the year ended December 31, 2007 compared to net cash used in investing activities of $203.1 million for the year earlier period, primarily due to our increased drilling activity. Cash provided by financing activities was $243.1 million for the year ended December 31, 2007 compared to $151.8 million for the comparable prior year period. Cash provided by financing activities was higher in 2007 primarily due to cash received in April from our convertible debt and equity offerings.
Our cash flow from operating activities increased 5% to $53.4 million for the year ended December 31, 2006 compared to $50.7 million for the same period a year earlier. Our net cash used in investing activities decreased by 32% to $203.1 million for the year ended December 31, 2006 compared to $297.2 million for the same period a year earlier. The decrease in cash used for investing activity can be attributed to a reduction in property acquisitions due to an increased focus on drilling activities. Cash flow from financing activities decreased to $151.8 million for the year
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ended December 31, 2006 compared to $250.6 million for the same period the prior year. During the year ended December 31, 2006, we financed our operations, acquisitions, and capital expenditures primarily with net proceeds of $33.9 million in newly issued equity and $118.3 million in net debt additions.
Capital and Exploration Expenditures and Financing
Our capital and exploration expenditures and sources of financing for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005 were as follows:
Six Months | Year | |||||||||||||||
Years Ended | Ended | Ended | ||||||||||||||
December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands) | ||||||||||||||||
CAPITAL AND EXPLORATION EXPENDITURES: | ||||||||||||||||
Acquisitions: | ||||||||||||||||
Garden Gulch | $ | 34,778 | $ | — | $ | — | $ | — | ||||||||
Austin Chalk incremental interests | 23,765 | — | — | — | ||||||||||||
Wyoming (Yates) | 3,500 | — | — | — | ||||||||||||
Washington County, South and North Tongue | 1,000 | — | 828 | 10,571 | ||||||||||||
Armstrong Acquisition | — | 40,103 | — | — | ||||||||||||
Castle | — | 33,648 | — | — | ||||||||||||
Savant Acquisition | — | — | 85,000 | — | ||||||||||||
Manti | — | — | — | 59,700 | ||||||||||||
Columbia River Basin | — | — | — | 18,255 | ||||||||||||
Sacramento Basin | — | — | — | 10,400 | ||||||||||||
Karnes County, Texas | — | — | — | 5,000 | ||||||||||||
Other | 9,988 | 24,678 | 7,904 | 2,718 | ||||||||||||
Other development costs | 287,790 | 179,874 | 86,871 | 102,216 | ||||||||||||
Drilling and trucking companies | 22,292 | 63,848 | 25,733 | 32,690 | ||||||||||||
Exploration costs | 9,062 | 4,690 | 2,061 | 6,155 | ||||||||||||
$ | 392,175 | $ | 346,841 | $ | 208,397 | $ | 247,705 | |||||||||
FINANCING SOURCES: | ||||||||||||||||
Cash flow provided by operating activities | 78,173 | $ | 53,386 | $ | 24,879 | $ | 44,862 | |||||||||
Stock issued for cash upon exercised options | 137 | 3,711 | 1,166 | 132 | ||||||||||||
Stock issued for cash, net | 202,084 | 33,870 | 95,026 | — | ||||||||||||
Net long-term borrowings | 40,836 | 114,265 | 28,715 | 139,051 | ||||||||||||
Proceeds from sale of oil and gas properties | 46,193 | 82,716 | 34,178 | 18,721 | ||||||||||||
Proceeds from sale of drilling assets | 7,145 | — | — | — | ||||||||||||
Investments in and notes issued to affiliates | (12,440 | ) | — | — | — | |||||||||||
Minority interest contributions | (355 | ) | 9,018 | — | 14,800 | |||||||||||
Other | (106 | ) | (3,646 | ) | 2,566 | 63 | ||||||||||
$ | 361,667 | $ | 293,320 | $ | 186,530 | $ | 217,629 | |||||||||
We anticipate our drilling expenditures to range between $350.0 and $370.0 million for the year ending December 31, 2008 based on expected cash flow from operations and anticipated other property or equity transactions during the course of 2008. The timing of a portion of our capital expenditures is discretionary and could be delayed or curtailed, if necessary.
Sale of Oil and Gas Properties — Discontinued Operations
On October 1, 2007, we divested our Washington County, Colorado assets in conjunction with an asset exchange transaction to acquire additional working interest in the Garden Gulch Field in the Piceance Basin.
On September 4, 2007, we completed the sale of certain non-core properties located in North Dakota for cash consideration of approximately $6.2 million. The sale resulted in a gain of $4.3 million.
On March 30, 2007, we completed the sale of certain non-core properties located in New Mexico and East Texas for cash consideration of approximately $31.5 million, prior to customary purchase price adjustments. The sale resulted in a loss of approximately $10.8 million.
On March 27, 2007, we completed the sale of certain non-core properties located in Australia for cash consideration of approximately $6.0 million. The sale resulted in an after-tax gain of $2.0 million.
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On January 10, 2007, we completed the sale of certain non-core properties located in Padgett field, Kansas for cash consideration of $5.6 million. The transaction resulted in a gain on sale of properties of $297,000.
In March 2006, we sold approximately 26% of PGR for $20.4 million. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain could be recognized as all of the unproved cost basis was not yet recovered. We recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million reduction to property during the first quarter of 2006 as a result of the transaction. We have retained a 74% interest in PGR.
During December 2005, we transferred our ownership in approximately 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin to a newly created wholly owned subsidiary, CRBP. In January and March 2006, we sold a combined 44% minority interest in CRBP for total proceeds of $32.8 million. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, we recorded a $13.0 million gain, ($8.1 million net of tax) and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction.
Also included in discontinued operations are our Midway Loop, Texas oil and gas properties which are held for sale as of December 31, 2007.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Contractual and Long-Term Debt Obligations
Payments Due by Period | ||||||||||||||||||||
Less than | More than | |||||||||||||||||||
Contractual Obligations at December 31, 2007 | 1 year | 1-3 Years | 3-5 Years | 5 Years | Total | |||||||||||||||
(In thousands) | ||||||||||||||||||||
7% Senior unsecured notes | $ | — | $ | — | $ | — | $ | 150,000 | $ | 150,000 | ||||||||||
Interest on 7% Senior unsecured notes | 10,500 | 21,000 | 21,000 | 31,033 | 83,533 | |||||||||||||||
33/4% Senior convertible notes | — | — | — | 115,000 | 115,000 | |||||||||||||||
Credit facility | — | 73,600 | — | — | 73,600 | |||||||||||||||
Term loan – DHS | — | 75,000 | — | — | 75,000 | |||||||||||||||
Derivative liability | 6,295 | — | — | — | 6,295 | |||||||||||||||
Abandonment retirement obligation | 1,045 | 431 | 454 | 10,449 | 12,379 | |||||||||||||||
Operating leases | 3,527 | 5,331 | 2,997 | 2,394 | 14,249 | |||||||||||||||
Drilling commitments | 3,500 | 14,000 | — | — | 17,500 | |||||||||||||||
Other debt obligations | 13 | — | — | — | 13 | |||||||||||||||
Total contractual cash obligations | $ | 24,880 | $ | 189,362 | $ | 24,451 | $ | 308,876 | $ | 547,569 | ||||||||||
7% Senior Unsecured Notes, due 2015
On March 15, 2005, we issued 7% senior unsecured notes for an aggregate amount of $150.0 million which pay interest semi-annually on April 1 and October 1 and mature in 2015. The net proceeds were used to refinance debt outstanding under our credit facility which included the amount required to acquire the Manti properties located in the Gulf Coast Region. The notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries. These covenants may limit management’s discretion in operating our business.
33/4% Senior Convertible Notes, due 2037
On April 25, 2007, we issued $115.0 million aggregate principal amount of 33/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes bear interest at a rate of 33/4% per annum, payable semi-annually in arrears, on May 1 and November 1 of each year, beginning November 1, 2007. The Notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The Notes will be convertible at the holder’s option, in whole or in part, at an
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initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, we will have the option to deliver shares of our common stock, cash or a combination of cash and shares of our common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require us to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause our wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue our corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.
Credit Facility
At December 31, 2007, the $250.0 million credit facility had $73.6 million outstanding. On February 20, 2008, the credit facility was fully paid down with a portion of the proceeds from our equity offering. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between prime + .25% and 1.00% for base rate loans and between Libor + 1.5% and 2.25% for Eurodollar loans. We are required to meet certain financial covenants which include a current ratio of 1 to 1, net of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) ratio of less than 4.0 to 1 for the quarter ended December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. The financial covenants only include subsidiaries which we own 100%. At December 31, 2007, we were in compliance with our quarterly debt covenants and restrictions.
The borrowing base is re-determined by the lending banks at least semi-annually on April 1 and October 1 of each year, or by special re-determinations if requested by the Company based on drilling success. If, as a result of any reduction in the amount of our borrowing base, the total amount of the outstanding debt were to exceed the amount of the borrowing base in effect, then, within 30 days after we are notified of the borrowing base deficiency, we would be required (1) to make a mandatory payment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base, (2) to eliminate the deficiency by making three equal monthly principal payments, (3) within 90 days, to provide additional collateral for consideration to eliminate the deficiency or (4) to eliminate the deficiency through a combination of (1) through (3). If for any reason we were unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, we would be in default of our obligations under our credit facility. There was no change to our borrowing base as a result of the October 2007 re-determination.
The credit facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers and acquisitions, and includes financial covenants.
Under certain conditions, amounts outstanding under the credit facility may be accelerated. Bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under the credit facility. Subject to notice and cure periods in certain cases, other events of default under the credit facility will result in acceleration of the indebtedness at the option of the lending banks. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the credit facility (including financial covenants), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the credit facility.
This facility is secured by a first and prior lien to the lending banks on most of our oil and gas properties, certain related equipment, oil and gas inventory, and certain bank accounts and proceeds.
Unsecured Term Loan
In December 2006 we entered into an agreement with JP Morgan Chase Bank N.A. for a $25.0 million unsecured term loan with interest at LIBOR plus a margin of 3.5% at December 31, 2006. The note was paid in full in January 2007 with the proceeds from the $56.4 million equity offering.
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Credit Facility – DHS
On December 20, 2007, DHS entered into a new $75.0 million credit agreement with Lehman Commercial Paper Inc. The proceeds were used to pay off the JP Morgan credit facility. The credit facility has a variable interest rate based on 90-day LIBOR plus a fixed margin of 5.50% and matures on December 31, 2010. Annual principal payments are based upon a calculation of excess cash flow (as defined) for the preceding year. DHS is required to meet certain financial covenants quarterly beginning March 31, 2008 including (i) consolidated EBITDA for four consecutive fiscal quarters must be greater than $20.0 million; (ii) Consolidated Leverage Ratio (as defined) for four consecutive fiscal quarters cannot exceed 3.50 to 1.00; (iii) Consolidated Interest Coverage Ratio (as defined) for four consecutive fiscal quarters must exceed 2.50 to 1.00 and (iv) the Current Ratio for any fiscal quarter must be greater than 1.0 to 1.0. DHS incurred $1.3 million of financing charges in conjunction with the agreement which will be amortized over the life of the loan.
On May 4, 2006, DHS entered into a $100.0 million senior secured credit facility with JP Morgan Chase Bank, N.A. Proceeds from the $75.0 million initial draw were used to pay off the Guggenheim term loan, complete the acquisition of C&L Drilling, finance additional capital expenditures and pay transaction expenses. In December 2007, DHS used proceeds from the Lehman credit agreement and the sale of Rigs 2 and 3 to pay off the $79.7 million outstanding balance of the JP Morgan senior secured credit facility.
Term Loan - DHS
On May 4, 2006, DHS used proceeds from the JP Morgan credit facility to pay off the remaining balance of the previously outstanding term loan of approximately $41.0 million.
Other Contractual Obligations
Our asset retirement obligation arises from the costs necessary to plug and abandon our oil and gas wells. The majority of this obligation will not occur during the next five years.
We lease our corporate office in Denver, Colorado under an operating lease which will expire in 2014. Our average yearly payments approximate $1.6 million over the life of the lease. We have additional operating lease commitments which represent office equipment leases and short term debt obligations primarily relating to field vehicles and equipment.
In March 2007, we executed an earn-in agreement with EnCana whereby we can earn up to 6,000 net acres in the Piceance Basin with the drilling of 128 wells during the next 36 months. We are committed to drill 64 total wells, eight of which were drilled by October 31, 2007. The remaining wells are required to be drilled by June 1, 2009. We are liable for $250,000 per undrilled well in the event the drilling obligations are not met.
Derivative instruments represent the net estimated unrealized losses for our oil and gas hedges at December 31, 2007. The ultimate settlement amounts of these hedges are unknown because they are subject to continuing market risk. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”
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The following table summarizes our derivative contracts outstanding at December 31, 2007:
Net Fair Value | |||||||||||||||||||||
Price Floor / | Asset (Liability) at | ||||||||||||||||||||
Commodity | Volume | Price Ceiling | Term | Index | December 31, 2007 | ||||||||||||||||
(In thousands) | |||||||||||||||||||||
Crude oil | 1,200 | Bbls / day | $ | 65.00 / $80.03 | Jan ’08 - Mar ’08 | NYMEX – WTI | $ | (1,705 | ) | ||||||||||||
Crude oil | 1,200 | Bbls / day | $ | 65.00 / $79.77 | Apr ’08 - June ’08 | NYMEX – WTI | (1,620 | ) | |||||||||||||
Crude oil | 1,200 | Bbls / day | $ | 65.00 / $79.86 | July ’08 - Sept ’08 | NYMEX – WTI | (1,522 | ) | |||||||||||||
Crude oil | 1,200 | Bbls / day | $ | 65.00 / $79.83 | Oct ’08 - Dec ’08 | NYMEX – WTI | (1,448 | ) | |||||||||||||
Natural gas | 15,000 | MMBtu / day | $ | 6.50 / $8.30 | Jan ’08 - Dec ’08 | CIG | 2,404 | ||||||||||||||
Natural gas | 5,000 | MMBtu / day | $ | 6.50 / $8.40 | Jan ’08 - Mar ’08 | CIG | 211 | ||||||||||||||
Natural gas | 10,000 | MMBtu / day | $ | 6.00 / $7.25 | Apr ’08 - Sept ’08 | CIG | 139 | ||||||||||||||
Natural gas | 10,000 | MMBtu / day | $ | 6.50 / $7.90 | Oct ’08 - Dec ’08 | CIG | 176 | ||||||||||||||
$ | (3,365 | ) | |||||||||||||||||||
The fair value of our derivative instruments liability was a $3.4 million loss at December 31, 2007. Subsequent to year-end, we entered into new CIG gas hedges for 10,000 Mmbtu per day for the second and third quarters of 2008 with a floor price of $6.50 and ceiling prices of $7.70 and $8.15 per Mmbtu, respectively. We also entered into new CIG gas hedges for 35,000 Mmbtu per day for the first quarter of 2009 with a floor price of $7.50 per Mmbtu and a ceiling price of $9.88 per Mmbtu. The fair value of our derivative liability at February 26, 2008 was $15.2 million.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations were based on the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 2 to our consolidated financial statements. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.
Successful Efforts Method of Accounting
We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within an oil and gas field are typically considered development costs and are capitalized, but often these seismic programs extend beyond the reserve area considered proved, and management must estimate the portion of the seismic costs to
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expense. The evaluation of gas and oil leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.
Reserve Estimates
Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
Impairment of Gas and Oil Properties
We review our oil and gas properties for impairment quarterly or whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our developed proved properties and compare such future cash flows to the carrying amount of the proved properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and production costs, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.
Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment during the year ended December 31, 2007, an impairment of $58.4 million was recorded primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 million and $10.3 million, respectively), and the South Angleton field in Texas ($9.7 million), primarily due to lower Rocky Mountain natural gas prices and marginally economic deep zones on the Howard Ranch Prospect. During the year ended December 31, 2006, an impairment of $10.4 million was recorded on certain of the Company’s eastern Colorado properties primarily due to lower Rocky Mountain natural gas prices. In addition, an impairment of $1.0 million was recorded on certain Oklahoma properties. The Company recorded no impairment provision attributable to developed properties for the six months ended December 31, 2005 and the year ended June 30, 2005. For fiscal year 2008, we are continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or commodity prices may cause us to revise in future quarters our estimates of those properties’ future cash flows. Such revisions of estimates could require us to record an impairment in the period of such revisions.
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Commodity Derivative Instruments and Hedging Activities
We may periodically enter into commodity derivative contracts or fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize futures contracts, swaps or options, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks.
All derivative instruments are recorded on the balance sheet at fair value. Effective July 1, 2007, we elected to discontinue cash flow hedge accounting prospectively. Beginning July 1, 2007, we recognize mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income.
Asset Retirement Obligation
We account for our asset retirement obligations under SFAS 143. SFAS 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells.
In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS 143. The Company applied the guidance of FIN 47 beginning July 1, 2005, resulting in no impact on its financial statements.
Deferred Tax Asset Valuation Allowance
We follow SFAS 109 to account for our deferred tax assets and liabilities. Under SFAS 109, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. As a result of management’s current assessment, we maintain a significant valuation allowance against our deferred tax assets. We will continue to monitor facts and circumstances in our reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, we may determine that the deferred tax asset valuation allowance should be increased or decreased. Such changes would impact net income through offsetting changes in income tax expense or benefit.
Recently Issued Accounting Standards and Pronouncements
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any resulting goodwill, and any noncontrolling interest in the acquiree. The Statement also provides for disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008, or our fiscal year 2009, and must be applied prospectively to business combinations completed on or after that date. We will evaluate how the new requirements could impact the accounting for any acquisitions completed beginning in fiscal 2009 and beyond, and the potential impact on our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for noncontrolling interests (“minority interests”) in subsidiaries. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, or our fiscal year 2009, and must be applied prospectively, except for the presentation and disclosure requirements, which will apply retrospectively. We are currently evaluating the potential impact of the adoption of SFAS 160 on our consolidated financial statements.
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In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits companies to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, or fiscal year 2008. We have not yet determined if we will elect to apply any of the provisions of SFAS 159 or what effect the adoption of the Statement would have, if any, on our consolidated financial statements.
Effective January 1, 2007, we adopted provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. Upon the adoption of FIN 48, we had no unrecognized tax benefits. During the year ended December 31, 2007, no adjustments were recognized for uncertain tax benefits.
We recognize interest and penalties related to uncertain tax positions in income tax benefit/expense. No interest and penalties related to uncertain tax positions were accrued at December 31, 2007.
The tax years 2003 through 2006 for federal returns and 2002 through 2006 for state returns remain open to examination by the major taxing jurisdictions in which we operate, although no material changes to unrecognized tax positions are expected within the next twelve months.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. SFAS 157 aims to improve the consistency and comparability of fair value measurements by creating a single definition of fair value. The Statement emphasizes that fair value is not entity-specific, but instead is a market-based measurement of an asset or liability. SFAS 157 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for fiscal year commencing January 1, 2008. We do not expect the impact of SFAS 157 to be material to our financial condition or results of operations. We anticipate the primary impact of the standard will be additional disclosures related to the measurement of fair value in the Company’s recurring impairment test calculations related to oil and gas properties, drilling rigs, and goodwill, the valuation of oil and gas derivative financial instruments, and the valuation of assets acquired or liabilities assumed in future business combinations, if any.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Rate and Price Risk
We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, including costless collars, swaps, and puts. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy. We use hedges to limit the risk of fluctuating cash flows that fund our capital expenditure program. We also may use hedges in conjunction with acquisitions to achieve expected economic returns during the payout period.
The net fair value of our derivative instruments was a $3.4 million liability at December 31, 2007 and a $15.2 million liability on February 26, 2008.
As of February 26, 2008, our derivative contracts cover approximately 12.2 Bcfe of our 2008 production. Assuming production and the percent of oil and gas sold remained unchanged from the year ended December 31, 2007, a hypothetical 10% decline in the average market price the Company realized during the year ended December 31, 2007 on unhedged production would reduce the Company’s oil and natural gas revenues by approximately $9.5 million on an annual basis.
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Interest Rate Risk
We were subject to interest rate risk on $148.6 million of variable rate debt obligations at December 31, 2007. The annual effect of a 10% change in interest rates would be approximately $1.3 million. The interest rate on these variable debt obligations approximates current market rates as of December 31, 2007.
Item 8. Financial Statements and Supplementary Data
Financial Statements are included and begin on page F-1. There are no financial statement schedules since they are either not applicable or the information is included in the notes to the financial statements.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. Management necessarily applied its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding management’s control objectives.
With the participation of management, our chief executive officer and chief financial officer evaluated the effectiveness of the design and operation of our disclosure controls and procedures at the conclusion of the period ended December 31, 2007. Based upon this evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that we file with the Securities and Exchange Commission.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for Delta. As defined by the Securities and Exchange Commission (Rule 13a-15(f) under the Exchange Act), internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles.
Our internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated 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.
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In connection with the preparation of our annual consolidated financial statements, management has undertaken an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls.
Based on this assessment, management has concluded that as of December 31, 2007, our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this report, has issued an attestation report on the effectiveness of internal control over financial reporting.
Changes in Internal Controls
There were no significant changes in our internal controls or, to the knowledge of our management, in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation of our disclosure controls and procedures utilized to compile information included in this filing.
Item 9B. Other Information
None.
PART III
The information required by Part III, Item 10 “Directors and Executive Officers and Corporate Governance,” Item 11 “Executive Compensation,” Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” Item 13 “Certain Relationships and Related Transactions, and Director Independence” and Item 14 “Principal Accounting Fees and Services” is incorporated by reference to the Company’s definitive Proxy Statement which will be filed with the Securities and Exchange Commission in connection with the 2008 Annual Meeting of Stockholders. For certain information concerning Item 10 “Directors, Executive Officers and Corporate Governance,” see Part I – “Directors and Executive Officers.”
