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Article by Anonymous    (11-24-08 10:27 AM)

Filed with the SEC from Nov 13 to Nov 19:

Delta Petroleum (DPTR)
Billionaire investor Kirk Kerkorian's investment vehicle, Tracinda, increased its holdings to 37,228,000 shares (36.02%), after buying 1.1 million shares on Nov. 11 and 12 at about $5.61 apiece.

BUSINESS OVERVIEW

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.

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.

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

(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 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.

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.
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.


CEO BACKGROUND

General

Our directors are elected annually by the stockholders to serve until the next annual meeting of stockholders and until their respective successors are duly elected and qualified, or until the earlier of their death, resignation or retirement. Our bylaws provide that the number of directors comprising the whole Board shall from time to time be fixed and determined by resolution adopted by our Board of Directors. Our Board has established the size of the Board at fifteen directors, with three Board seats currently vacant. Our Board is recommending that our twelve current directors be reelected.

Each nominee consented to be named as a nominee in this proxy statement, and we expect that each nominee will be able to serve if elected. If any nominee becomes unavailable or unwilling to accept his nomination for election for any reason, a substitute nominee may be proposed by our Board and the shares represented by proxy will be voted for any substitute nominee, unless the Board otherwise reduces the number of directors. Proxies cannot be voted for a greater number of persons than the number of nominees named below.

Pursuant to the terms of the Company Stock Purchase Agreement (the “Tracinda Agreement”), dated December 29, 2007, between Delta and Tracinda Corporation (“Tracinda”), Tracinda is entitled, at all times that it beneficially owns not less than ten percent of our outstanding Common Stock, to designate a number of nominees for election to serve on our Board of Directors and each of its committees that is equal to Tracinda’s pro rata share of stock ownership in our Company multiplied by the number of directors on our Board or committee, as the case may be, with any fractional number being rounded to the nearest whole number. However, during the twelve months following the closing of the transaction with Tracinda, Tracinda’s nominees may not constitute greater than the initial number of directors to which Tracinda is entitled to designate as a result of the purchase of the shares under the Tracinda Agreement. Tracinda is currently entitled to designate five nominees, but has chosen to nominate only two designees at this time. The persons designated by Tracinda for nomination for election to the Board are James J. Murren and Daniel J. Taylor.

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 Drilling Company (“DHS”) and since May 3, 2006 has served in those same capacities with DHS Holding Company. Mr. Parker also serves as President, Chief Executive Officer and Director of Amber Resources. He received a Bachelor of Science 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 and since May 3, 2006 has served in those same capacities with DHS Holding Company. Mr. Wallace was Vice President of Exploration and Acquisitions for United States Exploration, Inc. (“UXP”), a Denver-based publicly-held oil and gas exploration 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 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 and since May 3, 2006 has served in those same capacities with DHS Holding Company. Since 1989, he has been involved in public and private accounting with the oil and gas industry. Mr. Nanke received a Bachelor of Arts 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. Since May 3, 2006 he has served as Executive Vice President, General Counsel and Secretary of DHS Holding Company. 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 President Emeritus of the University of Colorado and holder of the Quigg and Virginia S. Newton Endowed Chair in Leadership. From June 2005 to March 2008 he served 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. Mr. Brown also currently serves as a director of Sensient Technologies Corporation and Sealed Air Corporation, both of which are publicly held.

Kevin R. Collins currently serves as President, Chief Executive Officer and a Director of Evergreen Energy Inc., which is listed on the New York Stock Exchange Arca. Prior to his current position, Mr. Collins served as Evergreen’s Executive Vice President and Chief Operating Officer from September 2005 to April 2007, 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. (NYSE), 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. 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 has served as Senior Vice President of Strategic Development at Verisign (NASDAQ: VRSN) since July 2007, where he is responsible for rationalizing the company’s lines of business. He also serves as President and CEO of Lewis Capital, LLC, 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 TransCore, a wireless transportation systems integration company that was and still is the market leader in electronic toll collection systems. Prior to that, Mr. Lewis managed an oil and gas exploration subsidiary of UGI, a publicly traded gas utility and was Vice President of EF Hutton in its Municipal Finance group. Mr. Lewis also serves on the Boards of Braintech, a publicly traded company that is a leader in vision guided robotics, and NameMedia, a private backed firm that holds a significant portfolio of internet domain names. Mr. Lewis has a BA 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 MGM Mirage from January 1998 to August 2007 and Treasurer of MGM Mirage from November 2001 to August 2007. Prior to 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 Bachelors and Masters 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 approximately 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 B.S. degree in Mechanical Engineering from the University of Oklahoma in 1975.

Daniel J. Taylor is an executive employed by Tracinda Corporation and currently serves as a Director of MGM Mirage. 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.

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 B.S. 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.


MANAGEMENT DISCUSSION FROM LATEST 10K


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 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.


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.


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.

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.


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.

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”).

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.



MANAGEMENT DISCUSSION FOR LATEST QUARTER



Forward Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements, within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”).
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 Form 10-Q 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 and divestiture 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; 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; 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 “Risk Factors” in our Form 10-K for the year ended December 31, 2007, 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;

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the timing, effects and success of our acquisitions, dispositions and exploration and development activities;

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uncertainties in the estimation of proved reserves and in the projection of future rates of production;

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timing, amount, and marketability of production;

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third party curtailment, or processing plant or pipeline capacity constraints beyond our control;

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our ability to find, acquire, develop, produce and market production from new properties;

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the availability of borrowings under our credit facility;

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effectiveness of management strategies and decisions;

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the strength and financial resources of our competitors;

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climatic conditions;

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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;

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unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids; and

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our ability to fully utilize income tax net operating loss and credit carry-forwards.
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.
Recent Developments
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Continued success from our Rocky Mountain drilling activities has increased our production from continuing operations by 64% for the three months ended September 30, 2008 to 5.8 Mmcfe, compared to 3.5 Mmcfe for the comparable prior year quarter, and for the nine months ended September 30, 2008, increased 69% to 15.9 Mmcfe, compared to 9.4 Mmcfe for the prior year nine month period.

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During the quarter through two transactions, we were able to lower our overall leasehold costs per acre in the Columbia River Basin while simultaneously obtaining a strategic partner in the future exploration of the area.
The following discussion and analysis relates to items that have affected our results of operations for the three and nine months ended September 30, 2008 and 2007. This analysis should be read in conjunction with our consolidated financial statements and the accompanying notes thereto included in this Form 10-Q.
Results of Operations
Quarter Ended September 30, 2008 Compared to Quarter Ended September 30, 2007
Net Income. Net income was $49.8 million, or $0.48 per diluted common share, for the three months ended September 30, 2008, compared to net loss of $5.0 million, or $.08 per diluted common share, for the three months ended September 30, 2007. Loss from continuing operations increased from $12.9 million for the three months ended September 30, 2007 to income of $43.1 million for the three months ended September 30, 2008. The primary reason for the change in net income and income from continuing operations was the recognition of $54.8 million of unrealized gains on derivative instruments during the third quarter 2008 as a result of significant declines in oil and gas prices during the period.
Oil and Gas Sales . During the three months ended September 30, 2008, oil and gas sales from continuing operations increased 112% to $49.0 million, as compared to $23.1 million for the comparable period a year earlier. The increase was the result of a 64% increase in production from continuing operations, a 53% increase in oil prices, and a 67% increase in gas prices. The average gas price received during the three months ended September 30, 2008 increased to $5.97 per Mcf compared to $3.58 per Mcf for the year earlier period due to increased natural gas prices. The average oil price received during the three months ended September 30, 2008 increased to $107.76 per Bbl compared to $70.35 per Bbl for the year earlier period. Net gains from hedging instruments were $5.2 million for the three months ended September 30, 2007. The hedging gains in 2007 were a result of lower gas prices. These gains were recorded as an increase in revenues.
Contract Drilling and Trucking Fees . Contract drilling and trucking fees for the three months ended September 30, 2008 decreased to $11.8 million compared to $15.5 million for the comparable year earlier period. The decrease is the result of additional rigs operating for Delta in 2008 compared to 2007. Revenues on such rigs are eliminated in consolidation.

Lease Operating Expense. Lease operating expenses for the three months ended September 30, 2008 increased to $7.3 million from $5.5 million in the year earlier period primarily due to the 64% increase in production from continuing operations. Lease operating expense from continuing operations per Mcfe for the three months ended September 30, 2008 decreased to $1.26 per Mcfe from $1.56 per Mcfe for the comparable year earlier period. The average LOE per Mcfe rate decreased due to a shift in production from higher cost Gulf Coast properties to lower cost Rockies properties and due to the timing of Piceance fracturing operations on new wells which utilize production water that would otherwise require costly offsite disposal and be recorded as lease operating expense.
Exploration Expense. Exploration expense consists of geological and geophysical costs, lease rentals and abandoned leases. Our exploration costs for the three months ended September 30, 2008 were $2.9 million compared to $4.7 million for the comparable year earlier period. Current year exploration activities primarily relate to seismic shoots in two areas with possible future drilling opportunities.