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PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements.
Page No. | ||
Reports of Independent Registered Public Accounting Firm | F-1,2 | |
Consolidated Balance Sheets as of December 31, 2007 and December 31, 2006 | F-3 | |
Consolidated Statements of Operations for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005 | F-4 | |
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005 | F-5 | |
Consolidated Statements of Cash Flows for the year ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005 | F-6 | |
Notes to Consolidated Financial Statements | F-7 |
(a)(2) Financial Statement Schedules. None.
(a)(3) Exhibits. The Exhibits listed in the Index to Exhibits appearing at page 62 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with a “*”.
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INDEX TO EXHIBITS
2. | Plans of Acquisition, Reorganization, Arrangement, Liquidation, or Succession. | |
2.1 | Agreement and Plan of Merger, dated as of November 8, 2005, among Delta Petroleum Corporation, a Colorado corporation, Delta Petroleum Corporation, and as amended a Delaware corporation, DPCA LLC, a Delaware limited liability company and a wholly owned subsidiary of Delta Colorado, and Castle Energy Corporation, a Delaware corporation. Incorporated by reference to Appendix A to the proxy statement/prospectus contained in the Company’s Form S-4 registration statement, SEC File No. 333-130672. | |
3. | Articles of Incorporation and By-laws. | |
3.1 | Certificate of Incorporation of the Company, as amended. Incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated January 31, 2006. | |
3.2 | Amended and Restated By-laws of the Company. Incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K, dated February 9, 2006. | |
4. | Instruments Defining the Rights of Security Holders. | |
4.1 | Purchase Agreement dated March 9, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.1 to the Company’s Form 8-K dated March 15, 2005. | |
4.2 | Registration Rights Agreement dated March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.2 to the Company’s Form 8-K dated March 15, 2005. | |
4.3 | Indenture dated as of March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and US Bank National Association, as Trustee. Incorporated by reference from Exhibit 4.3 to the Company’s Form 8-K dated March 15, 2005. | |
4.4 | Form of 7% Series A Senior Notes due 2015 with attached notation of Guarantees. | |
Incorporated by reference from Exhibit 4.4 to the Company’s Form 8-K dated March 15, 2005. | ||
4.5 | Indenture, dated as of April 25, 2007, by and between the Company and the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (including Form of 33/4% Convertible Senior Note due 2037). Incorporated by reference from Exhibit 4.1 to the Company’s Form 8-K dated April 19, 2007. | |
4.6 | Form of 33/4% Convertible Senior Note due 2037. Incorporated by reference from Exhibit 4.2 to the Company’s Form 8-K dated April 19, 2007. | |
10. | Material Contracts. | |
10.1 | Delta Petroleum Corporation 1993 Incentive Plan, as amended. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1996. * | |
10.2 | Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference from the Company’s Notice of Annual Meeting and Proxy Statement dated June 1, 1999.* | |
10.3 | Delta Petroleum Corporation 2001 Incentive Plan. Incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement dated July 26, 2001 for fiscal year 2000 ended June 30, 2000.* | |
10.4 | Delta Petroleum Corporation 2002 Incentive Plan incorporated by reference from Exhibit A to the Company’s definitive proxy statement filed May 1, 2002. |
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10.5 | Agreement between Delta Petroleum Corporation and Amber Resources Company dated July 1, 2001, incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated October 25, 2001. | |
10.6 | Delta Petroleum Corporation 2005 New-Hire Equity Incentive Plan. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 17, 2005.* | |
10.7 | Amendment No. 1 to Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated June 17, 2005.* | |
10.8 | Employment Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated May 5, 2005.* | |
10.9 | Employment Agreement with Kevin K. Nanke dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.10 | Employment Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.11 | Employment Agreement with Stanley F. Freedman dated January 11, 2006. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated January 11, 2006.* | |
10.12 | Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement filed on November 22, 2004.* | |
10.13 | Delta Petroleum Corporation 2006 New-Hire Equity Incentive Plan. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 20, 2006.* | |
10.14 | Amended and Restated Credit Agreement, dated November 17, 2006, by and among Delta Petroleum Corporation, JPMorgan Chase Bank, N.A. and certain other financial institutions named therein. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated November 17, 2006. | |
10.15 | First Amendment to Amended and Restated Credit Agreement, dated December 4, 2006, by and among Delta Petroleum Corporation, JPMorgan Chase Bank, N.A. and certain other financial institutions named therein. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated November 17, 2006. | |
10.16 | Promissory Note, dated December 4, 2006, by and between Delta Petroleum Corporation and JPMorgan Chase Bank, N.A. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated November 17, 2006. | |
10.17 | Delta Petroleum Corporation 2007 Performance and Equity Incentive Plan. Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement filed on December 28, 2006.* | |
10.18 | Form of Restricted Stock Award Agreement. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated February 5, 2007.* | |
10.19 | Change in Control Executive Severance Agreement with Roger A. Parker dated April 30, 2007. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated April 30, 2007.* | |
10.20 | Change in Control Executive Severance Agreement with John R. Wallace dated April 30, 2007. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated April 30, 2007.* | |
10.21 | Change in Control Executive Severance Agreement with Kevin K. Nanke dated April 30, 2007. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated April 30, 2007.* | |
10.22 | Change in Control Executive Severance Agreement with Stanley F. Freedman dated April 30, 2007. Incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K dated April 30, 2007. * |
63
10.23 | Company Stock Purchase Agreement, dated December 29, 2007, by and between Delta Petroleum Corporation and Tracinda Corporation. Incorporated by reference from Exhibit 1.1 to the Company’s Form 8-K dated December 31, 2007. | |
10.24 | $75,000,000 Credit Agreement dated as of December 19, 2007 among DHS Holding Company and DHS Drilling Company as borrowers, and Lehman Brothers Inc. as sole arranger and Lehman Brothers Commercial Paper Inc. as syndication agent and administrative agent. Filed herewith electronically. | |
11. | Statement Regarding Computation of Per Share Earnings. Not applicable. | |
12. | Statement Regarding Computation of Ratios. Not applicable. | |
14. | Code of Ethics. The Company’s Code of Business Conduct and Ethics is posted on the Company’s website at www.deltapetro.com. | |
16. | Letter re: change in certifying accountant. Not applicable. | |
18. | Letter re: change in accounting principles. Not applicable. | |
21. | Subsidiaries of the Registrant. Filed herewith electronically. | |
22. | Published report regarding matters submitted to vote of security holders. Not applicable. | |
23. | Consents of experts and counsel. | |
23.1 | Consent of KPMG LLP. Filed herewith electronically. | |
23.2 | Consent of Ralph E. Davis Associates, Inc. Filed herewith electronically. | |
23.3 | Consent of Mannon Associates. Filed herewith electronically. | |
24. | Power of attorney. Not applicable. | |
31. | Rule 13a-14(a) /15d-14(a) Certifications. | |
31.1 | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically. | |
31.2 | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically. | |
32. | Section 1350 Certifications. | |
32.1 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically. | |
32.2 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically. |
* | Management contracts and compensatory plans. |
64
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Delta Petroleum Corporation:
Delta Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income (loss), and cash flows for the years ended December 31, 2007 and 2006, the six months ended December 31, 2005 and the year ended June 30, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Delta Petroleum Corporation and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for the years ended December 31, 2007 and 2006, the six months ended December 31, 2005 and the year ended June 30, 2005, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Delta Petroleum Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
As discussed in note 2 to the consolidated financial statements, Delta Petroleum Corporation adopted FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109,effective January 1, 2007 and Statement of Financial Accounting Standards No. 123(R),Share-Based Payment, effective July 1, 2005.
/s/ KPMG LLP
Denver, Colorado
February 28, 2008
February 28, 2008
F-1
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Delta Petroleum Corporation:
Delta Petroleum Corporation:
We have audited Delta Petroleum Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Delta Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included inManagement’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with 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, Delta Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Delta Petroleum as of December 31, 2007 and 2006, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income (loss), and cash flows for the years ended December 31, 2007 and 2006, the six months ended December 31, 2005 and the year ended June 30, 2005, and our report dated February 28, 2008 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Denver, Colorado
February 28, 2008
February 28, 2008
F-2
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 10,091 | $ | 7,666 | ||||
Assets held for sale | 62,744 | 31,822 | ||||||
Trade accounts receivable, net of allowance for doubtful accounts, of $664 and $100, respectively | 38,761 | 29,503 | ||||||
Prepaid assets | 3,943 | 4,384 | ||||||
Inventory | 4,236 | 2,851 | ||||||
Derivative instruments | 2,930 | 10,799 | ||||||
Deferred tax asset | 150 | — | ||||||
Other current assets | 10,214 | 2,769 | ||||||
Total current assets | 133,069 | 89,794 | ||||||
Property and equipment: | ||||||||
Oil and gas properties, successful efforts method of accounting: | ||||||||
Unproved | 247,466 | 217,573 | ||||||
Proved | 740,408 | 564,242 | ||||||
Drilling and trucking equipment | 146,097 | 136,038 | ||||||
Pipeline and gathering system | 22,140 | 14,909 | ||||||
Other | 19,069 | 13,983 | ||||||
Total property and equipment | 1,175,180 | 946,745 | ||||||
Less accumulated depreciation and depletion | (245,153 | ) | (131,545 | ) | ||||
Net property and equipment | 930,027 | 815,200 | ||||||
Long-term assets: | ||||||||
Marketable securities | 6,268 | — | ||||||
Deferred financing costs | 7,187 | 6,928 | ||||||
Goodwill | 7,747 | 7,747 | ||||||
Other long-term assets | 10,616 | 6,722 | ||||||
Investment in unconsolidated affiliates | 10,281 | 2,932 | ||||||
Total long-term assets | 42,099 | 24,329 | ||||||
Total assets | $ | 1,105,195 | $ | 929,323 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 13 | $ | 816 | ||||
Accounts payable | 119,783 | 84,439 | ||||||
Other accrued liabilities | 17,105 | 10,818 | ||||||
Deferred tax liability | — | 2,893 | ||||||
Derivative instruments | 6,295 | 613 | ||||||
Total current liabilities | 143,196 | 99,579 | ||||||
Long-term liabilities: | ||||||||
7% Senior notes, unsecured | 149,459 | 149,384 | ||||||
33/4% Senior convertible notes | 115,000 | — | ||||||
Credit facility | 73,600 | 118,000 | ||||||
Unsecured term loan | — | 25,000 | ||||||
Credit facility/Term loan - DHS | 75,000 | 74,050 | ||||||
Asset retirement obligation | 4,154 | 4,013 | ||||||
Deferred tax liability | 9,085 | 3,660 | ||||||
Other debt, net | — | 14 | ||||||
Total long-term liabilities | 426,298 | 374,121 | ||||||
Minority interest | 27,296 | 27,390 | ||||||
Commitments and contingencies | ||||||||
Stockholders’ equity: | ||||||||
Preferred stock, $.01 par value: | ||||||||
authorized 3,000,000 shares, none issued | — | — | ||||||
Common stock, $.01 par value; | ||||||||
authorized 300,000,000 shares, issued 66,429,000 shares at December 31, 2007, and 53,439,000 shares at December 31, 2006 | 664 | 534 | ||||||
Additional paid-in capital | 664,733 | 430,479 | ||||||
Accumulated other comprehensive income | — | 4,865 | ||||||
Accumulated deficit | (156,992 | ) | (7,645 | ) | ||||
Total stockholders’ equity | 508,405 | 428,233 | ||||||
Total liabilities and stockholders’ equity | $ | 1,105,195 | $ | 929,323 | ||||
See accompanying notes to consolidated financial statements.
F-3
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Six Months Ended | Year Ended | |||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Revenue: | ||||||||||||||||
Oil and gas sales | $ | 94,559 | $ | 94,223 | $ | 42,643 | $ | 52,446 | ||||||||
Contract drilling and trucking fees | 56,777 | 57,149 | 9,096 | 4,796 | ||||||||||||
Gain (loss) on effective derivative instruments, net | 12,854 | (4,712 | ) | (3,413 | ) | (630 | ) | |||||||||
Total revenue | 164,190 | 146,660 | 48,326 | 56,612 | ||||||||||||
Operating expenses: | ||||||||||||||||
Lease operating expense | 20,142 | 17,655 | 6,507 | 9,291 | ||||||||||||
Transportation expense | 3,684 | 978 | 680 | 394 | ||||||||||||
Production taxes | 5,559 | 4,784 | 2,455 | 3,415 | ||||||||||||
Depreciation, depletion, accretion and amortization – oil and gas | 63,373 | 53,980 | 12,411 | 14,055 | ||||||||||||
Depreciation and amortization – drilling and trucking | 22,052 | 16,404 | 2,847 | 1,525 | ||||||||||||
Exploration expense | 9,062 | 4,690 | 2,061 | 6,155 | ||||||||||||
Dry hole costs and impairments | 85,084 | 15,682 | 5,423 | 2,771 | ||||||||||||
Drilling and trucking operations | 36,954 | 34,163 | 5,821 | 4,666 | ||||||||||||
General and administrative | 49,621 | 35,696 | 16,491 | 16,930 | ||||||||||||
Gain on sale of oil and gas properties | — | (20,034 | ) | — | — | |||||||||||
Total operating expenses | 295,531 | 163,998 | 54,696 | 59,202 | ||||||||||||
Operating income (loss) | (131,341 | ) | (17,338 | ) | (6,370 | ) | (2,590 | ) | ||||||||
Other income and (expense): | ||||||||||||||||
Other income (expense) | 376 | (154 | ) | (36 | ) | (570 | ) | |||||||||
Gain (loss) on ineffective derivative instruments, net | (2,902 | ) | 11,722 | (14,437 | ) | (330 | ) | |||||||||
Gain on sale of marketable securities, net | — | — | 1,194 | — | ||||||||||||
Gain on sale of investment in LNG | — | 1,058 | — | — | ||||||||||||
Minority interest | 1,231 | (2,595 | ) | (688 | ) | 1,017 | ||||||||||
Losses from unconsolidated affiliates | (393 | ) | — | — | — | |||||||||||
Interest and financing costs | (27,199 | ) | (26,316 | ) | (8,866 | ) | (7,880 | ) | ||||||||
Total other expense | (28,887 | ) | (16,285 | ) | (22,833 | ) | (7,763 | ) | ||||||||
�� | ||||||||||||||||
Loss from continuing operations before income taxes and discontinued operations | (160,228 | ) | (33,623 | ) | (29,203 | ) | (10,353 | ) | ||||||||
Income tax benefit (expense) | (2,677 | ) | 12,623 | 10,873 | 11,969 | |||||||||||
Income (loss) from continuing operations | (162,905 | ) | (21,000 | ) | (18,330 | ) | 1,616 | |||||||||
Discontinued operations: | ||||||||||||||||
Income from discontinued operations of properties sold, net of tax | 17,556 | 9,163 | 5,952 | 13,434 | ||||||||||||
Gain (loss) on sale of discontinued operations, net of tax | (3,998 | ) | 6,712 | 11,788 | — | |||||||||||
Income (loss) before extraordinary gain, net of tax | (149,347 | ) | (5,125 | ) | (590 | ) | 15,050 | |||||||||
Extraordinary gain, net of tax | — | 5,560 | — | — | ||||||||||||
Net income (loss) | $ | (149,347 | ) | $ | 435 | $ | (590 | ) | $ | 15,050 | ||||||
Basic income (loss) per common share: | ||||||||||||||||
Income (loss) from continuing operations | $ | (2.66 | ) | $ | (.41 | ) | $ | (.41 | ) | $ | .04 | |||||
Discontinued operations | .22 | .31 | .40 | .33 | ||||||||||||
Extraordinary gain, net of tax | — | .11 | — | — | ||||||||||||
Net income (loss) | $ | (2.44 | ) | $ | .01 | $ | (.01 | ) | $ | .37 | ||||||
Diluted income (loss) per common share: | ||||||||||||||||
Income (loss) from continuing operations | $ | (2.66 | ) | $ | (.39 | ) | $ | (.41 | ) | $ | .04 | |||||
Discontinued operations | .22 | .30 | .40 | .32 | ||||||||||||
Extraordinary gain, net of tax | — | .10 | — | — | ||||||||||||
Net income (loss) | $ | (2.44 | ) | $ | .01 | $ | (.01 | ) | $ | .36 | ||||||
See accompanying notes to consolidated financial statements.
F-4
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’
EQUITY AND COMPREHENSIVE INCOME (LOSS)
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’
EQUITY AND COMPREHENSIVE INCOME (LOSS)
Accumulated | ||||||||||||||||||||||||||||||||
Additional | other | |||||||||||||||||||||||||||||||
Common stock | paid-in | comprehensive | Comprehensive | Unearned | Accumulated | |||||||||||||||||||||||||||
Shares | Amount | capital | income/(loss) | income (loss) | Compensation | deficit | Total | |||||||||||||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||||||||||||||||||
Balance, July 1, 2004 | 38,447 | $ | 384 | $ | 207,811 | $ | 342 | $ | (22,540 | ) | $ | 185,997 | ||||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||||||||
Net income | — | — | — | — | $ | 15,050 | 15,050 | 15,050 | ||||||||||||||||||||||||
Other comprehensive gain, net of tax | ||||||||||||||||||||||||||||||||
Change in fair value of derivative hedging instruments, net of tax benefit of $3,722 | — | — | — | (5,961 | ) | (5,961 | ) | — | (5,961 | ) | ||||||||||||||||||||||
Unrealized gain on marketable securities, net of tax expense of $458 | — | — | — | 394 | 394 | — | 394 | |||||||||||||||||||||||||
Comprehensive income | $ | 9,483 | ||||||||||||||||||||||||||||||
Shares issued for oil and gas properties | 1,571 | 16 | 22,175 | — | — | 22,191 | ||||||||||||||||||||||||||
Shares issued for drilling equipment | 131 | 1 | 1,892 | — | — | 1,893 | ||||||||||||||||||||||||||
Shares issued for cash upon exercise of options, net | 1,793 | 18 | 114 | — | — | 132 | ||||||||||||||||||||||||||
Tax benefit on options exercised | — | — | 1,255 | — | — | 1,255 | ||||||||||||||||||||||||||
Issuance of options below market | — | — | 346 | — | $ | (346 | ) | — | — | |||||||||||||||||||||||
Issuance of restricted options | 75 | 1 | 1,707 | — | (1,708 | ) | — | — | ||||||||||||||||||||||||
Amortization of unearned option compensation | — | — | — | — | 672 | — | 672 | |||||||||||||||||||||||||
Balance, June 30, 2005 | 42,017 | 420 | 235,300 | (5,225 | ) | (1,382 | ) | (7,490 | ) | 221,623 | ||||||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||||||||
Net loss | — | — | — | — | $ | (590 | ) | (590 | ) | (590 | ) | |||||||||||||||||||||
Other comprehensive income transactions, net of tax | ||||||||||||||||||||||||||||||||
Realized gain on equity securities sold, net of tax expense of $458 | — | — | — | (736 | ) | (736 | ) | — | (736 | ) | ||||||||||||||||||||||
Hedging loss reclassified to income upon settlement, net of tax benefit of $1,733 | — | — | — | 2,398 | 2,398 | — | 2,398 | |||||||||||||||||||||||||
Change in fair value of derivative hedging instruments, net of tax benefit of $1,036 | — | — | — | (1,434 | ) | (1,434 | ) | — | (1,434 | ) | ||||||||||||||||||||||
Comprehensive loss | $ | (362 | ) | |||||||||||||||||||||||||||||
Shares issued for oil and gas properties | 50 | 1 | 827 | — | — | 828 | ||||||||||||||||||||||||||
Shares issued for cash, net of offering costs | 5,405 | 54 | 94,917 | — | — | 94,971 | ||||||||||||||||||||||||||
Shares issued for cash upon exercise of options | 200 | 2 | 623 | — | — | 625 | ||||||||||||||||||||||||||
Reclassification of unearned compensation upon adoption of SFAS 123R | — | — | (1,382 | ) | — | 1,382 | — | — | ||||||||||||||||||||||||
Issuance and amortization of unearned compensation | 153 | 1 | 766 | — | — | — | 767 | |||||||||||||||||||||||||
Compensation on options vested | — | — | 2,003 | — | — | — | 2,003 | |||||||||||||||||||||||||
Balance, December 31, 2005 | 47,825 | 478 | 333,054 | (4,997 | ) | — | (8,080 | ) | 320,455 | |||||||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||||||||
Net loss | — | — | — | — | $ | 435 | 435 | 435 | ||||||||||||||||||||||||
Other comprehensive income transactions, net of tax | ||||||||||||||||||||||||||||||||
Hedging loss reclassified to income upon settlement, net of tax benefit of $1,738 | — | — | — | 2,860 | 2,860 | — | 2,860 | |||||||||||||||||||||||||
Change in fair value of derivative hedging instruments, net of tax expense of $4,315 | — | — | — | 7,002 | 7,002 | — | 7,002 | |||||||||||||||||||||||||
Comprehensive income | $ | 10,297 | ||||||||||||||||||||||||||||||
Shares issued for acquisition of Castle and oil and gas properties | 2,473 | 25 | 47,307 | — | — | 47,332 | ||||||||||||||||||||||||||
Shares issued for cash, net of offering costs | 1,500 | 15 | 33,855 | — | — | 33,870 | ||||||||||||||||||||||||||
Shares issued for drilling rig assets | 350 | 3 | 8,291 | — | — | 8,294 | ||||||||||||||||||||||||||
Shares issued for cash or return of shares upon exercise of options or vesting of restricted stock | 779 | 8 | 3,095 | — | — | 3,103 | ||||||||||||||||||||||||||
Issuance and amortization of non-vested stock | 512 | 5 | 3,430 | — | — | 3,435 | ||||||||||||||||||||||||||
Compensation on options vested | — | — | 1,447 | — | — | 1,447 | ||||||||||||||||||||||||||
Balance, December 31, 2006 | 53,439 | 534 | 430,479 | 4,865 | — | (7,645 | ) | 428,233 | ||||||||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||||||||
Net loss | — | — | — | — | $ | (149,347 | ) | (149,347 | ) | (149,347 | ) | |||||||||||||||||||||
Other comprehensive income transactions, net of tax | ||||||||||||||||||||||||||||||||
Hedging gains reclassified to income upon settlement | — | — | — | (13,920 | ) | (13,920 | ) | — | (13,920 | ) | ||||||||||||||||||||||
Change in fair value of derivative hedging instruments, | — | — | — | 6,025 | 6,025 | — | 6,025 | |||||||||||||||||||||||||
Tax effect of valuation allowance | — | — | — | 3,030 | 3,030 | — | 3,030 | |||||||||||||||||||||||||
Comprehensive loss | $ | (154,212 | ) | |||||||||||||||||||||||||||||
Shares issued for oil and gas properties | 1,229 | 12 | 23,753 | — | — | 23,765 | ||||||||||||||||||||||||||
Shares issued for cash, net of offering costs | 9,898 | 99 | 196,435 | — | — | 196,534 | ||||||||||||||||||||||||||
Shares issued for cash or return of shares upon exercise of options or vesting of restricted stock | 155 | 3 | 137 | — | — | 140 | ||||||||||||||||||||||||||
Issuance and amortization of non-vested stock | 1,708 | 16 | 13,610 | — | — | — | 13,626 | |||||||||||||||||||||||||
Compensation on options vested | — | — | 319 | — | — | — | 319 | |||||||||||||||||||||||||
Balance, December 31, 2007 | 66,429 | $ | 664 | $ | 664,733 | $ | — | $ | — | $ | (156,992 | ) | $ | 508,405 | ||||||||||||||||||
See accompanying notes to consolidated financial statements.