Dry Hole Costs and Impairments. We incurred dry hole costs of approximately $8.1 million for the three months ended September 30, 2008 compared to $273,000 for the comparable period a year ago. During the three months ended September 30, 2008, dry hole costs primarily related to four wells, one well in Wyoming, one well in California, one well in Utah and a non-operated well in the Columbia River Basin. No impairments were recorded during the three months ended September 30, 2008.
Depreciation, Depletion, Amortization and Accretion — oil and gas. Depreciation, depletion and amortization expense increased 61% to $25.5 million for the three months ended September 30, 2008, as compared to $15.9 million for the comparable year earlier period. Depletion expense for the three months ended September 30, 2008 was $24.8 million compared to $15.3 million for the three months ended September 30, 2007. The 62% increase in depletion expense was due to a 64% increase in production from continuing operations. Our depletion rate decreased slightly from $4.35 per Mcfe for the three months ended September 30, 2007 to $4.28 per Mcfe for the current year period.
Drilling and Trucking Operations . Drilling expense decreased to $8.2 million for the three months ended September 30, 2008 compared to $10.0 million for the comparable prior year period. This decrease can be attributed to lower utilization during the current year period, coupled with greater usage of DHS rigs by Delta, as intercompany expenses are eliminated in consolidation.
Depreciation and Amortization — drilling and trucking. Depreciation and amortization expense - drilling decreased to $2.7 million for the three months ended September 30, 2008, as compared to $4.0 million for the comparable year earlier period. The decrease is due to increased utilization of DHS rigs by Delta.
General and Administrative Expense. General and administrative expense increased 16% to $14.9 million for the three months ended September 30, 2008, as compared to $12.8 million for the comparable prior year period. The increase in general and administrative expenses is primarily attributed to an increase in staff and related personnel costs.
Other Expense. Other expense for the three months ended September 30, 2008 includes $2.8 million of impairment charges related to our auction rate securities and $1.3 million related to a forfeited deposit for a rig acquisition that DHS was unable to close due to Lehman’s failure to fund under the DHS credit facility.
Realized Gain on Derivative Instruments, Net. Effective July 1, 2007, we discontinued cash flow hedge accounting. Beginning July 1, 2007, we recognize realized gains or losses in other income and expense instead of as a component of revenue. As a result, other income and expense includes $10.8 million and $788,000 of realized gains for the three months ended September 30, 2008 and 2007, respectively.
Unrealized Gain on Derivative Instruments, Net . As a result of the discontinuation of cash flow hedge accounting, we recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $54.8 million of unrealized gains on derivative instruments in other income and expense during the three months ended September 30, 2008 compared to a gain of $3.2 million for the comparable prior year period, primarily due to lower commodity prices in the current year period.
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 three months ended September 30, 2008, DHS reported losses resulting in a minority interest credit to earnings, compared to the same period in 2007 in which DHS reported earnings resulting in a minority interest charge.
Interest Income. Interest income increased to $3.1 million for the three months ended September 30, 2008 compared to $1.1 million for the comparable prior year period. The increase is primarily due to interest earned on our $300 million restricted deposit in connection with the EnCana transaction and invested cash received from the Tracinda transaction during the first quarter of 2008.