F-5
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended | Six Months Ended | Year Ended | ||||||||||||||
December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands) | ||||||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net Income (loss) | $ | (149,347 | ) | $ | 435 | $ | (590 | ) | $ | 15,050 | ||||||
Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||||||||||||||||
Depreciation, depletion, and amortization – oil and gas | 63,054 | 53,783 | 12,315 | 13,802 | ||||||||||||
Depreciation and amortization – drilling and trucking | 22,052 | 16,404 | 2,847 | 1,525 | ||||||||||||
Depreciation, depletion, and amortization – discontinued operations | 12,990 | 12,212 | 5,257 | 7,835 | ||||||||||||
Accretion of abandonment obligation | 319 | 197 | 96 | 253 | ||||||||||||
Stock option and non-vested stock compensation | 15,590 | 4,882 | 2,770 | 672 | ||||||||||||
Amortization of deferred financing costs | 4,429 | 2,396 | 669 | 858 | ||||||||||||
Unrealized (gain) loss on derivative contracts | 5,816 | (12,205 | ) | 9,872 | 330 | |||||||||||
Dry hole costs and impairment | 84,091 | 11,897 | 1,872 | — | ||||||||||||
Minority Interest | (1,231 | ) | 2,595 | 688 | (1,017 | ) | ||||||||||
Gain on sale of oil and gas properties | — | (20,034 | ) | — | — | |||||||||||
Gain on sale of marketable securities | — | — | (1,194 | ) | — | |||||||||||
Gain on sale of investment in LNG | — | (1,058 | ) | — | — | |||||||||||
Loss (Gain) on sale of discontinued operations | 2,644 | (10,775 | ) | (11,788 | ) | — | ||||||||||
Extraordinary gain on Castle acquisition | — | (8,776 | ) | — | — | |||||||||||
DHS stock granted to management | 245 | 280 | 140 | — | ||||||||||||
Deferred income tax expense (benefit) | 4,113 | (502 | ) | (7,336 | ) | (3,045 | ) | |||||||||
Other gain (loss) | 141 | 319 | — | 394 | ||||||||||||
Net changes in operating assets and liabilities: | ||||||||||||||||
Increase in trade accounts receivable | (4,316 | ) | (4,501 | ) | (10,454 | ) | (1,586 | ) | ||||||||
(Increase) decrease in prepaid assets | 441 | (731 | ) | (457 | ) | (1,844 | ) | |||||||||
(Increase) decrease in inventory | (1,385 | ) | 434 | 947 | (5,062 | ) | ||||||||||
(Increase) decrease in other current assets | 713 | (438 | ) | (1,968 | ) | (225 | ) | |||||||||
Increase in accounts payable trade | 23,838 | 4,477 | 6,688 | 14,004 | ||||||||||||
Increase in other accrued liabilities | 195 | 2,095 | 14,505 | 2,918 | ||||||||||||
Net cash provided by operating activities | 84,392 | 53,386 | 24,879 | 44,862 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Additions to property and equipment, | (332,450 | ) | (218,761 | ) | (157,519 | ) | (186,669 | ) | ||||||||
Additions to drilling and trucking equipment, | (22,292 | ) | (63,848 | ) | (21,828 | ) | (30,797 | ) | ||||||||
Acquisitions, net of cash acquired | (4,500 | ) | (8,564 | ) | (3,905 | ) | — | |||||||||
Proceeds from sale of oil and gas properties | 46,193 | 82,716 | 34,178 | 18,721 | ||||||||||||
Proceeds from sale of drilling assets | 7,145 | — | — | — | ||||||||||||
Proceeds from sale of marketable securities | — | — | 1,764 | — | ||||||||||||
Increase in marketable securities | (6,219 | ) | — | — | — | |||||||||||
Investment in unconsolidated affiliates | (3,929 | ) | — | — | — | |||||||||||
Loan to affiliate | (8,511 | ) | — | — | — | |||||||||||
Minority interest holder contributions (distributions) | (355 | ) | 9,018 | — | 14,800 | |||||||||||
(Increase) decrease in long term assets | (106 | ) | (3,646 | ) | 802 | 63 | ||||||||||
Net cash used in investing activities | (325,024 | ) | (203,085 | ) | (146,508 | ) | (183,882 | ) | ||||||||
Cash flows from financing activities: | ||||||||||||||||
Stock issued for cash upon exercise of options | 137 | 3,711 | 1,166 | 132 | ||||||||||||
Stock issued for cash, net | 202,084 | 33,870 | 95,026 | — | ||||||||||||
Proceeds from borrowings | 343,600 | 220,035 | 72,998 | 361,016 | ||||||||||||
Payment of financing fees | (4,897 | ) | (3,994 | ) | (502 | ) | (7,370 | ) | ||||||||
Repayment of borrowings | (297,867 | ) | (101,776 | ) | (43,781 | ) | (214,595 | ) | ||||||||
Net cash provided by financing activities | 243,057 | 151,846 | 124,907 | 139,183 | ||||||||||||
Net increase in cash and cash equivalents | 2,425 | 2,147 | 3,278 | 163 | ||||||||||||
Cash at beginning of period | 7,666 | 5,519 | 2,241 | 2,078 | ||||||||||||
Cash at end of period | $ | 10,091 | $ | 7,666 | $ | 5,519 | $ | 2,241 | ||||||||
Supplemental cash flow information: | ||||||||||||||||
Cash paid for interest and financing costs | $ | 13,926 | $ | 28,438 | $ | 8,149 | $ | 11,420 | ||||||||
Non-cash financing activities: | ||||||||||||||||
Common stock issued for the purchase of Castle and oil and gas properties | $ | 23,765 | $ | 47,332 | $ | 828 | $ | 22,191 | ||||||||
Common stock issued for the purchase of drilling and trucking equipment | $ | — | $ | 8,294 | $ | — | $ | 1,893 | ||||||||
See accompanying notes to consolidated financial statements.
F-6
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(1) Nature of Organization
Delta Petroleum Corporation (“Delta” or the “Company”) was organized December 21, 1984 as a Colorado corporation and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. On January 31, 2006, the Company reincorporated in the state of Delaware. The Company’s core areas of operation are the Rocky Mountain and Gulf Coast Regions, which comprise the majority of its proved reserves, production and long-term growth prospects. The Company owns interests in developed and undeveloped oil and gas properties in federal units offshore California, near Santa Barbara, and developed and undeveloped oil and gas properties in the continental United States.
The Company, through a series of transactions in 2004, 2005, and 2007, owns a 50.0% interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. Delta representatives currently constitute a majority of the members of the Board of DHS and Delta has the right to use all of the rigs owned by DHS on a priority basis, although approximately half of the rigs are currently working for third party operators. DHS also owns 100% of Chapman Trucking which was acquired in November 2005 and which ensures DHS rig mobility. In May 2006, DHS acquired two rigs in conjunction with the acquisition of C&L Drilling Company, Inc. (“C&L Drilling”). Also, during the second quarter of 2006, DHS engaged in a reorganization transaction pursuant to which it became a subsidiary of DHS Holding Company, a Delaware corporation, and the Company’s ownership interest became an interest in DHS Holding Company. References to DHS herein shall be deemed to include both DHS Holding Company and DHS, unless the context otherwise requires. DHS is a consolidated entity of Delta.
At December 31, 2007, the Company owned 4,277,977 shares of the common stock of Amber Resources Company of Colorado (“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company that owns undeveloped oil and gas properties in federal units offshore California, near Santa Barbara.
On February 19, 2002, the Company acquired 100% of the outstanding shares of Piper Petroleum Company (“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. Piper was merged into a subsidiary wholly owned by Delta.
In late 2005, the Company transferred its ownership in approximately 64,000 net acres of non-operated interests in the Columbia River Basin to CRB Partners, LLC, which originally was a wholly-owned subsidiary (“CRBP”). These interests consist of the Company’s 1% overriding royalty interest convertible into a 15% back-in working interest after project payout. During the first quarter of 2006, the Company sold a 44% minority interest in CRBP. Delta has retained the majority ownership in, and is the manager of, CRBP. The non-Delta members of CRBP have certain limited consent rights with respect to, among other things, CRBP’s election to convert to a working interest prior to actual project payout, disposition of its assets or effecting certain transactions outside the ordinary course of CRBP’s business. Further, Delta’s ownership in CRBP is subject to certain rights of first refusal and co-sale rights. The sole asset of CRBP is oil and gas properties contributed by Delta, and therefore, the sale of the minority interest in CRBP was accounted for as a disposal of oil and gas properties.
In March 2006, the Company sold approximately 26% of PGR Partners, LLC (“PGR”). PGR owns a 25% non-operated working interest in 6,314 gross acres in the Piceance Basin. The assets included in the sale consisted of both proved and unproved properties. The Company retained a 74% interest in, and is the manager of, PGR. The non-Delta members of PGR have certain limited consent rights with respect to, among other things, amending the joint operating agreement to which PGR is subject, disposition of its assets or effecting certain transactions outside the ordinary course of PGR’s business.
F-7
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(1) Nature of Organization, Continued
On April 28, 2006, Castle Energy Corporation shareholders approved the merger agreement between Delta and Castle Energy Corporation and subsidiaries (collectively, “Castle”). As of that date, Delta, via its merger subsidiary DPCA LLC (“DPCA”), acquired Castle. On August 21, 2006, the Company sold the Pennsylvania and West Virginia properties acquired with the Castle merger. DPCA now holds only minor non-oil and gas property assets of Castle. See Footnote 3 (“Oil and Gas Properties”).
(2) Summary of Significant Accounting Policies
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of Delta, Amber Resources Company of Colorado (“Amber”), Piper Petroleum Company (“Piper”), CRB Partners, LLC (“CRBP”), PGR Partners, LLC (“PGR”), DHS Holding Company and DHS Drilling Company (collectively “DHS”), DPCA LLC (“DPCA”) and other subsidiaries with minimal net assets or activity (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods presented. The Company does not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.
During June 2007, the Company acquired a 50% non-controlling ownership interest in Delta Oilfield Tank Company, LLC (“Delta Oilfield”) for cash consideration of $4.0 million. Delta Oilfield is accounted for using the equity method of accounting and is an unconsolidated affiliate of the Company. In conjunction with the investment, the Company entered into an agreement to finance up to $9.0 million for construction of a plant expansion. As of December 31, 2007, the Company had advanced $8.5 million to Delta Oilfield under this agreement, of which $7.5 million is included in other current assets in the accompanying consolidated balance sheets. The loan is payable quarterly, beginning after the expansion is complete, in an amount equal to 75% of distributable cash of Delta Oilfield, as defined, with any remaining balance due December 31, 2010.
Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures, including CRBP and PGR. The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements.
Certain reclassifications have been made to amounts reported in previous years to conform to the current year presentation. Among other items, revenues and expenses on properties that were sold during the year ended December 31, 2007 have been reclassified to income from discontinued operations for all periods presented. Such reclassifications had no effect on net income.
Fiscal Year Change
On September 14, 2005, the Board of Directors approved the change of the fiscal year end from June 30 to December 31, effective December 31, 2005. This Form 10-K includes information for the years ended December 31, 2007 and 2006, six-month transitional period ended December 31, 2005 and for the twelve-month period ended June 30, 2005. The unaudited financial information for the twelve months ended December 31, 2005 is as follows:
F-8
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
Twelve Months Ended | ||||
December 31, 2005 | ||||
(In thousands, except per share data) | ||||
Total Revenues | $ | 84,818 | ||
Operating Loss | (7,007 | ) | ||
Loss from continuing operations before income taxes and discontinued operations | (35,533 | ) | ||
Net Income | 5,706 | |||
Net income per common share: | ||||
Basic | $ | .13 | ||
Diluted | $ | .13 |
Cash Equivalents
Cash equivalents consist of money market funds. The Company considers all highly liquid investments with maturities at date of acquisition of three months or less to be cash equivalents.
Marketable Securities
For the six months ended December 31, 2005 and the year ended June 30, 2005, the Company had investments classified as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (“SFAS 115”), such securities are measured at fair market value in the financial statements with unrealized gains or losses recorded in other comprehensive income. At the time securities are sold or otherwise disposed of, gains or losses are included in earnings. During the six months ended December 31, 2005, the Company sold its investments as shown below.
Realized | Proceeds | |||||||||||
Cost | Gain (Loss) | From Sale | ||||||||||
(In thousands) | ||||||||||||
December 31, 2005 | ||||||||||||
Bion Environmental Technologies, Inc. | $ | 152 | $ | (140 | ) | $ | 12 | |||||
Tipperary Oil & Gas Company | 418 | 1,334 | 1,752 | |||||||||
$ | 570 | $ | 1,194 | $ | 1,764 | |||||||
Unrealized | Estimated | |||||||||||
Cost | Gain (Loss) | Market Value | ||||||||||
(In thousands) | ||||||||||||
June 30, 2005 | ||||||||||||
Bion Environmental Technologies, Inc. | $ | 152 | $ | (140 | ) | $ | 12 | |||||
Tipperary Oil & Gas Company | 418 | 1,334 | 1,752 | |||||||||
$ | 570 | $ | 1,194 | $ | 1,764 | |||||||
During 2007, the Company held investments in securities that were classified as trading securities and thus recorded at estimated fair market value with interest, dividend income, and changes in market value recognized in earnings. The Company recorded $334,000 of losses related to these securities during the year ended December 31, 2007. Due to the marketplace changes in late 2007 affecting the liquidity of such investments, the Company reclassified the securities from trading to available for sale as of December 31, 2007. Accordingly, the marketable securities are recorded in long term assets in the accompanying consolidated balance sheet and future changes in their fair market value will be recorded in accumulated other comprehensive income until the securities are sold. If issuers of the securities we hold are unable to successfully close future auctions and their credit ratings deteriorate, we may in future periods be required to record an impairment charge to earnings on these investments.
F-9
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
Oil and Gas Properties Held for Sale
Oil and Gas Properties held for sale as of December 31, 2007 represent the Company’s Texas Midway Loop oil and gas properties that are for sale. Accordingly, current and prior years’ operating revenue and expense have been reclassified as a component of discontinued operations.
Oil and Gas Properties held for sale as of December 31, 2006 represent the Company’s Kansas oil and gas properties that were sold in January 2007 and the Midway Loop assets mentioned above which were reclassified to conform to current presentation.
Inventories
Inventories consist of pipe and other production equipment. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value.
Investment in LNG project
On March 30, 2006, the Company sold its long-term minority investment in a liquid natural gas (“LNG”) project for total proceeds of $2.1 million. The Company recorded a gain on sale of $1.1 million ($657,000 net of tax).
Minority Interest
Minority interest represents the 50.0% (47% for Chesapeake Energy Corporation and 3.0% for DHS executive officers and management) investors of DHS at December 31, 2007. Minority interest for December 31, 2006, represents 50.6% (45% for Chesapeake Energy Corporation and 5.6% for DHS executive officers and management) investors of DHS at December 31, 2006. During 2007, one of the founding officers was bought out, resulting in a slight increase in Delta’s ownership of DHS.
Investment in and Earnings (Losses) From Unconsolidated Affiliates
Investments in operating entities where the Company has the ability to exert significant influence, but does not control the operating and financial policies, are accounted for using the equity method and include the Company’s 50% investment in Delta Oilfield and other minor investments. The Company’s share of net income of these entities is recorded as earnings (losses) from unconsolidated affiliates in the consolidated statements of operations. Investments in operating entities where the Company does not exert significant influence are accounted for using the cost method, and income is only recognized when a distribution is received. These investments in unconsolidated affiliates are carried as a single amount in our consolidated balance sheets totaling $10.3 million and $2.9 million as of December 31, 2007 and December 31, 2006, respectively.
Revenue Recognition
Oil and Gas
Revenues are recognized when title to the products transfers to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of the year ended December 31, 2007 and 2006, six months ended December 31, 2005 and the year ended June 30, 2005, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements except for an imbalance acquired during fiscal 2005 which was collected during the six months ended December 31, 2005.
F-10
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
Drilling and Trucking
The Company earns its contract drilling revenues under daywork or turnkey contracts. The Company recognizes revenues on daywork contracts for the days completed based on the dayrate each contract specifies. Turnkey contracts are accounted for on a percentage-of-completion basis. The costs of drilling the Company’s own oil and gas properties are capitalized in oil and gas properties as the expenditures are incurred. Trucking and hauling revenues are recognized based on either an hourly rate or a fixed fee per mile depending on the type of vehicle, the services performed, and the contract terms.
Property and Equipment
The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological or geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.
Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is charged to expense. If the unproved properties are determined to be productive, the related costs are transferred to proved gas and oil properties. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss until all costs have been recovered.
Depreciation and depletion of capitalized acquisition, exploration and development costs is computed on the units-of-production method by individual fields as the related proved reserves are produced.
Drilling equipment is recorded at cost or estimated fair value upon acquisition and depreciated on a component basis using the straight-line method over their estimated useful lives ranging from five to 15 years. Pipelines and gathering systems and other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 40 years.
Depreciation, depletion and amortization of oil and gas property and equipment for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the fiscal year ended June 30, 2005 were $63.4 million, $54.0 million, $12.4 million, and $14.1 million, respectively.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) requires that long-lived assets be reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.
Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized in accordance with SFAS 144 are permanent and may not be restored in the future.
F-11
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
The Company assesses developed properties on an individual field basis for impairment on at least an annual basis. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, the Company recorded no impairment provision attributable to producing properties for the six months ended December 31, 2005 and the fiscal year ended June 30, 2005. During the year ended December 31, 2007, an impairment of $58.4 million was recorded primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 million and $10.3 million, respectively), and the South Angleton field in Texas ($9.7 million), primarily due to lower Rocky Mountain natural gas prices and marginally economic deep zones on the Howard Ranch Prospect. During the year ended December 31, 2006, an impairment of $10.4 million was recorded on certain of the Company’s eastern Colorado properties primarily due to lower Rocky Mountain natural gas prices in the latter part of the year. In addition, during 2006, an impairment of $1.0 million was recorded on certain Oklahoma properties that were held for sale at December 31, 2007.
For undeveloped properties, the need for an impairment is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the undeveloped property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, the Company recorded no impairment provision attributable to undeveloped properties for the years ended December 31, 2007 and 2006, and June 30, 2005.
However, during the six months ended December 31, 2005, a dry hole was drilled on the Company’s prospect located in Orange County, California. Based on drilling results and the Company’s evaluation of the prospect, the Company determined that it would not pursue development of the field and accordingly an impairment was recorded. Included in the Company’s consolidated statement of operations for the six months ended December 31, 2005 are $2.0 million for the dry hole that was drilled and $1.3 million for the full impairment of the remaining leasehold costs related to the prospect.
For the fiscal year 2008, the Company is continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or commodity prices may cause a revision to future quarters’ estimates of those properties’ future cash flows. Such revisions of estimates could require the Company to record an impairment in the period of such revisions.
Goodwill
Goodwill represents the excess of the cost of the acquisitions by DHS of C&L Drilling in May 2006, Rooster Drilling in March 2006, and Chapman Trucking in November 2005 over the fair value of the assets and liabilities acquired. For goodwill and intangible assets recorded in the financial statements, an impairment test is performed at least annually in accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” (“SFAS 142”). No impairment of goodwill was indicated as a result of the Company’s impairment test performed during the third quarter of 2007.
F-12
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
Asset Retirement Obligations
The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller. The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005:
Years Ended | Six Months Ended | Year Ended | ||||||||||||||
December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands) | ||||||||||||||||
Asset retirement obligation — beginning of period | $ | 4,421 | $ | 3,467 | $ | 3,691 | $ | 2,647 | ||||||||
Accretion expense | 278 | 199 | 96 | 253 | ||||||||||||
Change in estimate | 313 | 639 | (19 | ) | — | |||||||||||
Obligations acquired | 1,743 | 850 | 160 | 1,153 | ||||||||||||
Obligations settled | (224 | ) | (139 | ) | — | — | ||||||||||
Obligations on sold properties | (1,332 | ) | (595 | ) | (461 | ) | (362 | ) | ||||||||
Asset retirement obligation — end of period | 5,199 | 4,421 | 3,467 | 3,691 | ||||||||||||
Less: Current asset retirement obligation | (1,045 | ) | (408 | ) | (465 | ) | (716 | ) | ||||||||
Long-term asset retirement obligation | $ | 4,154 | $ | 4,013 | $ | 3,002 | $ | 2,975 | ||||||||
In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS 143. The Company applied the guidance of FIN 47 beginning July 1, 2005 resulting in no impact on its financial statements.
Comprehensive Income (Loss)
Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, if any. The components of comprehensive income (loss) for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005 are as follows (in thousands):
Six Months Ended | Year Ended | |||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
Net income (loss) | $ | (149,347 | ) | $ | 435 | $ | (590 | ) | $ | 15,050 | ||||||
Other comprehensive income (transactions): | ||||||||||||||||
Realized gain on equity securities sold, net of tax benefit of $458 | — | — | (736 | ) | — | |||||||||||
Unrealized gain on marketable securities, net of tax expense of zero, zero, zero and $458, respectively | — | — | — | 394 | ||||||||||||
Hedging instruments reclassified to income upon settlement, net of tax benefit of zero, $1,738 and $1,733, respectively | (13,920 | ) | 2,860 | 2,398 | — | |||||||||||
Change in fair value of derivative hedging instruments, net of tax (expense) benefit of zero, ($4,315), $1,036, and $3,722, respectively | 6,025 | 7,002 | (1,434 | ) | (5,961 | ) | ||||||||||
Tax effect of valuation allowance | 3,030 | — | — | — | ||||||||||||
Comprehensive income (loss) | $ | (154,212 | ) | $ | 10,297 | $ | (362 | ) | $ | 9,483 | ||||||
F-13
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
Financial Instruments
The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, marketable securities and accounts receivable. The Company’s cash equivalents are cash investments funds that are placed with major financial institutions. The Company manages and controls market and credit risk through established formal internal control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure to purchasers of the Company’s oil and natural gas through formal credit policies, monitoring procedures, and letters of credit.
The Company used various assumptions and methods in estimating fair value disclosures for financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair market value due to the short maturity of these instruments. The carrying amount of the Company’s credit facility approximated fair value because the interest rates on the credit facility are variable. The fair value of marketable securities and the fair value of long-term debt were estimated based on quoted market prices. The fair values of derivative instruments were estimated based on discounted future net cash flows.
Accounting and reporting standards require that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. Those standards also require that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of Other Comprehensive Income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The Company had no such qualifying hedge instruments at December 31, 2007.
Stock Option Plans
Prior to July 1, 2005, the Company accounted for its stock option plans in accordance with the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. As such, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.
In December 2004, SFAS No. 123 (Revised 2004), “Share Based Payment” (“SFAS 123R”) was issued, which now requires the Company to recognize the grant-date fair value of stock options and other equity based compensation issued to employees, in the statement of operations. The cost of share based payments is recognized over the period the employee provides service. The Company adopted SFAS 123R effective July 1, 2005 using the modified prospective method and recognized compensation expense related to stock options of $319,000, $1.4 million and $2.0 million, relating to employee provided services during the years ended December 31, 2007 and 2006 and six months ended December 31, 2005, respectively.
Non-Qualified Stock Options — Directors and Employees
On December 14, 2004, the stockholders ratified the Company’s 2004 Incentive Plan (the “2004 Plan”) under which it reserved up to an additional 1,650,000 shares of common stock for issuance. Although grants of shares of common stock were made under the 2004 Plan during the 2006 fiscal year, no stock options were issued by the Company during that period.
F-14
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
On January 29, 2007, the stockholders ratified the Company’s 2007 Performance and Equity Incentive Plan (the “2007 Plan”). Subject to adjustment as provided in the 2007 Plan, the number of shares of Common Stock that may be issued or transferred, plus the amount of shares of Common Stock covered by outstanding awards granted under the 2007 Plan, may not in the aggregate exceed 2,800,000. The 2007 Plan supplements the Company’s 1993, 2001 and 2004 Incentive Plans. The purpose of the 2007 Plan is to provide incentives to selected employees and directors of the Company and its subsidiaries, and selected non-employee consultants and advisors to the Company and its subsidiaries, who contribute and are expected to contribute to the Company’s success and to create stockholder value.
Incentive awards under the 2007 Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date under the Company’s various incentive plans have been non-qualified stock options as defined in such plans.
Exercise prices for options outstanding under the Company’s various plans as of December 31, 2007 ranged from $1.75 to $15.60 per share, and the weighted-average remaining contractual life of those options was 4.18 years. All compensation expense related to these options has been recorded as of December 31, 2007. The Company has not issued stock options since the adoption of SFAS 123R, though it has the discretion to issue options again in the future. At December 31, 2007, all remaining options outstanding were fully vested.
Had compensation cost for the Company’s stock-based compensation plan been determined using the fair value of the options at the grant date prior to July 1, 2005, the Company’s net income for the year ended June 30, 2005 would have been as follows:
Year Ended | ||||
June 30, 2005 | ||||
(In thousands, except per share amounts) | ||||
Net income (loss) | $ | 15,050 | ||
Equity compensation booked | 306 | |||
FAS 123 compensation effect | (2,759 | )1 | ||
Pro forma net income after FAS 123 implementation | $ | 12,597 | ||
Pro forma income per common share: | ||||
Basic | $ | .31 | ||
Diluted | $ | .30 | ||
1 | During the quarter ended December 31, 2004, the Company granted 420,000 options to officers and 98,000 options to directors to purchase shares of its common stock at an average price of $15.34 per share, which was the market price on the date of the grant. The officers’ options vest over a three year period and the directors’ options vested on March 15, 2005. The fair market value of each option granted was $10.07 and was calculated using a risk free rate of 4.60%, volatility factors of the expected market price of the Company’s common stock of 48.76% and an average expected life of 8.0 years. During the quarter ended December 31, 2004, the Company granted 318,000 options to employees to purchase 318,000 shares of its common stock at an average price of $15.29 per share. Certain options were granted below market price. For options granted below market price, the Company recorded an expense for the difference between the option price and the grant price. The employee options vested over a year period. The average fair market value of each option granted was $7.10 and was calculated using a risk free rate of 4.60%, volatility factors of the expected market price of the Company’s common stock of 48.76% and an average expected life of 3.2 years. During the quarter ended March 31, 2005, the Company granted 105,700 options to employees to purchase 105,700 shares of its common stock at an average price of $14.75 per share. The employee options vested over a year period. The average fair market value of each option granted was $7.49 and was calculated using a risk free rate of 4.65%, volatility factors of the expected market price of the Company’s common stock of 61.23% and an average expected life of 2.0 years. The SFAS 123R compensation effect is calculated based on the options’ vesting period and includes additional grants from other periods. |
On February 9, 2007, the Company issued executive performance share grants to each of the Company’s four executive officers (Roger Parker — Chief Executive Officer, John Wallace — President, Kevin Nanke — Chief Financial Officer, and Ted Freedman — Senior Vice President and General Counsel) that provide that the shares of common stock awarded will vest if the market price of Delta stock reaches and maintains certain price levels. The awards will vest in five tranches on the dates that the average daily closing price of Delta’s common stock equals or exceeds a defined price for a specified number of trading days within any period of 90 calendar days (a “Vesting Threshold”). The Vesting Threshold for the first tranche is $40, for the second tranche it is $50, for the third tranche it is $60, for the fourth tranche it is $75 and for the fifth tranche it is $90. Upon attaining the Vesting Threshold for each of the
F-15
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
first, second and third tranches, 100,000 of Mr. Parker’s shares would vest for each such tranche, 70,000 of Mr. Wallace’s shares would vest for each such tranche and 40,000 of Mr. Nanke’s and Mr. Freedman’s shares would each vest for each such tranche. Upon attaining the Vesting Thresholds for each of the fourth and fifth tranches, 150,000 of Mr. Parker’s shares would vest for each such tranche, 105,000 of Mr. Wallace’s shares would vest for each such tranche and 60,000 of Mr. Nanke’s and Mr. Freedman’s shares would each vest for each such tranche. Each award provides for the lapse of the $75 and $90 tranches if the $40 tranche has not vested on or before March 31, 2008, and the lapse of the $50 and $60 tranches if the $40 tranche has not vested on or before March 31, 2009. In addition, the grants will lapse and be forfeited to the extent not vested prior to a termination of the executive’s employment, and will be forfeited to the extent not vested on or before January 29, 2017. The awards also provide for a minimum 364-day period between achievement of two vesting thresholds, subject to acceleration of vesting upon a change in control at a price in excess of one or more of the stock price thresholds, with proportional vesting should a change in control occur at a price in excess of one threshold, but below the next threshold.
The performance share grants were valued at $18.4 million, in the aggregate, with derived service periods over which the value of each tranche will be expensed ranging from 1 to 5 years. Equity compensation of $6.9 million related to the performance share grants was included in general and administrative expense during the year ended December 31, 2007.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes as set forth in SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. Deferred tax assets are recorded based on the “more likely than not” requirements of SFAS 109, and to the extent this threshold is not met, a valuation allowance is recorded. The Company is currently providing a full valuation allowance on its net deferred tax assets. DHS deferred tax assets and liabilities are recorded on the same basis of accounting, though no valuation allowance has been provided.
Income (Loss) per Common Share
Basic income (loss) per share is computed by dividing net income (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted income (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, convertible debt, stock options, restricted stock and warrants.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and gas reserves, bad debts, depletion and impairment of oil and gas properties, marketable securities, income taxes, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.
F-16
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
Recently Issued Accounting Standards and Pronouncements
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any resulting goodwill, and any noncontrolling interest in the acquiree. The Statement also provides for disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year 2009, and must be applied prospectively to business combinations completed on or after that date. The Company will evaluate how the new requirements could impact the accounting for any acquisitions completed beginning in fiscal 2009 and beyond, and the potential impact on its consolidated financial statements.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for noncontrolling interests (“minority interests”) in subsidiaries. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year 2009, and must be applied prospectively, except for the presentation and disclosure requirements, which will apply retrospectively. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits companies to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, or fiscal year 2008. The Company has not yet determined if it will elect to apply any of the provisions of SFAS 159 or what effect the adoption of the Statement would have, if any, on its consolidated financial statements.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. SFAS 157 aims to improve the consistency and comparability of fair value measurements by creating a single definition of fair value. The Statement emphasizes that fair value is not entity-specific, but instead is a market-based measurement of an asset or liability. SFAS 157 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for fiscal year commencing January 1, 2008. The Company does not expect the impact of SFAS 157 to be material to the Company’s financial condition or results of operations. The Company anticipates the primary impact of the standard will be additional disclosures related to the measurement of fair value in the Company’s recurring impairment test calculations related to oil and gas properties, drilling rigs, and goodwill, the valuation of oil and gas derivative instruments, and the valuation of assets acquired or liabilities assumed in future business combinations, if any.
Recently Adopted Accounting Standards and Pronouncements
Effective January 1, 2007, the Company adopted provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. Upon the adoption of FIN 48, the Company had no unrecognized tax benefits. During the year ended December 31, 2007, no adjustments were recognized for uncertain tax benefits.
F-17
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(2) Summary of Significant Accounting Policies, Continued
The Company recognizes interest and penalties related to uncertain tax positions in income tax (benefit)/expense. No interest and penalties related to uncertain tax positions were accrued at December 31, 2007.
The tax years 2003 through 2007 for federal returns and 2002 through 2007 for state returns remain open to examination by the major taxing jurisdictions in which we operate, although no material changes to unrecognized tax positions are expected within the next twelve months.
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 was issued to provide interpretive guidance on how the effects of the carryover reversal of prior year misstatements should be considered in quantifying a current year misstatement. The provisions of SAB 108 were effective for the December 31, 2006 year-end. The adoption of SAB 108 had no impact on our financial position or results of operations.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“SFAS 154”). SFAS 154 requires retrospective application to prior periods’ financial statements for changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The implementation of SFAS 154 did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.
In April 2005, the FASB issued Staff Position 19-1, “Accounting for Suspended Well Costs” (“FSP 19-1”). FSP 19-1 provides guidance for evaluating whether sufficient progress is being made to determine whether reserves can be classified as proved and specifies that drilling costs for completed exploratory wells should be expensed if the related reserves cannot be classified as proved within one year unless certain criteria are met. FSP 19-1 is effective for all reporting periods beginning after April 4, 2005, and accordingly, the Company adopted FSP 19-1 on July 1, 2005. The following table reflects the net changes in capitalized exploratory well costs for the periods presented below:
Six Months Ended | Year Ended | |||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
Balance at beginning of period | $ | 27,453 | $ | 357 | $ | 1,033 | $ | 10 | ||||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves1 | 30,797 | 27,744 | 10,151 | 10,991 | ||||||||||||
Exploratory well costs included in property divestitures | (2,941 | ) | — | — | — | |||||||||||
Reclassified to proved oil and gas properties based on the determination of proved reserves | — | (357 | ) | (6,754 | ) | (7,197 | ) | |||||||||
Capitalized exploratory well costs charged to dry hole expense | (11,218 | ) | (291 | ) | (4,073 | ) | (2,771 | ) | ||||||||
Balance at end of period | $ | 44,091 | $ | 27,453 | $ | 357 | $ | 1,033 | ||||||||
Exploratory well costs capitalized for one year or less | 35,649 | 27,453 | 357 | 1,033 | ||||||||||||
Exploratory well costs capitalized for greater than one year after completion of drilling | 8,442 | — | — | — | ||||||||||||
Balance at end of period | $ | 44,091 | $ | 27,453 | $ | 357 | $ | 1,033 | ||||||||
1 | The final FSP directs that costs suspended and expensed in the same period not be included in this analysis. | |
2 | Capitalized exploratory well costs for fiscal years ended June 30, 2005 are presented based on the Company’s previous accounting policy. |
Included in capitalized exploratory well costs capitalized for greater than one year at December 31, 2007 were two projects. One project representing $1.7 million of the costs is non-operated and pending connection to a new field gathering system. During 2007, permitting for the infrastructure was obtained and construction began. The second project representing $6.8 million of the costs is related to the Company’s Paradox Basin properties. In early 2008, permitting was obtained and construction began for the necessary pipeline infrastructure.
F-18
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(3) Oil and Gas Properties
Unproved Undeveloped Offshore California Properties
The Company has direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $14.8 million and $12.5 million at December 31, 2007 and 2006, respectively. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. The recovery of the Company’s investment in these properties through the sale of hydrocarbons will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed, and is therefore subject to other substantial risks and uncertainties.
The Company is not the designated operator of any of these properties but is an active participant in the ongoing activities of each property along with the designated operator and other interest owners. If the designated operator elected not to or was unable to continue as the operator, the other property interest owners would have the right to designate a new operator as well as share in additional property returns prior to the replaced operator being able to receive returns. Based on the Company’s size, it would be difficult for the Company to proceed with exploration and development plans should other substantial interest owners elect not to proceed; however, to the best of its knowledge, the Company believes the designated operators and other major property interest owners would proceed with exploration and development plans under the terms and conditions of the operating agreement if they were permitted to do so by regulators.
Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair values of its property interests are in excess of their carrying values at December 31, 2007, 2006 and 2005 and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off.
The ownership rights in each of these properties have been retained under various suspension notices issued by the Mineral Management Service (MMS) of the U.S. federal government whereby, as long as the owners of each property were progressing toward defined milestone objectives, the owners’ rights with respect to the properties will continue to be maintained. The issuance of the suspension notices has been necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies.
In 2001, however, a Federal Court in the case of California v. Norton, et al. ruled that the MMS does not have the power to grant suspensions on the subject leases without first making a consistency determination under the Coastal Zone Management Act (“CZMA”), and ordered the MMS to set aside its approval of the suspensions of the Company’s offshore leases and to direct suspensions for a time sufficient for the MMS to provide the State of California with the required consistency determination. In response to the ruling in the Norton case, the MMS made a consistency determination under the CZMA and the leases are still valid.
Further actions to develop the leases have been delayed, however, pending the outcome of a separate lawsuit (the “Amber case”) that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. by the Company, its 92%-owned subsidiary, Amber Resources Company of Colorado, and ten other property owners alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of the Company’s and Amber’s offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses
F-19
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(3) Oil and Gas Properties, Continued
it had received at the time of sale. On January 19, 2006, the government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by the Company (“Lease 452”). In its motion for reconsideration, the government has asserted that the Company should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and post-trial briefing is currently in process. The Company believes that the government’s assertion is without merit, but it cannot predict with certainty the ultimate outcome of this matter.
On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty five of the forty lawsuit leases. Under this order the Company is entitled to receive a gross amount of approximately $58.5 million and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. No payments will be made until all appeals have either been waived or exhausted. In the event that the Company ultimately receives any proceeds as the result of this litigation, it will be obligated to pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.
If new activities are commenced on the any of the leases, the requisite exploration and development plans will be subject to review by the California Coastal Commission for consistency with the CZMA and by the MMS for other technical requirements. None of the leases is currently impaired, but in the event that they are found not to be valid for some reason in the future, it would appear that they would become impaired. For example, if there is a future adverse ruling by the California Coastal Commission under the CZMA and the Company decides not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear the Company’s appeal of any such ruling or ultimately makes an adverse determination, it is likely that some or all of these leases would become impaired and written off at that time. It is also possible that other events could occur that would cause the leases to become impaired, and the Company will continuously evaluate those factors as they occur.
Year Ended December 31, 2007 — Acquisitions
On October 1, 2007, the Company completed a transaction involving an exchange of Washington County, Colorado properties and cash consideration of $33.0 million, prior to customary purchase price adjustments, to acquire a 12.5% working interest in the Garden Gulch field in the Piceance Basin. The transaction was accounted for as a non-monetary transaction in relation to the exchange of assets with a nominal loss recorded on the divestiture of the Washington County assets equal to the fair value of the asset relinquished less its net book value. The acquisition basis of the Garden Gulch asset acquired was recorded equal to the fair value of the Washington County assets relinquished plus the additional cash consideration paid.
On June 8, 2007, the Company issued 475,000 shares of common stock valued at approximately $9.9 million using a 5-day average closing price to acquire an additional interest in one well already owned and operated by the Company, and an additional interest in a non-operated property, both located in Polk County, Texas.
On March 9, 2007, the Company issued 754,000 shares of common stock valued at approximately $13.8 million using a 5-day average closing price for additional interests in two wells already owned and operated by the Company located in Polk County, Texas.
F-20
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(3) Oil and Gas Properties, Continued
On March 1, 2007, the Company paid $3.5 million for interests in producing properties and 39,000 undeveloped net acres in Fremont County, Wyoming.
In March 2007, the Company executed an earn-in agreement with EnCana whereby the Company can earn up to 6,000 net acres in the Piceance Basin with the drilling of 128 wells during the next 36 months. The Company is committed to drill 64 total wells, eight of which were drilled by October 31, 2007. The remaining wells are required to be drilled by June 1, 2009. The Company is liable for $250,000 per undrilled well in the event the drilling obligations are not met.
Year Ended December 31, 2006 — Acquisitions
On April 28, 2006, Castle shareholders approved the merger agreement between Delta and Castle. As of that date, Delta via its merger subsidiary DPCA, acquired Castle for a purchase price of $33.6 million comprised of 1.8 million net shares issued (8,500,000 shares issued net of 6,700,000 Delta shares owned by Castle) valued at $31.2 million and $2.4 million of transaction costs. Delta obtained assets valued at $39.7 million which were comprised of cash, producing oil and gas properties located in Pennsylvania and West Virginia, and certain other assets. Due to the excess fair value of the assets acquired compared to the purchase price of the transaction and in accordance with SFAS No. 141 when acquired assets are held for sale in the near term, Delta recorded a $6.1 million extraordinary gain ($9.6 million, net of $3.5 million of deferred taxes) during the quarter ended June 30, 2006. The properties were actually sold during August 2006 and a true-up of the gain based on actual final proceeds from the sale was recorded. No pro forma information is presented because discontinued operations are not reported in revenue and earnings from continuing operations, and the information related to the acquisition would be the same as the amounts reported.
On February 1, 2006 Delta entered into a purchase and sale agreement with Armstrong Resources, LLC (“Armstrong”) to acquire a 65% working interest in approximately 88,000 undeveloped gross acres in the central Utah hingeline play for a purchase price of $24 million in cash and 673,401 shares of common stock valued at $16.1 million. The closing of the transaction was effective as of January 26, 2006. Armstrong retained the remaining 35% working interest in the acreage. As part of the transaction, Delta agreed to pay 100% of the drilling costs for the first three wells in the project. Delta will be the operator of the majority of the acreage, and drilling of the first well commenced in November 2006.
Six Months Ended December 31, 2005 — Acquisitions
On September 29, 2005 the Company acquired an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington, and an interest in undeveloped acreage in the Piceance Basin in Colorado from Savant Resources, LLC (“Savant”) for an aggregate purchase price of $85.0 million in cash. James Wallace, a director of Delta, owns approximately a 1.7% interest in Savant, and also serves as a director of Savant. The majority of the acquired acreage in the Columbia River Basin consolidated the Company’s leasehold position at that time. Subsequent to the acquisition, Delta owned a 100% working interest in approximately 385,000 net acres. This acquisition included a small portion of acreage that is subject to an agreement with EnCana Oil & Gas (USA) Inc., whereby the Company has the right to convert an overriding royalty interest to a working interest at project payout. In the Piceance Basin, the Company acquired Savant’s interest in an entity that owns a 25% interest in approximately 6,314 gross acres that is currently being developed. The acquisition was funded through the issuance of securities discussed in Footnote 6, “Stockholders’ Equity.”
F-21
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(3) Oil and Gas Properties, Continued
Fiscal 2005 — Acquisitions
On May 4, 2005, the Company purchased from an unrelated private company a 14.25% back-in working interest in approximately 427,000 acres in the Columbia River Basin for $18.2 million in cash. The acreage is in close proximity to many of its existing leasehold interests in the basin and includes a lease on which another operator is currently drilling. The interest acquired is a non-cost bearing interest with a back-in after project payout. The Company can, however, at any time and at its discretion, convert the interest to a cost-bearing working interest by paying its proportionate share of the costs incurred in the project.
On December 15, 2004, the Company entered into a purchase and sale agreement to acquire substantially all of the oil and gas assets owned by several entities related to Manti Resources, Inc., which was an unaffiliated, privately held Texas corporation (“Manti”). The adjusted purchase price of $59.7 million was paid in cash at the closing of the transaction, which occurred on January 21, 2005. Substantially all of the assets that were acquired from Manti have been pledged as collateral on the Company’s bank credit facility.
On September 15, 2004, the Company acquired seven wells in Karnes County, Texas from an unrelated entity and an unrelated individual for $5.0 million in cash.
On July 1, 2004, the Company acquired certain interests in California’s Sacramento Basin and a 7.5% reversionary working interest in the South Tongue interests in Washington County, Colorado from Edward Mike Davis, LLC, a greater than 5% stockholder, for 760,000 shares of the Company’s common stock valued at $10.4 million using the average five-day closing price before and after the terms of the agreement were agreed upon and closed. The total acquisition cost was allocated $4.3 million to proved developed producing and $6.1 million to proved undeveloped.
Fiscal 2006 — Dispositions
During December 2005, Delta transferred its ownership in approximately 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin to CRBP. In January and March 2006, Delta sold a combined 44% minority interest in CRBP. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, the Company recorded a $13.0 million gain ($8.1 million net of tax) and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction.
In March 2006, the Company sold approximately 26% of PGR. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain could be recognized as all of the unproved cost basis was not yet recovered. The Company recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million offset to property during the first quarter of 2006 as a result of the transaction. The Company retains a 74% interest in PGR.
Six Months Ended December 31, 2005 — Dispositions
During October 2005, the Company sold its interest in various insignificant fields that were not strategic to the Company for proceeds of $5.3 million. The Company recorded a gain of $1.6 million, net of a $1.0 million provision for income taxes.
F-22
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(3) Oil and Gas Properties, Continued
Discontinued Operations
In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the results of operations and gain (loss) relating to the sale of the following property interests have been reflected as discontinued operations. Also included in discontinued operations are the Company’s Midway Loop, Texas oil and gas properties which are held for sale at December 31, 2007.
On October 1, 2007, the Company completed a transaction involving an exchange of Washington County, Colorado properties and cash consideration of $33.0 million, prior to customary purchase price adjustments, to acquire a 12.5% working interest in the Garden Gulch field in the Piceance Basin.
On September 4, 2007, the Company completed the sale of certain non-core properties located in North Dakota for cash consideration of approximately $6.2 million. The transaction resulted in a gain on sale of properties of $4.3 million.
On March 30, 2007, the Company completed the sale of certain non-core properties located in New Mexico and East Texas for cash consideration of approximately $31.5 million, prior to customary purchase price adjustments. The sale resulted in a loss of approximately $10.8 million.
On March 27, 2007, the Company completed the sale of certain non-core properties located in Australia for cash consideration of approximately $6.0 million. The sale resulted in an after-tax gain of $2.0 million.
On January 10, 2007, the Company completed the sale of certain non-core properties located in Padgett field, Kansas for cash consideration of $5.6 million. The transaction resulted in a gain on sale of properties of $297,000.
On August 21, 2006, the Company completed the sale of the properties acquired with the Castle acquisition in April 2006. During the year ended December 31, 2006, the Company recorded a $5.6 million extraordinary gain in accordance with SFAS No. 141.
On August 11, 2006, the Company sold certain non-operated East Texas interests for sales proceeds of $14.6 million and a gain of $9.8 million ($6.1 million net of tax).
On June 1, 2006, the Company completed the sale of certain properties located in Pointe Coupee Parish, Louisiana, for cash consideration of $8.9 million with an effective date of May 1, 2006. The transaction resulted in an after-tax gain on sale of oil and gas properties of $596,000.
On September 2, 2005, the Company completed the sale of its Deerlick Creek field in Tuscaloosa County, Alabama for $30.0 million with an effective date of July 1, 2005. The Company recorded an after tax gain on sale of oil and gas properties of $10.2 million on net proceeds of approximately $28.9 million after normal closing adjustments.
F-23
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(3) Oil and Gas Properties, Continued
The following table shows the total revenues and income included in discontinued operations for the above mentioned oil and gas properties for the years ended December 31, 2007 and 2006, the six months ended December 31, 2005, and the year ended June 30, 2005:
Six Months Ended | Year Ended | |||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues | $ | 36,084 | $ | 36,956 | $ | 18,012 | $ | 38,425 | ||||||||
Income from discontinued operations | $ | 17,642 | $ | 14,743 | $ | 8,686 | $ | 21,630 | ||||||||
Income tax expense | (86 | ) | (5,580 | ) | (2,734 | ) | (8,196 | ) | ||||||||
Income from discontinued operations, net of tax | $ | 17,556 | $ | 9,163 | $ | 5,952 | $ | 13,434 | ||||||||
(4) DHS Drilling Company
On April 15, 2005, the Company acquired a 49.4% ownership interest in DHS Drilling Company. The investment included the contribution of all of the net assets of the then 100% owned subsidiary, Big Dog, and certain drilling assets acquired by the Company. Previously, on March 31, 2005, the Company had purchased the remaining 50% interest of Big Dog owned by Davis for 100,000 shares of Delta’s common stock valued at $1.4 million based on the closing stock price on March 31, 2005, its 50% interest in Shark, another 100% owned subsidiary, and certain drilling equipment. Delta has the right to use all of the DHS rigs on a priority basis, although approximately one-half are currently working for third party operators.
In January 2006, the Company purchased Rooster Drilling Company (“Rooster Drilling”) for 350,000 shares of Delta common stock valued at $8.3 million. Rooster Drilling owned one drilling rig, an Oilwell 66 with a depth capacity of 12,000 feet. Concurrent with the Company’s acquisition of Rooster Drilling, the Company and DHS entered into an operating agreement whereby DHS operated the rig (“Rig 15”) on behalf of the Company. In March 2006, the Company contributed Rooster Drilling (renamed “Hastings Drilling Company”) to DHS.
In March 2006, DHS issued additional common stock to Delta, Chesapeake, and officers and management of DHS in exchange for assets, cash and notes as described below. The Company contributed Rooster Drilling and additional cash totaling $9.9 million to DHS in exchange for 2.7 million shares of DHS common stock. Chesapeake contributed approximately $9.0 million in cash to DHS in exchange for 2.4 million shares of DHS common stock. Two executive officers purchased 150,000 shares each by execution and delivery of promissory notes for $549,000. An officer of DHS paid $33,000 for 9,000 shares of DHS common stock. Subsequent to these transactions there were 14.6 million shares of DHS common stock outstanding.
During the fourth quarter 2007, the Company acquired an additional interest for $354,000 from one of the DHS founding officers, increasing the Company’s total ownership interest to 50.0% as of December 31, 2007.
On March 5, 2007, DHS purchased a drilling rig (“Rig 18”) for cash consideration of $7.6 million, funded with borrowings under the DHS credit facility. The rig is a 700 horsepower rig with a depth rating of 10,500 feet. The rig is currently operating in the Rocky Mountain Region.
In March 2006, DHS purchased a Kremco 750G drilling rig (“Rig 16”) for $4.75 million. The rig is a 500 horsepower rig with a depth rating of 10,000 feet. The rig commenced work in the Rocky Mountain Region in June 2006.
F-24
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(4) DHS Drilling Company , Continued
In May 2006, DHS acquired two rigs (“Rig 12” and “Rig 14”) and certain other assets in conjunction with the acquisition of C&L Drilling for a purchase price of approximately $16.7 million. Rigs 12 and 14 have depth ratings of 15,000 and 12,500 feet, respectively. The rigs are currently under contract to third party operators and working in California and Utah.
On July 18, 2006, DHS purchased a National 55 drilling rig (“Rig 17”) for $7.25 million. The rig is a 1,000 horsepower rig with a depth rating of 12,500 feet. The rig was placed into service during the fourth quarter 2006 and is working in Fremont County, Wyoming.
In December 2007, DHS sold Rigs 2 and 3 for proceeds of $6.3 million and a net loss of $31,000. The proceeds from the rigs sold were used to pay-off the JP Morgan credit facility balance in conjunction with the new Lehman facility. (See Footnote 5, “Long Term Debt”).
(5) Long Term Debt
7% Senior Unsecured Notes, due 2015
On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate amount of $150.0 million, which pay interest semiannually on April 1 and October 1 and mature in 2015. The net proceeds were used to refinance debt outstanding under its credit facility which included the amount required to acquire the Manti properties. The notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that may limit the Company’s and its subsidiaries’ ability to, among other things, incur additional indebtedness, repurchase capital stock, pay dividends, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries. These covenants may limit the discretion of the Company’s management in operating the Company’s business. The Company was not in default (as defined in the indenture) under the indenture as of December 31, 2007. (See Footnote 12, “Guarantor Financial Information”). The fair value of the Company’s senior notes at December 31, 2007 was $134.6 million.
33/4% Senior Convertible Notes, due 2037
On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 33/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes bear interest at a rate of 33/4% per annum, payable semi-annually in arrears, on May 1 and November 1 of each year, beginning November 1, 2007. The Notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The Notes will be convertible at the holder’s option, in whole or in part, at an initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, the Company will have the option to deliver shares of common stock, cash or a combination of cash and shares of common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, the Company will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require the Company to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause its wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue its corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws. The fair value of the Notes at December 31, 2007 was approximately $110.7 million.
F-25
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(5) Long Term Debt, Continued
Credit Facility
During the year ended December 31, 2007, the Company’s borrowing base under its $250.0 million credit facility was $140.0 million. At December 31, 2007, the Company had $73.6 million outstanding under the facility. Borrowing availability under this credit facility at December 31, 2007 was approximately $49.9 million after reduction for the outstanding balance and $16.5 million of outstanding letters of credit. The borrowing base is redetermined semiannually and can be increased with future drilling success. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between prime + .25% and 1.00% for base rate loans and between Libor + 1.5% and 2.25% for Eurodollar loans. The LIBOR and prime rates at December 31, 2007 approximated 6.35% and 7.25%, respectively. The loan is collateralized by substantially all of the Company’s oil and gas properties. The Company is required to meet certain financial covenants for the quarter ended December 31, 2007 which include a current ratio of 1 to 1, net of derivative instruments and deferred taxes, as defined, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 4.0 to 1 for the quarter ended December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. The financial covenants only include subsidiaries which the Company owns 100%. At December 31, 2007, the Company was in compliance with its quarterly debt covenants and restrictions under the facility. The facility matures on December 31, 2010. Subsequent to year-end, the Company paid down its borrowing base in full with proceeds from an equity offering completed in February (See Footnote 18 “Subsequent Events”).
Unsecured Term Loan
In December 2006 the Company entered into an agreement with JP Morgan Chase Bank N.A., for a $25.0 million unsecured term loan with interest at LIBOR plus a margin of 3.5% at December 31, 2006. The note was paid in full in January 2007 with the proceeds from an equity offering.
Credit Facility — DHS
On December 20, 2007, DHS entered into a new $75.0 million credit agreement with Lehman Commercial Paper Inc. The proceeds were used to pay off the JP Morgan credit facility discussed below. The Lehman credit facility has a variable interest rate based on 90-day LIBOR plus a fixed margin of 5.50% which approximated 10.43% as of December 31, 2007. The note matures on December 31, 2010. Annual principal payments are based upon a calculation of excess cash flow (as defined) for the preceding year. DHS is required to meet certain financial covenants quarterly beginning March 31, 2008 including (i) consolidated EBITDA for four consecutive fiscal quarters must be greater than $20.0 million; (ii) Consolidated Leverage Ratio (as defined) for four consecutive fiscal quarters cannot exceed 3.50 to 1.00; (iii) Consolidated Interest Coverage Ratio (as defined) for four consecutive fiscal quarters must exceed 2.50 to 1.00 and (iv) the Current Ratio for any fiscal quarter must be greater than 1.0 to 1.0. DHS incurred $1.3 million of financing charges in conjunction with the agreement which will be amortized over the life of the loan.
On May 4, 2006, DHS entered a $100.0 million senior secured credit facility with JP Morgan Chase Bank, N.A. Proceeds from the $75.0 million initial draw were used to pay off the Guggenheim term loan, complete the acquisition of C&L Drilling, finance additional capital expenditures and pay transaction expenses. In December 2007, DHS used proceeds from the Lehman credit agreement and the sale of Rigs 2 and 3 to pay off the $79.7 million outstanding balance of the JP Morgan senior secured credit facility.
F-26
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(5) Long Term Debt, Continued
Term Loan — DHS
On May 4, 2006, DHS used proceeds from the JP Morgan credit facility to pay off the remaining balance of the previously outstanding term loan of approximately $41.0 million and prepayment penalties of approximately $820,000. In addition, $431,000 of unamortized deferred financing costs associated with the repaid term loan were written-off during the quarter ended June 30, 2006. Borrowing availability at December 31, 2007 was zero under the DHS facility.
Maturities
Maturities of long-term debt, in thousands of dollars based on contractual terms, are as follows:
YEAR ENDING December 31, | ||||
2008 | $ | 13 | ||
2009 | — | |||
2010 | 148,600 | |||
2011 | — | |||
2012 | — | |||
Thereafter | 265,000 | |||
$ | 413,613 | |||
(6) Stockholders’ Equity
Preferred Stock
The Company has 3,000,000 shares of preferred stock authorized, par value $.10 per share, issuable from time to time in one or more series. As of December 31, 2007 and 2006, no preferred stock was issued. As part of the reincorporation on January 31, 2006, the Company reduced the par value of the preferred stock to $.01 per share.
Common Stock
During the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005, the Company acquired oil and gas properties for 1,229,000 shares, 673,000 shares, 50,000 shares, and 1,571,000 shares of the Company’s common stock, respectively. The shares were valued at $23.7 million, $16.1 million, $799,000, and $22.2 million, respectively, based on the market price of the shares at the time of issuance.
On June 8, 2007, the Company issued 475,000 shares of common stock valued at approximately $9.9 million to acquire an additional interest in one well already owned and operated by the Company, and an additional interest in a non-operated property, both located in Polk County, Texas.
On April 25, 2007, the Company received net proceeds of $140.3 million from a public offering of 7,130,000 shares of the Company’s common stock.
On March 9, 2007, the Company issued 754,000 shares of common stock valued at approximately $13.8 million to acquire additional interests in two wells already owned and operated by the Company located in Polk County, Texas.
On February 9, 2007, the Company issued 1.5 million non-vested shares as executive performance share grants to the Company’s four executive officers that provide that the shares of common stock awarded will vest if the market price of Delta stock reaches and maintains certain price levels (See Footnote 2, “Summary of Significant Accounting Policies”).
F-27
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(6) Stockholders’ Equity, Continued
On January 25, 2007, the Company received net proceeds of $56.4 million from a public offering of 2,768,000 shares of the Company’s common stock.
On October 2, 2006, the Company granted 334,500 shares of restricted common stock to certain non-executive employees. These shares will vest over a three year service period.
On April 28, 2006, Castle shareholders approved the merger agreement between Delta and Castle as announced on November 8, 2005. Delta, via its merger subsidiary DPCA, acquired Castle which held 6,700,000 shares of Delta, and issued 8,500,000 shares of its common stock to Castle’s stockholders, for a net issuance of 1,800,000 shares of common stock. The shares of the Company’s common stock were valued at $31.2 million using the average five-day closing price before and after the terms of the agreement were agreed upon and announced.
On February 1, 2006, the Company acquired a 65% working interest in approximately 88,000 gross acres in the central Utah hingeline play from Armstrong Resources, LLC for 673,401 shares and $24.0 million in cash. The shares of the Company’s common stock were valued at $16.1 million using the average five-day closing price before and after the terms of the agreement were agreed upon and announced. The total purchase price of $40.1 million was allocated to unproved undeveloped properties.
On February 1, 2006, the Company received net proceeds of $33.9 million from a public offering of 1.5 million shares of the Company’s common stock.
In January 2006, the Company purchased Rooster Drilling for 350,000 shares of Delta common stock valued at $8.3 million based on the value of the stock when the transaction closed (See Footnote 4 “DHS Drilling Company”).
On September 27, 2005, the Company sold 5,405,418 shares of common stock to twenty-seven institutional investors at a price of $18.50 per share in cash for gross proceeds of $100.0 million and net proceeds of approximately $95.0 million. The proceeds were used to finance the Savant acquisition discussed above and to fund drilling activities.
During fiscal 2005, the Company acquired drilling equipment for 131,000 shares of the Company’s common stock valued at $1.9 million.
Non-Qualified Stock Options — Directors and Employees
On December 14, 2004, the stockholders ratified the Company’s 2004 Incentive Plan (the “2004 Plan”) under which it reserved up to an additional 1,650,000 shares of common stock for issuance. Although grants of shares of common stock were made under the 2004 Plan during the 2006 fiscal year, no stock options were issued by the Company during that period.
On January 29, 2007, the stockholders ratified the Company’s 2007 Performance and Equity Incentive Plan (the “2007 Plan”). Subject to adjustment as provided in the 2007 Plan, the number of shares of Common Stock that may be issued or transferred, plus the amount of shares of Common Stock covered by outstanding awards granted under the 2007 Plan, may not in the aggregate exceed 2,800,000. The 2007 Plan supplements the Company’s 1993, 2001 and 2004 Incentive Plans. The purpose of the 2007 Plan is to provide incentives to selected employees and directors of the Company and its subsidiaries, and selected non-employee consultants and advisors to the Company and its subsidiaries, who contribute and are expected to contribute to the Company’s success and to create stockholder value.
Incentive awards under the 2007 Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date under the Company’s various incentive plans have been non-qualified stock options as defined in such plans.
F-28
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(6) Stockholders’ Equity, Continued
A summary of the stock option activity under the Company’s various plans and related information for the year ended December 31, 2007 follows:
Year Ended | ||||||||||||||||
December 31, 2007 | ||||||||||||||||
Weighted-Average | Weighted-Average | Aggregate | ||||||||||||||
Exercise | Remaining Contractual | Intrinsic | ||||||||||||||
Options | Price | Term | Value | |||||||||||||
Outstanding-beginning of year | 2,359,776 | $ | 7.85 | |||||||||||||
Granted | — | — | ||||||||||||||
Exercised | (202,510 | ) | (4.86 | ) | ||||||||||||
Expired / Returned | — | — | ||||||||||||||
Outstanding-end of year | 2,157,266 | $ | 9.04 | 4.18 | $ | 21,153,000 | ||||||||||
Exercisable-end of year | 2,157,266 | $ | 9.04 | 4.18 | $ | 21,153,000 | ||||||||||
The total intrinsic value of options exercised during the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the year ended June 30, 2005 were $2.8 million, $12.3 million, $3.2 million, and $24.9 million, respectively.
A summary of the Company’s non-vested stock options and related information for the year ended December 31, 2007 follows:
Year Ended | ||||||||
December 31, 2007 | ||||||||
Weighted-Average | ||||||||
Grant-Date | ||||||||
Options | Fair Value | |||||||
Nonvested-beginning of year | 166,667 | $ | 7.67 | |||||
Granted | — | — | ||||||
Vested | (166,667 | ) | (7.67 | ) | ||||
Forfeited / Returned | — | — | ||||||
Nonvested-end of year | — | $ | — | |||||
The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the year ended June 30, 2005, risk-free interest rate of 4.28%, dividend yield of 0%, volatility factor of the expected market price of the Company’s common stock of 43.97%, and a weighted-average expected life of the options of 4.76 years. The fair value of the options granted at the grant date was $8.0 million for the year ended June 30, 2005. No options were granted during the years ended December 31, 2007 and 2006 or six months ended December 31, 2005.
A summary of the restricted stock (nonvested stock) activity under the Company’s plan and related information for the year ended December 31, 2007 follows:
Year Ended | ||||||||||||||||
December 31, 2007 | ||||||||||||||||
Weighted-Average | Weighted-Average | Aggregate | ||||||||||||||
Nonvested | Grant-Date | Remaining Contractual | Intrinsic | |||||||||||||
Stock | Fair Value | Term | Value | |||||||||||||
Nonvested-beginning of year | 627,500 | $ | 20.78 | |||||||||||||
Granted | 1,780,787 | 21.56 | ||||||||||||||
Vested | (266,493 | ) | (20.76 | ) | ||||||||||||
Expired / Returned | (27,173 | ) | (18.32 | ) | ||||||||||||
Nonvested-end of year | 2,114,621 | $ | 21.47 | 6.90 | $ | 39,861,000 | ||||||||||
F-29
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(6) Stockholders’ Equity, Continued
Restricted Stock — Directors and Employees
The total fair value of restricted stock vested during the years ended December 31, 2007 and 2006, and the six months ended December 31, 2005 was $5.2 million, $2.4 million and $697,000, respectively.
At December 31, 2007, 2006 and 2005, the total unrecognized compensation cost related to the non-vested portion of restricted stock and stock options was $20.8 million, $11.4 million and $5.8 million which is expected to be recognized over a weighted average period of 6.90, 2.08 and 4.75 years, respectively.
Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005, was $686,000, $3.6 million, $625,000, and $132,000, respectively. Tax benefits realized from the stock options exercised during the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005, was zero, zero, zero, and $1.3 million, respectively. During the years ended December 31, 2007 and 2006 and six months ended December 31, 2005, $8.0 million, $4.6 million and $6.6 million, respectively, of tax benefits were generated from the exercise of stock options; however, such benefit will not be recognized in stockholders’ equity until the period that these amounts decrease taxes payable.
(7) Employee Benefits
The Company adopted a profit sharing plan on January 1, 2002. All employees are eligible to participate and contributions to the profit sharing plan are voluntary and must be approved by the Board of Directors. Amounts contributed to the Plan vest over a six year service period.
For the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005, the Company contributed $632,000, $528,000, $240,000, and $291,000, respectively, under its profit sharing plan.
The Company adopted a 401(k) plan effective May 1, 2005. All employees are eligible to participate and make employee contributions once they have met the plan’s eligibility criteria. Under the 401(k) plan, the Company’s employees make salary reduction contributions in accordance with the Internal Revenue Service guidelines. The Company’s matching contribution is an amount equal to 100% of the employee’s elective deferral contribution which cannot exceed 3% of the employee’s compensation, and 50% of the employee’s elective deferral which exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation.
(8) Commodity Derivative Instruments and Hedging Activities
The Company periodically enters into commodity price risk transactions to manage its exposure to oil and gas price volatility. These transactions may take the form of futures contracts, collar agreements, swaps or options. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. All transactions are accounted for in accordance with requirements of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Effective July 1, 2007, the Company elected to discontinue cash flow hedge accounting on a prospective basis. Beginning July 1, 2007, the Company recognizes mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. As a result of the Company’s election to discontinue hedge accounting, the amount recorded in accumulated other comprehensive income for hedges that were effective as of June 30, 2007 was fixed until the period those derivatives were settled, with all subsequent changes in fair value recorded in gain (loss) from ineffective derivative contracts. All amounts in accumulated other comprehensive income as of June 30, 2007 were reclassified to gain (loss) on effective derivative contracts as of December 31, 2007, as all such derivatives had settled.
F-30
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(8) Commodity Derivative Instruments and Hedging Activities, Continued
At December 31, 2007, the Company’s outstanding derivative contracts were collars. Under a collar agreement the Company receives the difference between the floor price and the index price only when the index price is below the floor price, and the Company pays the difference between the ceiling price and the index price only when the index price is above the ceiling price. The Company’s collars are settled in cash on a monthly basis. By entering into collars, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the collar also establishes a maximum price that the Company will receive for the hedged production when prices increase above the ceiling price. The Company enters into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for foregoing the benefit of price increases in excess of the ceiling price on the hedged production.
The following table summarizes our derivative contracts outstanding at December 31, 2007:
Net Fair Value | ||||||||||||||||||||||||||||
Price Floor/ | Asset (Liability) at | |||||||||||||||||||||||||||
Commodity | Volume | Price Ceiling | Term | Index | December 31, 2007 | |||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Crude oil | 1,200 | Bbls / day | $ | 65.00 / | $ | 80.03 | Jan ’08 - Mar ’08 | NYMEX – WTI | $ | (1,705 | ) | |||||||||||||||||
Crude oil | 1,200 | Bbls / day | $ | 65.00 / | $ | 79.77 | Apr ’08 - June ’08 | NYMEX – WTI | (1,620 | ) | ||||||||||||||||||
Crude oil | 1,200 | Bbls / day | $ | 65.00 / | $ | 79.86 | July ’08 - Sept ’08 | NYMEX – WTI | (1,522 | ) | ||||||||||||||||||
Crude oil | 1,200 | Bbls / day | $ | 65.00 / | $ | 79.83 | Oct ’08 - Dec ’08 | NYMEX – WTI | (1,448 | ) | ||||||||||||||||||
Natural gas | 15,000 | mMBtu / day | $ | 6.50 / | $ | 8.30 | Jan ’08 - Dec ’08 | CIG | 2,404 | |||||||||||||||||||
Natural gas | 5,000 | mMBtu / day | $ | 6.50 / | $ | 8.40 | Jan ’08 - Mar ’08 | CIG | 211 | |||||||||||||||||||
Natural gas | 10,000 | mMBtu / day | $ | 6.00 / | $ | 7.25 | Apr ’08 - Sept ’08 | CIG | 139 | |||||||||||||||||||
Natural gas | 10,000 | mMBtu / day | $ | 6.50 / | $ | 7.90 | Oct ’08 - Dec ’08 | CIG | 176 | |||||||||||||||||||
$ | (3,365 | ) | ||||||||||||||||||||||||||
The fair value of the Company’s derivative instruments liability was $3.4 million at December 31, 2007. Subsequent to year-end, the Company entered into new CIG gas hedges for 10,000 Mmbtu per day for the second and third quarters of 2008 with a floor price of $6.50 and ceiling prices of $7.70 and $8.15 per Mmbtu, respectively. The Company also entered into new CIG gas hedges for 35,000 Mmbtu per day for the first quarter of 2009 with a floor price of $7.50 per Mmbtu and a ceiling price of $9.88 per Mmbtu. The fair value of the derivative liability at February 26, 2008 was $15.2 million.
The net gains (losses) from effective hedging activities recognized in the Company’s statements of operations were $12.9 million, ($4.7 million), ($3.4 million), and ($630,000), for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005, respectively. These gains (losses) are recorded as an increase or decrease in revenues.
F-31
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(9) Income Taxes
The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). Income tax expense (benefit) attributable to income from continuing operations consisted of the following for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005:
Six Months Ended | Year Ended | |||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands) | ||||||||||||||||
CURRENT: | ||||||||||||||||
U.S. — Federal | $ | 47 | $ | 192 | $ | — | $ | — | ||||||||
U.S. — State | (5 | ) | — | — | — | |||||||||||
Foreign | — | — | — | — | ||||||||||||
DEFERRED: | ||||||||||||||||
U.S. — Federal | 2,452 | (11,052 | ) | (9,458 | ) | (10,898 | ) | |||||||||
U.S. — State | 183 | (1,763 | ) | (1,415 | ) | (1,071 | ) | |||||||||
Foreign | — | — | — | — | ||||||||||||
$ | 2,677 | $ | (12,623 | ) | $ | (10,873 | ) | $ | (11,969 | ) | ||||||
Income from continuing operations before taxes consists of the following for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the fiscal year ended June 30, 2005:
U.S. | $ | (160,228 | ) | $ | (33,623 | ) | $ | (29,203 | ) | $ | (10,353 | ) | ||||
Foreign | — | — | — | — | ||||||||||||
Income (loss) from continuing operations before taxes | $ | (160,228 | ) | $ | (33,623 | ) | $ | (29,203 | ) | $ | (10,353 | ) | ||||
Income tax expense attributable to income from continuing operations was different from the amounts computed by applying U.S. Federal income tax rate of 35% to pretax income from continuing operations as a result of the following:
Six Months Ended | Year Ended | |||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
Federal statutory rate | (35.0) | % | (35.0) | % | (35.0) | % | 35.0 | % | ||||||||
State income taxes, net of federal benefit | (2.1 | ) | (2.7 | ) | (3.1 | ) | 3.4 | |||||||||
Investment in DHS | — | — | (5.8 | ) | 3.5 | |||||||||||
Change in valuation allowance | 40.6 | — | 1.0 | (69.6 | ) | |||||||||||
Other | (1.8 | ) | 0.2 | 5.7 | (1.8 | ) | ||||||||||
Actual income tax rate | 1.7 | % | (37.5) | % | (37.2) | % | (29.5) | % | ||||||||
F-32
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(9) Income Taxes, Continued
Included in the consolidated statement of operations as a component of discontinued operations for the year ended December 31, 2006 is a $5.0 million deferred tax provision on the sale and operations of properties that were sold during the period. Also included in the consolidated statement of operations as a component of extraordinary gain for the year ended December 31, 2006 is a $3.2 million deferred tax provision on the sale of properties acquired in the Castle acquisition.
Deferred tax assets (liabilities) are comprised of the following at December 31, 2007, December 31, 2006, December 31, 2005, and June 30, 2005:
Six Months Ended | Year Ended | |||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands) | ||||||||||||||||
Current deferred tax asset (liability) | ||||||||||||||||
Derivative instruments | $ | 1,249 | $ | (3,844 | ) | $ | 4,665 | $ | 2,638 | |||||||
Accrued bonuses | 1,737 | 1,138 | 452 | — | ||||||||||||
Allowance for doubtful accounts | 236 | 38 | 38 | 38 | ||||||||||||
Accrued vacation liability | 212 | 140 | 82 | — | ||||||||||||
Prepaid insurance and other | (394 | ) | (365 | ) | — | — | ||||||||||
Total current deferred tax assets | 3,040 | (2,893 | ) | 5,237 | 2,676 | |||||||||||
Less valuation allowance | (2,890 | ) | — | — | — | |||||||||||
Net current deferred tax asset (liability) | $ | 150 | $ | (2,893 | ) | $ | 5,237 | $ | 2,676 | |||||||
Long-term deferred tax asset (liability): | ||||||||||||||||
Deferred tax assets: | ||||||||||||||||
Net operating loss1 | $ | 56,649 | $ | 15,306 | $ | 16,074 | $ | 14,544 | ||||||||
Asset retirement obligation | 1,976 | 1,754 | 1,306 | 1,419 | ||||||||||||
Derivative instruments | — | — | 2,204 | 1,211 | ||||||||||||
Percentage depletion | 596 | 531 | 530 | 541 | ||||||||||||
Drilling equipment | — | — | 792 | 403 | ||||||||||||
Equity compensation | 4,807 | 2,142 | 942 | — | ||||||||||||
Minimum tax credit | 1,221 | 1,368 | — | — | ||||||||||||
Other | 153 | 558 | 152 | 66 | ||||||||||||
Total long-term deferred tax assets | 65,402 | 21,659 | 22,000 | 18,184 | ||||||||||||
Valuation allowance | (55,187 | ) | (661 | ) | (712 | ) | (1,139 | ) | ||||||||
Net deferred tax asset | 10,215 | 20,998 | 21,288 | 17,045 | ||||||||||||
Deferred tax liabilities: | ||||||||||||||||
Property and equipment | (19,261 | ) | (23,081 | ) | (17,879 | ) | (11,256 | ) | ||||||||
Investment in DHS | — | — | (2,001 | ) | (399 | ) | ||||||||||
Investments — available for sale | — | — | — | (503 | ) | |||||||||||
Other | (39 | ) | (1,577 | ) | (86 | ) | — | |||||||||
Total long-term deferred tax liabilities | (19,300 | ) | (24,658 | ) | (19,966 | ) | (12,158 | ) | ||||||||
Net long-term deferred tax asset (liability) | $ | (9,085 | ) | $ | (3,660 | ) | $ | 1,322 | $ | 4,887 | ||||||
Total deferred tax assets before valuation allowance | $ | 68,836 | $ | 22,975 | $ | 27,237 | $ | 20,860 | ||||||||
Total deferred tax liabilities | $ | 19,694 | $ | 28,867 | $ | 19,966 | $ | 12,158 | ||||||||
1 | Included in net operating loss carryforwards is $1.25 million at June 30, 2005 that related to the tax effect of stock options exercised and restricted stock for which the benefit was recognized in stockholders’ equity rather than in operations in accordance with FAS 109. Not included in the deferred tax asset for net operating loss at December 31, 2007 and 2006 is approximately $7.9 million and $11.4 million, respectively, that relates to the tax effect of stock options exercised for which the benefit will not be recognized in stockholders’ equity until the period that these amounts decrease taxes payable. The related $38.1 million tax deduction is included in the table of net operating losses shown below. |
F-33
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(9) Income Taxes, Continued
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the year ended December 31, 2007, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management concluded during the second quarter of 2007 and continues to conclude that the Company does not meet the “more likely than not” requirement of SFAS 109 in order to recognize deferred tax assets. Accordingly, for the year ended December 31, 2007, the Company recorded in income tax expense an increase to the valuation allowance of $57.4 million offsetting the Company’s deferred tax assets.
At December 31, 2007, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes as follows:
Regular tax net operating loss | $ | 191,918 | ||
Alternative minimum tax net operating loss | 176,617 |
If not utilized, the tax net operating loss carryforwards will expire from 2008 through 2027.
The Company’s net operating losses are scheduled to expire as follows (in thousands):
2008 | $ | 720 | ||
2009 | 3,914 | |||
2010 | 6,004 | |||
2011 | 5,939 | |||
2012 | 994 | |||
2013 and thereafter | 174,347 | |||
$ | 191,918 | |||
In August 2007, the Company experienced cumulative ownership changes as defined by the Internal Revenue Code (“IRC”) 382 and as a result, a portion of the Company’s net operating loss utilization after the change date will be subject to IRC 382 limitations of approximately $45.0 million for federal income taxes.
(10) Related Party Transactions
Transactions with Directors and Officers
On September 29, 2005 we acquired an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington and purchased an interest in undeveloped acreage in the Piceance Basin in Colorado from Savant Resources, LLC (“Savant”) for an aggregate purchase price of $85.0 million in cash. At the time of the transaction, James Wallace, one of our directors, owned approximately a 1.7% interest in and served as a director of Savant. The majority of the acquired acreage in the Columbia River Basin consolidates our current leasehold position.
During the quarter ended September 30, 2005, DHS borrowed $8.0 million from Chesapeake, a related party who owns approximately a 45% interest in DHS. The loan was subsequently paid in full.
During fiscal 2001 and 2000, Mr. Larson and Mr. Parker guaranteed certain borrowings which have subsequently been paid in full. As consideration for the guarantee of the Company’s indebtedness, each officer was assigned a 1% overriding royalty interest (“ORRI”) in the properties acquired with the proceeds of the borrowings. Each of Mr. Larson and Mr. Parker earned approximately $110,000, $142,000, $58,000, and $100,000, for their respective 1% ORRI during the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005, respectively.
F-34
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(10) Related Party Transactions, Continued
As of December 31, 2007, the Company’s executive officers had employment agreements which, among other things, include clauses that provide for the payment of certain amounts to the executives upon termination of employment and for the continuation of group medical benefits after such termination.
Accounts Receivable Related Parties
At December 31, 2007 and 2006, the Company had $276,000 and $30,000 of receivables from related parties, respectively. These amounts include drilling costs and lease operating expense on wells owned by the related parties and operated by the Company.
(11) Earnings Per Share
The following table sets forth the computation of basic and diluted earnings per share:
Years Ended | Six Months Ended | Year Ended | ||||||||||||||
December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Net income (loss) | $ | (149,347 | ) | $ | 435 | $ | (590 | ) | $ | 15,050 | ||||||
Basic weighted-average shares outstanding | 61,297 | 51,702 | 44,959 | 40,327 | ||||||||||||
Add: dilutive effects of stock options and unrestricted stock grants | — | 1,611 | — | 1,693 | ||||||||||||
Add: dilutive effect of 33/4% Convertible Notes using the if-converted method | — | — | — | — | ||||||||||||
Diluted weighted-average common shares outstanding | 61,297 | 53,313 | 44,959 | 42,020 | ||||||||||||
Basic net income (loss) per common share | $ | (2.44 | ) | $ | .01 | $ | (.01 | ) | $ | .37 | ||||||
Diluted net income (loss) per common share1 | $ | (2.44 | ) | $ | .01 | $ | (.01 | ) | $ | .36 | ||||||
1 | The denominator for diluted net income (loss) per common share for the year ended December 31, 2007 and the six months ended December 31, 2005 excludes 7,951,000 and 3,231,000, respectively, of potentially dilutive shares because such shares were anti-dilutive. |
F-35
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(12) Guarantor Financial Information
On March 15, 2005 Delta issued 7% Senior Notes (“Senior Notes”) that mature in 2015 for an aggregate amount of $150.0 million and on which interest is paid semiannually on April 1st and October 1st. The net proceeds from the Senior Notes were used to refinance debt outstanding under the Company’s credit facility. In addition, on April 25, 2007 the Company issued 33/4% Convertible Senior Notes due in 2037 (“Convertible Notes”) for aggregate proceeds of $111.6 million and on which interest is paid semiannually on May 1 and November 1. The proceeds of the Convertible Notes were used for capital expenditures. Both the Senior Notes and the Convertible Notes are guaranteed by Piper Petroleum Company and all of the Company’s other wholly-owned subsidiaries (“Guarantors”). Each of the Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantees the performance and payment when due of all the obligations under the Senior Notes and the Convertible Notes. DHS, CRBP, PGR, and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Senior Notes or the Convertible Notes.
The following financial information sets forth the Company’s condensed consolidated balance sheets as of December 31, 2007 and 2006, the condensed consolidated statements of operations for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the year ended June 30, 2005, and the condensed consolidated statements of cash flows for the years ended December 31, 2007 and 2006, six months ended December 31, 2005, and year ended June 30, 2005 (in thousands):
Condensed Consolidated Balance Sheet
December 31, 2007
December 31, 2007
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Current assets | $ | 98,918 | $ | 898 | $ | 33,253 | $ | — | $ | 133,069 | ||||||||||
Property and equipment: | ||||||||||||||||||||
Oil and gas | 918,247 | 487 | 80,784 | (11,644 | ) | 987,874 | ||||||||||||||
Drilling rigs and trucks | 595 | — | 145,502 | — | 146,097 | |||||||||||||||
Other | 35,444 | 4,316 | 1,449 | — | 41,209 | |||||||||||||||
Total property and equipment | 954,286 | 4,803 | 227,735 | (11,644 | ) | 1,175,180 | ||||||||||||||
Accumulated DD&A | (203,091 | ) | (125 | ) | (41,937 | ) | — | (245,153 | ) | |||||||||||
Net property and equipment | 751,195 | 4,678 | 185,798 | (11,644 | ) | 930,027 | ||||||||||||||
Investment in subsidiaries | 87,961 | — | — | (87,961 | ) | — | ||||||||||||||
Other long-term assets | 29,786 | 3,800 | 8,513 | — | 42,099 | |||||||||||||||
Total assets | $ | 967,860 | $ | 9,376 | $ | 227,564 | $ | (99,605 | ) | $ | 1,105,195 | |||||||||
Current liabilities | $ | 135,997 | $ | 188 | $ | 7,011 | $ | — | $ | 143,196 | ||||||||||
Long-term liabilities | ||||||||||||||||||||
Long-term debt and deferred taxes | 336,409 | 1,800 | 83,935 | — | 422,144 | |||||||||||||||
Asset retirement obligation | 3,976 | 9 | 169 | — | 4,154 | |||||||||||||||
Total long-term liabilities | 340,385 | 1,809 | 84,104 | — | 426,298 | |||||||||||||||
Minority interest | 27,296 | — | — | — | 27,296 | |||||||||||||||
Stockholders’ equity | 464,182 | 7,379 | 136,449 | (99,605 | ) | 508,405 | ||||||||||||||
Total liabilities and stockholders’ equity | $ | 967,860 | $ | 9,376 | $ | 227,564 | $ | (99,605 | ) | $ | 1,105,195 | |||||||||
F-36
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Operations
Year Ended December 31, 2007
Year Ended December 31, 2007
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Total revenue | $ | 102,735 | $ | 577 | $ | 95,288 | $ | (34,410 | ) | $ | 164,190 | |||||||||
Operating expenses: | ||||||||||||||||||||
Lease operating expense | 28,207 | 118 | 1,060 | — | 29,385 | |||||||||||||||
Depreciation and depletion | 59,461 | 11 | 25,953 | — | 85,425 | |||||||||||||||
Exploration expense | 9,062 | — | — | — | 9,062 | |||||||||||||||
Drilling and trucking operations | — | — | 59,720 | (22,766 | ) | 36,954 | ||||||||||||||
Dry hole, abandonment and impaired | 85,084 | — | — | — | 85,084 | |||||||||||||||
General and administrative | 44,543 | (1 | ) | 5,079 | — | 49,621 | ||||||||||||||
Total expenses | 226,357 | 128 | 91,812 | (22,766 | ) | 295,531 | ||||||||||||||
Operating income (loss) | (123,622 | ) | 449 | 3,476 | (11,644 | ) | (131,341 | ) | ||||||||||||
Other income and expenses | (21,500 | ) | 88 | (8,705 | ) | 1,230 | (28,887 | ) | ||||||||||||
Income tax (expense) benefit | (4,486 | ) | — | 1,809 | — | (2,677 | ) | |||||||||||||
Discontinued operations | 13,558 | — | — | — | 13,558 | |||||||||||||||
Net income (loss) | $ | (136,050 | ) | $ | 537 | $ | (3,420 | ) | $ | (10,414 | ) | $ | (149,347 | ) | ||||||
Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2007
Year Ended December 31, 2007
Guarantor | Non-Guarantor | |||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
Operating activities | $ | 67,669 | $ | 208 | $ | 16,515 | $ | 84,392 | ||||||||
Investing activities | (284,900 | ) | (1,538 | ) | (38,586 | ) | (325,024 | ) | ||||||||
Financing activities | 219,904 | — | 23,153 | 243,057 | ||||||||||||
Net increase (decrease) in cash and cash equivalents | 2,673 | (1,330 | ) | 1,082 | 2,425 | |||||||||||
Cash at beginning of the period | 2,282 | 1,637 | 3,747 | 7,666 | ||||||||||||
Cash at the end of the period | $ | 4,955 | $ | 307 | $ | 4,829 | $ | 10,091 | ||||||||
F -37
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(12) Guarantor Financial Information, Continued
Condensed Consolidated Balance Sheet
December 31, 2006
December 31, 2006
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Current assets | $ | 61,946 | $ | 2,447 | $ | 25,401 | $ | — | $ | 89,794 | ||||||||||
Property and equipment: | ||||||||||||||||||||
Oil and gas | 735,412 | 444 | 58,078 | (12,119 | ) | 781,815 | ||||||||||||||
Drilling rigs and trucks | 595 | — | 135,443 | — | 136,038 | |||||||||||||||
Other | 23,435 | 4,320 | 1,137 | — | 28,892 | |||||||||||||||
Total property and equipment | 759,442 | 4,764 | 194,658 | (12,119 | ) | 946,745 | ||||||||||||||
Accumulated DD&A | (111,422 | ) | (119 | ) | (20,004 | ) | — | (131,545 | ) | |||||||||||
Net property and equipment | 648,020 | 4,645 | 174,654 | (12,119 | ) | 815,200 | ||||||||||||||
Investment in subsidiaries | 66,366 | — | — | (66,366 | ) | — | ||||||||||||||
Other long-term assets | 11,423 | 3,521 | 9,385 | — | 24,329 | |||||||||||||||
Total assets | $ | 787,755 | $ | 10,613 | $ | 209,440 | $ | (78,485 | ) | $ | 929,323 | |||||||||
Current liabilities | $ | 88,344 | $ | 1,200 | $ | 10,035 | $ | — | $ | 99,579 | ||||||||||
Long-term liabilities | ||||||||||||||||||||
Long-term debt and deferred taxes | 283,709 | 1,600 | 84,799 | — | 370,108 | |||||||||||||||
Asset retirement obligation | 3,921 | 9 | 83 | — | 4,013 | |||||||||||||||
Total long-term liabilities | 287,630 | 1,609 | 84,882 | — | 374,121 | |||||||||||||||
Minority interest | 27,390 | — | — | — | 27,390 | |||||||||||||||
Stockholders’ equity | 384,391 | 7,804 | 114,523 | (78,485 | ) | 428,233 | ||||||||||||||
Total liabilities and stockholders’ equity | $ | 787,755 | $ | 10,613 | $ | 209,440 | $ | (78,485 | ) | $ | 929,323 | |||||||||
Condensed Consolidated Statement of Operations
Year Ended December 31, 2006
Year Ended December 31, 2006
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Total revenue | $ | 85,025 | $ | 1,362 | $ | 85,306 | $ | (25,033 | ) | $ | 146,660 | |||||||||
Operating expenses: | ||||||||||||||||||||
Lease operating expense | 22,553 | 471 | 393 | — | 23,417 | |||||||||||||||
Depreciation and depletion | 52,742 | 112 | 17,530 | — | 70,384 | |||||||||||||||
Exploration expense | 4,687 | — | 3 | — | 4,690 | |||||||||||||||
Drilling and trucking operations | — | — | 47,077 | (12,914 | ) | 34,163 | ||||||||||||||
Dry hole, abandonment and impaired | 15,682 | — | — | — | 15,682 | |||||||||||||||
General and administrative | 32,266 | 86 | 3,344 | — | 35,696 | |||||||||||||||
Gain on sale of oil and gas properties | (20,034 | ) | — | — | — | (20,034 | ) | |||||||||||||
Total expenses | 107,896 | 669 | 68,347 | (12,914 | ) | 163,998 | ||||||||||||||
Income (loss) from continuing operations | (22,871 | ) | 693 | 16,959 | (12,119 | ) | (17,338 | ) | ||||||||||||
Other income and expenses | (6,402 | ) | (23 | ) | (7,264 | ) | (2,596 | ) | (16,285 | ) | ||||||||||
Income tax benefit | 15,687 | — | (3,064 | ) | — | 12,623 | ||||||||||||||
Discontinued operations | 15,875 | — | — | — | 15,875 | |||||||||||||||
Extraordinary gain | — | 5,560 | — | — | 5,560 | |||||||||||||||
Net income (loss) | $ | 2,289 | $ | 6,230 | $ | 6,631 | $ | (14,715 | ) | $ | 435 | |||||||||
F-38
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2006
Year Ended December 31, 2006
Guarantor | Non-Guarantor | |||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
Operating activities | $ | 35,617 | $ | (237 | ) | $ | 18,006 | $ | 53,386 | |||||||
Investing activities | (148,788 | ) | 20,941 | (75,238 | ) | (203,085 | ) | |||||||||
Financing activities | 113,505 | (19,283 | ) | 57,624 | 151,846 | |||||||||||
Net increase (decrease) in cash and cash equivalents | 334 | 1,421 | 392 | 2,147 | ||||||||||||
Cash at beginning of the period | 1,949 | 216 | 3,354 | 5,519 | ||||||||||||
Cash at the end of the period | $ | 2,283 | $ | 1,637 | $ | 3,746 | $ | 7,666 | ||||||||
Condensed Consolidated Statement of Operations
Six Months Ended December 31, 2005
Six Months Ended December 31, 2005
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Total revenue | $ | 37,614 | $ | 1,616 | $ | 16,316 | $ | (7,220 | ) | $ | 48,326 | |||||||||
Operating expenses: | ||||||||||||||||||||
Lease operating expense | 9,464 | 178 | — | — | 9,642 | |||||||||||||||
Depreciation and depletion | 12,254 | 158 | 2,846 | — | 15,258 | |||||||||||||||
Exploration expense | 2,058 | (1 | ) | 4 | — | 2,061 | ||||||||||||||
Drilling and trucking operations | — | — | 9,545 | (3,724 | ) | 5,821 | ||||||||||||||
Dry hole, abandonment and impaired | 5,423 | — | — | — | 5,423 | |||||||||||||||
General and administrative | 15,263 | 7 | 1,221 | — | 16,491 | |||||||||||||||
Total expenses | 44,462 | 342 | 13,616 | (3,724 | ) | 54,696 | ||||||||||||||
Income (loss) from continuing operations | (6,848 | ) | 1,274 | 2,700 | (3,496 | ) | (6,370 | ) | ||||||||||||
Other income and expenses | (21,146 | ) | 4 | (1,003 | ) | (688 | ) | (22,833 | ) | |||||||||||
Income tax benefit | 10,873 | — | — | — | 10,873 | |||||||||||||||
Discontinued operations | 17,740 | — | — | — | 17,740 | |||||||||||||||
Net income (loss) | $ | 619 | $ | 1,278 | $ | 1,697 | $ | (4,184 | ) | $ | (590 | ) | ||||||||
Condensed Consolidated Statement of Cash Flows
Six Months Ended December 31, 2005
Six Months Ended December 31, 2005
Guarantor | Non-Guarantor | |||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
Operating activities | $ | 21,477 | $ | (1,244 | ) | $ | 4,646 | $ | 24,879 | |||||||
Investing activities | (96,840 | ) | 1,472 | (51,140 | ) | (146,508 | ) | |||||||||
Financing activities | 75,314 | (209 | ) | 49,802 | 124,907 | |||||||||||
Net increase (decrease) in cash and cash equivalents | (49 | ) | 19 | 3,308 | 3,278 | |||||||||||
Cash at beginning of the period | 1,999 | 196 | 46 | 2,241 | ||||||||||||
Cash at the end of the period | $ | 1,950 | $ | 215 | $ | 3,354 | $ | 5,519 | ||||||||
F -39
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Operations
Year Ended June 30, 2005
Year Ended June 30, 2005
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Total revenue | $ | 50,159 | $ | 1,657 | $ | 7,319 | $ | (2,523 | ) | $ | 56,612 | |||||||||
Operating expenses: | ||||||||||||||||||||
Lease operating expense | 12,611 | 489 | — | — | 13,100 | |||||||||||||||
Depreciation and depletion | 13,907 | 148 | 1,525 | — | 15,580 | |||||||||||||||
Exploration expense | 6,155 | — | — | — | 6,155 | |||||||||||||||
Drilling and trucking operations | — | — | 6,799 | (2,133 | ) | 4,666 | ||||||||||||||
Dry hole, abandonment and impaired | 2,771 | — | — | — | 2,771 | |||||||||||||||
General and administrative | 15,788 | 9 | 1,133 | — | 16,930 | |||||||||||||||
Total expenses | 51,232 | 646 | 9,457 | (2,133 | ) | 59,202 | ||||||||||||||
Income (loss) from continuing operations | (1,073 | ) | 1,011 | (2,138 | ) | (390 | ) | (2,590 | ) | |||||||||||
Other income and expenses | (7,792 | ) | 31 | (2 | ) | — | (7,763 | ) | ||||||||||||
Income tax benefit | 11,969 | — | — | — | 11,969 | |||||||||||||||
Discontinued operations | 13,434 | — | — | — | 13,434 | |||||||||||||||
Net income (loss) | $ | 16,538 | $ | 1,042 | $ | (2,140 | ) | $ | (390 | ) | $ | 15,050 | ||||||||
Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2005
Year Ended June 30, 2005
Guarantor | Non-Guarantor | |||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
Operating activities | $ | 37,057 | $ | 707 | $ | 7,098 | $ | 44,862 | ||||||||
Investing activities | (158,273 | ) | (551 | ) | (25,058 | ) | (183,882 | ) | ||||||||
Financing activities | 121,262 | — | 17,921 | 139,183 | ||||||||||||
Net increase (decrease) in cash and cash equivalents | 46 | 156 | (39 | ) | 163 | |||||||||||
Cash at beginning of the period | 1,992 | 40 | 46 | 2,078 | ||||||||||||
Cash at the end of the period | $ | 2,038 | $ | 196 | $ | 7 | $ | 2,241 | ||||||||
F-40
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(13) Commitments and Contingencies
The Company leases office space in Denver, Colorado and certain other locations in North America and also leases equipment and autos under non-cancelable operating leases. Rent expense for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005, was approximately $1,150,000, $856,000, $432,000, and $491,000, respectively. The following table summarizes the future minimum payments under all non-cancelable operating lease obligations:
(In thousands) | ||||
2008 | $ | 3,527 | ||
2009 | 3,413 | |||
2010 | 1,918 | |||
2011 | 1,796 | |||
2012 | 1,201 | |||
2013 and thereafter | 2,394 | |||
$ | 14,249 | |||
On April 30, 2007, the Company entered into agreements with four executive officers which provide for severance payments, three times the calculated average of the officer’s combined annual salary and bonus, benefit continuation and accelerated vesting of options and stock grants in the event there is a change in control of the Company. These agreements replace similar agreements that expired on December 31, 2006.
Offshore Litigation
The Company and its 92% owned subsidiary, Amber, are among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of the Company’s offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 19, 2006, the government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by the Company (“Lease 452”). In its motion for reconsideration, the government has asserted that the Company should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and post-trial briefing is currently in process. The Company believes that the government’s assertion is without merit, but it cannot predict with certainty the ultimate outcome of this matter.
On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty five of the forty lawsuit leases. Under this order the Company is entitled to receive a gross amount of approximately $58.5 million and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. No payments will be made until all appeals have either been waived or exhausted. In the event that the Company ultimately receives any proceeds as the result of this litigation, it will be obligated to pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.
F -41
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(13) Commitments and Contingencies, Continued
Shareholder Derivative Suit
Within the past two years, there has been significant focus on corporate governance and accounting practices in the grant of equity based awards to executives and employees of publicly traded companies, including the use of market hindsight to select award dates to favor award recipients. After being identified in a third-party report as statistically being at risk for possibly backdating option grants, in May 2006 the Company’s Board of Directors created a special committee comprised of outside directors of the Company. The special committee, which was advised by independent legal counsel and advisors, undertook a comprehensive review of the Company’s historical stock option practices and related accounting treatment. In June 2006 the Company received a subpoena from the U.S. Attorney for the Southern District of New York and an inquiry from the staff of the SEC related to the Company’s stock option grants and related practices. The special committee of the Company’s Board of Directors reported to the Board that, while its review revealed deficiencies in the documentation of the Company’s option grants in prior years, there was no evidence of option backdating or other misconduct by the Company’s executives or directors in the timing or selection of the Company’s option grant dates, or that would cause the Company to conclude that its prior accounting for stock option grants was incorrect in any material respect. The Company provided the results of the internal investigation to the U.S. Attorney and to the SEC in August of 2006, and was subsequently informed by both agencies that the matter had been closed.
During September and October of 2006, three separate shareholder derivative actions were filed on the Company’s behalf in U.S. District Court for the District of Colorado relating to the options backdating issue, all of which were consolidated into a single action. The consolidated complaint alleged that certain of the Company’s executive officers and directors engaged in various types of misconduct in connection with certain stock option grants. Specifically, the plaintiffs alleged that the defendant directors, in their capacity as members of the Company’s Board of Directors and its Audit or Compensation Committee, at the behest of the defendants who are or were officers and to benefit themselves, backdated the Company’s stock option grants to make it appear as though they were granted on a prior date when the Company’s stock price was lower. They alleged that these backdated options unduly benefited the defendants who are or were officers and/or directors, resulted in the Company issuing materially inaccurate and misleading financial statements and caused the Company to incur substantial damages. The action also sought to have the current and former officers and directors who are defendants disgorge to the Company certain options they received, including the proceeds of options exercised, as well as certain equitable relief and attorneys’ fees and costs. On September 26, 2007, the Court entered an Order dismissing the action for failing to plead sufficient facts to support the claims that were made in the complaint, and stayed the dismissal for ten days to allow the Plaintiffs to file a motion for leave to file an amended complaint. Extensions were granted and the Plaintiffs filed such a motion on October 29, 2007. The stay will remain in effect until the Court rules on the motion.
Castle/Longs Trust Litigation
As a result of the acquisition of Castle Energy in April 2006, the Company’s wholly-owned subsidiary, DPCA LLC, as successor to Castle, became party to Castle’s ongoing litigation with the Longs Trust in District Court in Rusk County, Texas. The Longs Trust litigation, which was originally the subject of a jury trial in November 2000, has been separated into two pending suits, one in which the Longs Trust is seeking relief on contract claims regarding oil and gas sales and gas balancing under joint operating agreements with various Castle entities, and the other in which Castle’s claims for unpaid joint interest billings and attorneys’ fees in the amount of $964,000, plus prejudgment interest, have been granted by the trial court and upheld on appeal. The Company intends to vigorously defend the Longs Trust breach of contract claims. The Company has not accrued any recoveries associated with the judgment against the Longs Trust, but will do so when and if they are ultimately collected.
Management does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
F -42
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(14) Business Segments
The Company has two reportable segments: oil and gas exploration and production (“Oil and Gas”) and drilling operations (“Drilling”) through its ownership in DHS. Following is a summary of segment results for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005.
Inter-segment | ||||||||||||||||
Oil and Gas | Drilling | Eliminations | Consolidated | |||||||||||||
(In thousands) | ||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||
Revenues from external customers | $ | 107,413 | $ | 56,777 | $ | — | $ | 164,190 | ||||||||
Inter-segment revenues | — | 34,410 | (34,410 | ) | — | |||||||||||
Total revenues | 107,413 | 91,187 | (34,410 | ) | 164,190 | |||||||||||
Operating income (loss) | (124,135 | ) | 4,438 | (11,644 | ) | (131,341 | ) | |||||||||
Other income and (expense)1 | (21,413 | ) | (8,705 | ) | 1,231 | (28,887 | ) | |||||||||
Income (loss) from continuing operations, before tax | $ | (145,548 | ) | $ | (4,267 | ) | $ | (10,413 | ) | $ | (160,228 | ) | ||||
Total Assets | $ | 996,549 | $ | 146,314 | $ | (37,668 | ) | $ | 1,105,195 | |||||||
Year Ended December 31, 2006 | �� | |||||||||||||||
Revenues from external customers | $ | 89,511 | $ | 57,149 | $ | — | $ | 146,660 | ||||||||
Inter-segment revenues | — | 25,033 | (25,033 | ) | — | |||||||||||
Total revenues | 89,511 | 82,182 | (25,033 | ) | 146,660 | |||||||||||
Operating income (loss) | (20,685 | ) | 15,467 | (12,120 | ) | (17,338 | ) | |||||||||
Other income and (expense)1 | (6,426 | ) | (7,264 | ) | (2,595 | ) | (16,285 | ) | ||||||||
Income (loss) from continuing operations, before tax | $ | (27,111 | ) | $ | 8,203 | $ | (14,715 | ) | $ | (33,623 | ) | |||||
Total Assets | $ | 819,470 | $ | 148,869 | $ | (39,016 | ) | $ | 929,323 | |||||||
Six Months Ended December 31, 2005 | ||||||||||||||||
Revenues from external customers | $ | 39,230 | $ | 9,096 | $ | — | $ | 48,326 | ||||||||
Inter-segment revenues | — | 7,220 | (7,220 | ) | — | |||||||||||
Total revenues | 39,230 | 16,316 | (7,220 | ) | 48,326 | |||||||||||
Operating income (loss) | (5,631 | ) | 2,757 | (3,496 | ) | (6,370 | ) | |||||||||
Other income and (expense)1 | (21,142 | ) | (1,003 | ) | (688 | ) | (22,833 | ) | ||||||||
Income (loss) from continuing operations, before tax | $ | (26,773 | ) | $ | 1,754 | $ | (4,184 | ) | $ | (29,203 | ) | |||||
Year Ended June 30, 2005 | ||||||||||||||||
Revenues from external customers | $ | 51,816 | $ | 4,796 | $ | — | $ | 56,612 | ||||||||
Inter-segment revenues | — | 2,523 | (2,523 | ) | — | |||||||||||
Total revenues | 51,816 | 7,319 | (2,523 | ) | 56,612 | |||||||||||
Operating income (loss) | (174 | ) | (2,028 | ) | (388 | ) | (2,590 | ) | ||||||||
Other income and (expense)1 | (8,778 | ) | (2 | ) | 1,017 | (7,763 | ) | |||||||||
Income (loss) from continuing operations, before tax | $ | (8,952 | ) | $ | (2,030 | ) | $ | 629 | $ | (10,353 | ) | |||||
1 | Includes interest and financing costs, gain on sale of marketable securities, unrealized losses on derivative contracts and other miscellaneous income for Oil and Gas, and other miscellaneous income for Drilling. Minority interest is included in inter-segment eliminations. |
F -43
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(15) Selected Quarterly Financial Data (Unaudited)
Quarter Ended | ||||||||||||||||
March 31, | June 30, | September 30, | December 31, | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||
Total revenue | $ | 36,913 | $ | 38,200 | $ | 44,019 | $ | 45,058 | ||||||||
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect | (25,135 | ) | (83,869 | ) | (15,056 | ) | (36,168 | ) | ||||||||
Net income (loss) | (18,744 | ) | (94,205 | ) | (6,418 | ) | (29,980 | ) | ||||||||
Net income (loss) per common share:1 | ||||||||||||||||
Basic | $ | (.34 | ) | $ | (1.51 | ) | $ | (.10 | ) | $ | (.47 | ) | ||||
Diluted | $ | (.34 | ) | $ | (1.51 | ) | $ | (.10 | ) | $ | (.47 | ) | ||||
Year Ended December 31, 2006 | ||||||||||||||||
Total revenue | $ | 31,717 | $ | 36,564 | $ | 41,034 | $ | 37,345 | ||||||||
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect | 17,554 | (8,365 | ) | (23,425 | ) | (19,387 | ) | |||||||||
Net income (loss) | 13,805 | 4,210 | (7,080 | ) | (10,500 | ) | ||||||||||
Net income (loss) per common share:1 | ||||||||||||||||
Basic | $ | .28 | $ | .08 | $ | (.13 | ) | $ | (.20 | ) | ||||||
Diluted | $ | .27 | $ | .08 | $ | (.13 | ) | $ | (.20 | ) |
1 | The sum of individual quarterly net income per share may not agree with year-to-date net income per share as each period’s computation is based on the weighted average number of common shares outstanding during the period. |
F-44
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(16) Disclosures About Capitalized Costs, Costs Incurred and Major Customers (Unaudited)
Capitalized costs related to oil and gas activities are as follows:
December 31, | December 31, | December 31, | June 30, | |||||||||||||
2007 | 2006 | 2005 | 2004 | |||||||||||||
(In thousands) | ||||||||||||||||
Unproved offshore California properties | $ | 14,789 | $ | 12,484 | $ | 10,960 | $ | 10,925 | ||||||||
Unproved onshore domestic properties | 232,677 | 205,089 | 156,183 | 91,010 | ||||||||||||
Proved offshore California properties | 17,733 | 16,906 | 13,678 | 12,207 | ||||||||||||
Proved onshore domestic properties | 722,675 | 547,336 | 424,988 | 353,099 | ||||||||||||
987,874 | 781,815 | 605,809 | 467,241 | |||||||||||||
Accumulated depreciation and depletion | (204,014 | ) | (116,151 | ) | (57,922 | ) | (43,034 | ) | ||||||||
$ | 783,860 | $ | 665,664 | $ | 547,887 | $ | 424,207 | |||||||||
Costs incurred1 in oil and gas activities are as follows:
Six Months Ended | Year Ended | |||||||||||||||||||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||||||||||||||
Unproved property acquisition costs | $ | 26,408 | $ | 2,305 | $ | 60,002 | $ | 1,525 | $ | 88,116 | $ | 35 | $ | 25,383 | $ | 81 | ||||||||||||||||
Proved property acquisition costs | 45,857 | 301 | 2,972 | 283 | 4,386 | 82 | 81,190 | — | ||||||||||||||||||||||||
Developed costs incurred on undeveloped reserves | 143,630 | 526 | 43,198 | 2,946 | 30,891 | 1,389 | 72,413 | 3,104 | ||||||||||||||||||||||||
Development costs – other | 119,607 | — | 159,807 | — | 54,591 | — | 36,369 | — | ||||||||||||||||||||||||
Exploration costs | 9,062 | — | 4,690 | — | 2,061 | — | 6,155 | — | ||||||||||||||||||||||||
$ | 344,564 | $ | 3,132 | $ | 270,669 | $ | 4,754 | $ | 180,045 | $ | 1,506 | $ | 221,510 | $ | 3,185 | |||||||||||||||||
1 | Included in costs incurred are asset retirement obligation costs for all periods presented. |
A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, is as follows:
Six Months Ended | Year Ended | |||||||||||||||||||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||||||||||||||
Revenue: | ||||||||||||||||||||||||||||||||
Oil and gas revenues | $ | 86,838 | $ | 7,721 | $ | 86,627 | $ | 7,596 | $ | 38,833 | $ | 3,810 | $ | 47,255 | $ | 5,191 | ||||||||||||||||
Expenses: | ||||||||||||||||||||||||||||||||
Production costs | 25,747 | 3,638 | 19,711 | 3,705 | 7,517 | 2,128 | 9,260 | 3,840 | ||||||||||||||||||||||||
Depletion | 62,088 | 1,285 | 53,190 | 1,049 | 11,593 | 382 | 12,544 | 720 | ||||||||||||||||||||||||
Exploration | 9,062 | — | 4,690 | — | 2,061 | — | 6,155 | — | ||||||||||||||||||||||||
Abandonment and impaired properties | 58,411 | — | 11,359 | — | — | — | — | — | ||||||||||||||||||||||||
Dry hole costs | 26,673 | — | 4,323 | — | 5,423 | — | 2,771 | — | ||||||||||||||||||||||||
Results of operations of oil and gas producing activities | $ | (95,143 | ) | $ | 2,798 | $ | (6,646 | ) | $ | 2,842 | $ | 12,239 | $ | 1,300 | $ | 16,525 | $ | 631 | ||||||||||||||
Income from operations of properties sold, net | 17,556 | — | 9,163 | — | 5,952 | — | 13,434 | — | ||||||||||||||||||||||||
Gain (loss) on sale of properties | (3,998 | ) | — | 6,712 | — | 11,788 | — | — | — | |||||||||||||||||||||||
Results of discontinued operations of oil and gas producing activities | $ | 13,558 | $ | — | $ | 15,875 | $ | — | $ | 17,740 | $ | — | $ | 13,434 | $ | — | ||||||||||||||||
F- 45
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(16) Disclosures About Capitalized Costs, Cost Incurred and Major Customers (Unaudited), Continued
During the year ended December 31, 2007, two customers accounted individually for 27% and 13% of the Company’s total oil and gas sales. During the year ended December 31, 2006, two customers individually accounted for 24% and 15% of the Company’s total oil and gas sales. During the six months ended December 31, 2005, three customers individually accounted for 15%, 14% and 12% of the Company’s total oil and gas sales. During the fiscal year ended June 30, 2005, one customer individually accounted for 10% of the Company’s total oil and gas sales.
(17) Information Regarding Proved Oil and Gas Reserves (Unaudited)
Proved Oil and Gas Reserves.Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. For the purposes of this disclosure, the Company has included reserves it is committed to and anticipates drilling.
(i) Reservoirs are considered proved if economic producability is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves;” (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other un-drilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
F- 46
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(17) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
“Prepared” reserves are those quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of revenues which were estimated by the Company’s employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.
Estimates of the Company’s oil and natural gas reserves and present values as of December 31, 2007, December 31, 2006, December 31, 2005, and June 30, 2005 were prepared by Ralph E. Davis Associates, Inc., the Company’s independent reserve engineers with respect to onshore reserves for all periods presented and with respect to offshore reserves as of December 31, 2007 and 2006.
Estimates of the Company’s offshore reserves were prepared by Mannon Associates Inc. as of December 31, 2005 and June 30, 2005.
A summary of changes in estimated quantities of proved reserves for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the year ended June 30, 2005 is as follows:
Onshore | Offshore | |||||||||||
GAS | OIL | OIL | ||||||||||
(MMcf) | (MBbl) | (MBbl) | ||||||||||
(In thousands) | ||||||||||||
Estimated Proved Reserves: Balance at June 30, 2004 | 88,479 | 11,378 | 1,827 | |||||||||
Revisions of quantity estimate | (3,850 | ) | (512 | ) | (173 | ) | ||||||
Extensions and discoveries | 39,459 | 1,162 | — | |||||||||
Purchase of properties | 32,282 | 1,397 | — | |||||||||
Sale of properties | (7,654 | ) | (153 | ) | — | |||||||
Production | (7,675 | ) | (899 | ) | (156 | ) | ||||||
Estimated Proved Reserves: Balance at June 30, 2005 | 141,041 | 12,373 | 1,498 | |||||||||
Revisions of quantity estimate | (4,683 | ) | (506 | ) | (468 | ) | ||||||
Extensions and discoveries | 58,725 | 2,542 | — | |||||||||
Purchase of properties | 11,816 | — | — | |||||||||
Sale of properties | (22,025 | ) | (221 | ) | — | |||||||
Production | (3,720 | ) | (428 | ) | (81 | ) | ||||||
Estimated Proved Reserves: Balance at December 31, 2005 | 181,154 | 13,760 | 949 | |||||||||
Revisions of quantity estimate | (23,050 | ) | (2,943 | ) | (328 | ) | ||||||
Extensions and discoveries | 90,738 | 3,533 | — | |||||||||
Purchase of properties | 7,590 | 3 | — | |||||||||
Sale of properties | (23,706 | ) | (673 | ) | — | |||||||
Production | (8,022 | ) | (1,192 | ) | (162 | ) | ||||||
Estimated Proved Reserves: Balance at December 31, 2006 | 224,704 | 12,488 | 459 | |||||||||
Revisions of quantity estimate | 23,932 | (2,126 | ) | 25 | ||||||||
Extensions and discoveries | 86,269 | 2,423 | — | |||||||||
Purchase of properties | 10,559 | 266 | — | |||||||||
Sale of properties | (24,738 | ) | (1,425 | ) | — | |||||||
Production | (11,253 | ) | (940 | ) | (145 | ) | ||||||
Estimated Proved Reserves: Balance at December 31, 2007 | 309,473 | 10,686 | 339 | |||||||||
F- 47
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(17) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
Proved developed reserves:
June 30, 2004 | 55,786 | 6,240 | 695 | |||||||||
June 30, 2005 | 70,568 | 6,947 | 585 | |||||||||
December 31, 2005 | 56,852 | 7,171 | 657 | |||||||||
December 31, 2006 | 65,026 | 5,828 | 459 | |||||||||
December 31, 2007 | 92,194 | 4,209 | 339 |
F- 48
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(17) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
Future net cash flows presented below are computed using year end prices and costs and are net of all overriding royalty revenue interests.
Future corporate overhead expenses and interest expense have not been included.
Onshore | Offshore | Combined | ||||||||||
(In thousands) | ||||||||||||
December 31, 2007 | ||||||||||||
Future net cash flows | $ | 2,923,129 | $ | 28,352 | $ | 2,951,481 | ||||||
Future costs: | ||||||||||||
Production | 723,689 | 11,921 | 735,610 | |||||||||
Development and abandonment | 585,622 | — | 585,622 | |||||||||
Income taxes | 224,073 | 2,281 | 226,354 | |||||||||
Future net cash flows | 1,389,745 | 14,150 | 1,403,895 | |||||||||
10% discount factor | (699,896 | ) | (2,125 | ) | (702,021 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 689,849 | $ | 12,025 | $ | 701,874 | ||||||
Estimated future development cost anticipated for fiscal 2008 and 2009 on existing properties | $ | 334,326 | $ | — | $ | 334,326 | ||||||
December 31, 2006 | ||||||||||||
Future net cash flows | $ | 1,743,639 | $ | 21,695 | $ | 1,765,334 | ||||||
Future costs: | ||||||||||||
Production | 466,919 | 14,727 | 481,646 | |||||||||
Development and abandonment | 329,355 | — | 329,355 | |||||||||
Income taxes | 76,373 | 562 | 76,935 | |||||||||
Future net cash flows | 870,992 | 6,406 | 877,398 | |||||||||
10% discount factor | (393,249 | ) | (915 | ) | (394,164 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 477,743 | $ | 5,491 | $ | 483,234 | ||||||
Estimated future development cost anticipated for fiscal 2007 and 2008 on existing properties | $ | 250,224 | $ | — | $ | 250,224 | ||||||
December 31, 2005 | ||||||||||||
Future net cash flows | $ | 2,613,958 | $ | 45,420 | $ | 2,659,378 | ||||||
Future costs: | ||||||||||||
Production | 481,537 | 21,970 | 503,507 | |||||||||
Development and abandonment | 318,704 | 2,950 | 321,654 | |||||||||
Income taxes | 471,125 | 5,325 | 476,450 | |||||||||
Future net cash flows | 1,342,592 | 15,175 | 1,357,767 | |||||||||
10% discount factor | (604,355 | ) | (3,788 | ) | (608,143 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 738,237 | $ | 11,387 | $ | 749,624 | ||||||
June 30, 2005 | ||||||||||||
Future net cash flows | $ | 1,724,986 | $ | 64,516 | $ | 1,789,502 | ||||||
Future costs: | ||||||||||||
Production | 366,453 | 19,286 | 385,739 | |||||||||
Development and abandonment | 183,416 | 8,934 | 192,350 | |||||||||
Income taxes | 294,754 | — | 294,754 | |||||||||
Future net cash flows | 880,363 | 36,296 | 916,659 | |||||||||
10% discount factor | (387,874 | ) | (11,415 | ) | (399,289 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 492,489 | $ | 24,881 | $ | 517,370 | ||||||
F- 49
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(17) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
The principal sources of changes in the standardized measure of discounted net cash flows during the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the fiscal year ended June 30, 2005 are as follows:
Six Months Ended | Year Ended | |||||||||||||||
Years Ended December 31, | December 31, | June 30, | ||||||||||||||
2007 | 2006 | 2005 | 2005 | |||||||||||||
(In thousands) | ||||||||||||||||
Beginning of the year | $ | 483,234 | $ | 749,624 | $ | 517,370 | $ | 288,037 | ||||||||
Sales of oil and gas production during the period, net of production costs | (95,976 | ) | (98,340 | ) | (47,746 | ) | (68,602 | ) | ||||||||
Purchase of reserves in place | 38,364 | 14,716 | 58,790 | 201,693 | ||||||||||||
Net change in prices and production costs | 286,255 | (567,435 | ) | 170,831 | 90,938 | |||||||||||
Changes in estimated future development costs | (106,678 | ) | (35,041 | ) | (50,676 | ) | 19,345 | |||||||||
Extensions, discoveries and improved recovery | 135,868 | 213,741 | 336,920 | 93,624 | ||||||||||||
Revisions of previous quantity estimates, estimated timing of development and other | (83,240 | ) | (82,456 | ) | (164,632 | ) | (91,002 | ) | ||||||||
Previously estimated development and abandonment costs incurred during the period | 144,156 | 46,144 | 32,280 | 72,413 | ||||||||||||
Sales of reserves in place | (77,631 | ) | (55,640 | ) | (56,276 | ) | (42,508 | ) | ||||||||
Change in future income tax | (70,801 | ) | 222,959 | (98,974 | ) | (75,371 | ) | |||||||||
Accretion of discount | 48,323 | 74,962 | 51,737 | 28,803 | ||||||||||||
End of year | $ | 701,874 | $ | 483,234 | $ | 749,624 | $ | 517,370 | ||||||||
(18) Subsequent Events
In early February, the Company added CIG collars for 10,000 Mmbtu/day with a $6.50 per Mmbtu floor and a $7.70 per Mmbtu ceiling in the second quarter of 2008 and a $6.50 per Mmbtu floor and an $8.15 per Mmbtu ceiling in the third quarter of 2008. The Company also entered into new CIG gas hedges for 35,000 Mmbtu per day for the first quarter of 2009 with a floor price of $7.50 per Mmbtu and a ceiling price of $9.88 per Mmbtu. The fair value of the derivative liability at February 26, 2008 was $15.2 million.
On February 19, 2008, the Company’s shareholders approved a transaction between the Company and Tracinda Corporation (“Tracinda”) to issue 36.0 million shares of the Company’s common stock at $19.00 per share for proceeds of $684.0 million. The transaction closed on February 20, 2008 and a portion of the proceeds was immediately used to pay down to zero all amounts outstanding under the Company’s revolving credit facility. As a result of the transaction, Tracinda owns approximately 35% of our outstanding common stock and named two members to our Board of Directors, bringing the Board to 12 members. Tracinda has the right to proportional representation on our Board, and based on their current ownership may add up to three additional members at its discretion in the future. It also has a right to proportional representation on all of our Board committees.
F- 50
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005
(18) Subsequent Events, Continued
On February 28, 2008, the Company closed a transaction with EnCana Oil & Gas (USA) Inc., (“EnCana”) to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. In addition, Delta has acquired over 1,700 drilling locations on approximately 18,250 gross acres with a 95% working interest. The transaction increases the Company’s working interest in the North Vega project leasehold to 95% from an average 50%, with additional acquired acreage that includes the Buzzard Creek federal unit (4,300 acres) and approximately 6,000 acres immediately adjacent to the Buzzard Creek Unit. With this agreement, the Company’s acreage position in the Vega Area totals over 20,250 net acres. The effective date of the transaction is March 1, 2008. Under terms of the agreement the Company has committed to fund $410.5 million, $110.5 million paid at closing and three $100 million installments over the next four years that have been guaranteed with a Letter of Credit.
F- 51
Glossary of Oil and Gas Terms
The terms defined in this section are used throughout this Form 10-K.
Bbl.Barrel (of oil or natural gas liquids).
Bcf.Billion cubic feet (of natural gas).
Bcfe.Billion cubic feet equivalent.
Bbtu.One billion British Thermal Units.
Developed acreage.The number of acres which are allocated or held by producing wells or wells capable of production.
Development well.A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole; dry well.A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Equivalent volumes.Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.
Exploratory well.A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
Gross acres or gross wells.The total acres or wells, as the case may be, in which a working interest is owned.
Liquids.Describes oil, condensate, and natural gas liquids.
MBbls.Thousands of barrels.
Mcf.Thousand cubic feet (of natural gas).
Mcfe.Thousand cubic feet equivalent.
MMBtu.One million British Thermal Units, a common energy measurement.
MMcf.Million cubic feet.
MMcfe.Million cubic feet equivalent.
NGL.Natural gas liquids.
Net acres or net wells.The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers.
NYMEX.New York Mercantile Exchange.
Present value or PV10% or “SEC PV10%.” When used with respect to oil and gas reserves, present value or PV10% or SEC PV10% means the estimated future gross revenue to be generated from the production of net proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service, accretion, and future income tax expense or to depreciation, depletion, and amortization, discounted using monthly end-of-period discounting at a nominal discount rate of 10% per annum.
Productive wells.Producing wells and wells that are capable of production, including injection wells, salt water disposal wells, service wells, and wells that are shut-in.
Proved developed reserves.Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves.Estimated quantities of crude oil, natural gas, and natural gas liquids which, upon analysis of geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.
Proved undeveloped reserves.Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
Undeveloped acreage.Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains estimated proved reserves.
Working interest.An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property and a share of production.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange of Act of 1934, we have caused this Form 10-K to be signed on our behalf by the undersigned, thereunto duly authorized, in the City of Denver and State of Colorado on the 29thday of February, 2008.
DELTA PETROLEUM CORPORATION | ||||
By: | /s/ Roger A. Parker | |||
Roger A. Parker, Chairman and | ||||
Chief Executive Officer | ||||
By: | /s/ Kevin K. Nanke | |||
Kevin K. Nanke, Treasurer and | ||||
Chief Financial Officer | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this Form 10-K has been signed below by the following persons on our behalf and in the capacities and on the dates indicated.
Signature and Title | Date | |||||
/s/ Roger A. Parker | February 29, 2008 | |||||
/s/ Hank Brown | February 29, 2008 | |||||
/s/ Kevin R. Collins | February 29, 2008 | |||||
/s/ Jerrie F. Eckelberger | February 29, 2008 | |||||
/s/ Aleron H. Larson, Jr. | February 29, 2008 | |||||
/s/ Russell S. Lewis | February 29, 2008 | |||||
/s/ James J. Murren | February 29, 2008 | |||||
/s/ Jordan R. Smith | February 29, 2008 | |||||
/s/ Neal A. Stanley | February 29, 2008 | |||||
/s/ Daniel J. Taylor | February 29, 2008 | |||||
/s/ James B. Wallace | February 29, 2008 | |||||
/s/ John R. Wallace | February 29, 2008 |
INDEX TO EXHIBITS
2. | Plans of Acquisition, Reorganization, Arrangement, Liquidation, or Succession. | |
2.1 | Agreement and Plan of Merger, dated as of November 8, 2005, among Delta Petroleum Corporation, a Colorado corporation, Delta Petroleum Corporation, and as amended a Delaware corporation, DPCA LLC, a Delaware limited liability company and a wholly owned subsidiary of Delta Colorado, and Castle Energy Corporation, a Delaware corporation. Incorporated by reference to Appendix A to the proxy statement/prospectus contained in the Company’s Form S-4 registration statement, SEC File No. 333-130672. | |
3. | Articles of Incorporation and By-laws. | |
3.1 | Certificate of Incorporation of the Company, as amended. Incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated January 31, 2006. | |
3.2 | Amended and Restated By-laws of the Company. Incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K, dated February 9, 2006. | |
4. | Instruments Defining the Rights of Security Holders. | |
4.1 | Purchase Agreement dated March 9, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.1 to the Company’s Form 8-K dated March 15, 2005. | |
4.2 | Registration Rights Agreement dated March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.2 to the Company’s Form 8-K dated March 15, 2005. | |
4.3 | Indenture dated as of March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and US Bank National Association, as Trustee. Incorporated by reference from Exhibit 4.3 to the Company’s Form 8-K dated March 15, 2005. | |
4.4 | Form of 7% Series A Senior Notes due 2015 with attached notation of Guarantees. | |
Incorporated by reference from Exhibit 4.4 to the Company’s Form 8-K dated March 15, 2005. | ||
4.5 | Indenture, dated as of April 25, 2007, by and between the Company and the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (including Form of 33/4% Convertible Senior Note due 2037). Incorporated by reference from Exhibit 4.1 to the Company’s Form 8-K dated April 19, 2007. | |
4.6 | Form of 33/4% Convertible Senior Note due 2037. Incorporated by reference from Exhibit 4.2 to the Company’s Form 8-K dated April 19, 2007. | |
10. | Material Contracts. | |
10.1 | Delta Petroleum Corporation 1993 Incentive Plan, as amended. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1996. * | |
10.2 | Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference from the Company’s Notice of Annual Meeting and Proxy Statement dated June 1, 1999.* | |
10.3 | Delta Petroleum Corporation 2001 Incentive Plan. Incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement dated July 26, 2001 for fiscal year 2000 ended June 30, 2000.* | |
10.4 | Delta Petroleum Corporation 2002 Incentive Plan incorporated by reference from Exhibit A to the Company’s definitive proxy statement filed May 1, 2002. |
10.5 | Agreement between Delta Petroleum Corporation and Amber Resources Company dated July 1, 2001, incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated October 25, 2001. | |
10.6 | Delta Petroleum Corporation 2005 New-Hire Equity Incentive Plan. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 17, 2005.* | |
10.7 | Amendment No. 1 to Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated June 17, 2005.* | |
10.8 | Employment Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated May 5, 2005.* | |
10.9 | Employment Agreement with Kevin K. Nanke dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.10 | Employment Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.11 | Employment Agreement with Stanley F. Freedman dated January 11, 2006. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated January 11, 2006.* | |
10.12 | Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement filed on November 22, 2004.* | |
10.13 | Delta Petroleum Corporation 2006 New-Hire Equity Incentive Plan. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 20, 2006.* | |
10.14 | Amended and Restated Credit Agreement, dated November 17, 2006, by and among Delta Petroleum Corporation, JPMorgan Chase Bank, N.A. and certain other financial institutions named therein. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated November 17, 2006. | |
10.15 | First Amendment to Amended and Restated Credit Agreement, dated December 4, 2006, by and among Delta Petroleum Corporation, JPMorgan Chase Bank, N.A. and certain other financial institutions named therein. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated November 17, 2006. | |
10.16 | Promissory Note, dated December 4, 2006, by and between Delta Petroleum Corporation and JPMorgan Chase Bank, N.A. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated November 17, 2006. | |
10.17 | Delta Petroleum Corporation 2007 Performance and Equity Incentive Plan. Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement filed on December 28, 2006.* | |
10.18 | Form of Restricted Stock Award Agreement. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated February 5, 2007.* | |
10.19 | Change in Control Executive Severance Agreement with Roger A. Parker dated April 30, 2007. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated April 30, 2007.* | |
10.20 | Change in Control Executive Severance Agreement with John R. Wallace dated April 30, 2007. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated April 30, 2007.* | |
10.21 | Change in Control Executive Severance Agreement with Kevin K. Nanke dated April 30, 2007. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated April 30, 2007.* | |
10.22 | Change in Control Executive Severance Agreement with Stanley F. Freedman dated April 30, 2007. Incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K dated April 30, 2007. * |
10.23 | Company Stock Purchase Agreement, dated December 29, 2007, by and between Delta Petroleum Corporation and Tracinda Corporation. Incorporated by reference from Exhibit 1.1 to the Company’s Form 8-K dated December 31, 2007. | |
10.24 | $75,000,000 Credit Agreement dated as of December 19, 2007 among DHS Holding Company and DHS Drilling Company as borrowers, and Lehman Brothers Inc. as sole arranger and Lehman Brothers Commercial Paper Inc. as syndication agent and administrative agent. Filed herewith electronically. | |
11. | Statement Regarding Computation of Per Share Earnings. Not applicable. | |
12. | Statement Regarding Computation of Ratios. Not applicable. | |
14. | Code of Ethics. The Company’s Code of Business Conduct and Ethics is posted on the Company’s website at www.deltapetro.com. | |
16. | Letter re: change in certifying accountant. Not applicable. | |
18. | Letter re: change in accounting principles. Not applicable. | |
21. | Subsidiaries of the Registrant. Filed herewith electronically. | |
22. | Published report regarding matters submitted to vote of security holders. Not applicable. | |
23. | Consents of experts and counsel. | |
23.1 | Consent of KPMG LLP. Filed herewith electronically. | |
23.2 | Consent of Ralph E. Davis Associates, Inc. Filed herewith electronically. | |
23.3 | Consent of Mannon Associates. Filed herewith electronically. | |
24. | Power of attorney. Not applicable. | |
31. | Rule 13a-14(a) /15d-14(a) Certifications. | |
31.1 | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically. | |
31.2 | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically. | |
32. | Section 1350 Certifications. | |
32.1 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically. | |
32.2 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically. |
* | Management contracts and compensatory plans. |