Interest Expense and Financing Costs. Interest and financing costs increased 70% to $10.6 million for the three months ended September 30, 2008, as compared to $6.2 million for the comparable year earlier period. The increase is primarily related to an increase in the amounts outstanding under the Delta and DHS credit facilities and the non-cash amortization of discount on the installments payable to EnCana.
Income Tax Expense (Benefit) . Due to our continued losses, we were required by the “more likely than not” provisions of SFAS No. 109 to record a valuation allowance on our Delta stand-alone deferred tax assets beginning with the second quarter of 2007. As a result, our income tax benefit for the three months ended September 30, 2008 of $2.2 million relates only to DHS, as no benefit was provided for Delta’s pre-tax losses. During the three months ended September 30, 2007, an income tax benefit of $65,000 was recorded for continuing operations.
Discontinued Operations. Discontinued operations for the three months ended September 30, 2008 and September 30, 2007 include the Midway Loop, Texas properties that are held for sale as of September 30, 2008. Discontinued operations for the three months ended September 30, 2007 include the North Dakota properties sold in September 2007 and the Washington County, Colorado properties sold in October 2007.
Gain on Sale of Discontinued Operations. During the three months ended September 30, 2008, we completed an asset exchange agreement where we acquired additional interests in our Midway Loop properties in exchange for cash and certain non-core properties. The transaction resulted in a gain on the disposition of the non-core properties of $716,000. During the three months ended September 30, 2007, we sold non-core properties in North Dakota for proceeds of $6.2 million and recorded a gain of $4.3 million.
Results of Operations
Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007
Net Income. Net income was $7.7 million, or $0.08 per diluted common share, for the nine months ended September 30, 2008, compared to a net loss of $118.7 million, or $1.97 per diluted common share, for the nine months ended September 30, 2007. Loss from continuing operations decreased from $128.1 million for the nine months ended September 30, 2007 to $9.3 million for the nine months ended September 30, 2008. The nine months ended September 30, 2007 included $58.4 million of impairment charges and the initial recognition of a full valuation allowance required to be recorded against the Company’s deferred tax assets, while the nine months ended September 30, 2008 included $13.6 million of unrealized gains on derivative instruments.
Oil and Gas Sales . During the nine months ended September 30, 2008, oil and gas sales from continuing operations increased 147% to $156.1 million, as compared to $63.3 million for the comparable period a year earlier. The increase was the result of a 69% increase in production from continuing operations, a 69% increase in oil prices, and a 66% increase in gas prices. The average gas price received during the nine months ended September 30, 2008 increased to $7.50 per Mcf compared to $4.51 per Mcf for the year earlier period due to increased natural gas prices. The average oil price received during the nine months ended September 30, 2008 increased to $103.07 per Bbl compared to $60.82 per Bbl for the comparable year earlier period. Net gains from hedging instruments were $9.8 million for the nine months ended September 30, 2007. The hedging gains in 2007 were primarily due to lower gas prices. These gains were recorded as an increase in revenues.
Contract Drilling and Trucking Fees . Contract drilling and trucking fees for the nine months ended September 30, 2008 decreased to $30.4 million compared to $46.5 million for the comparable year earlier period. The decrease is primarily the result of additional rigs operating for Delta in 2008 compared to 2007. Revenues on such rigs are eliminated in consolidation.

CONF CALL

Broc Richardsonv

Thank you. Good morning and thanks everyone for joining us today on the call. On the conference call from Delta are Roger Parker, the Chairman and CEO; John Wallace, President and COO; Kevin Nanke, the Treasurer and Chief Financial Officer; Ted Freedman, Executive Vice President and General Counsel; and Carl Lakey, Senior Vice President of Operations.

Before we begin, I need to read the forward-looking statements disclosure. This conference call will include projections and other forward-looking statements with in the meaning of the Federal Securities Laws and are intended to be covered by the Safe Harbor's credited there by.

In that regard, you are referred to the cautionary statement displayed on Delta's website which is incorporated by reference to the information provided on this call. Further, the Securities and Exchange Commission permits oil and gas companies in their filings with the SEC to disclose only true reserves that the company has demonstrated by actual production, will conclude their formation test to be economically legally perusable under existing economic and operated conditions.

Delta may use certain terms in the conference call that the SEC's guidelines strictly prohibit us from including in the filings with the SEC. Investors are urged to consider closely the oil and gas disclosures in Delta's Form 10-K for fiscal year-end December 31, 2007 as updated by subsequent periodic and current reports on Forms 10-Q and 8-K respectively.

With that, I will turn the call over to Mr. Roger Parker.

Roger Parker

Thank you, Broc. Good morning and thank you for joining us for our third quarter conference call. As you have heard from many companies, especially energy companies, the significant and rapid decline in oil and gas prices have caused us to act in an expeditious manner to be fiscally responsible, and to ensure that Delta Petroleum is prudently situated to weather the current environment in the financial markets.

With revenue streams cut in half over a 60 day period and credit markets being all but closed, immediate and definitive action was necessary and important. This has obviously had an impact on drilling activity, in all but our lowest risk and predictable areas, which are basically located in the Piceance Basin.

It is not a reflection of the potential of areas like the Paradox Basin; rather, it is an acknowledgement that this company will do everything possible to maintain adequate liquidity and to evidence real value of assets for our shareholders.

In fact, I would like to note and emphasize many of the very important metrics that have been achieved and here to for used to be the drivers for an E&P company, prior to the worldwide fallout of the financial markets.

Number one, we reported that unaudited proven reserve estimates at September 30, 2008 were 657 Bcf equivalent; which represent as 75% increase over year-end 2007. Secondly, we referenced that we experienced a 64% increase in quarter-over-quarter production growth. Number three, EBITDAX increased 98% to approximately $43 million for the quarter.

These represent what are supposed to be… what we are supposed to be doing and have been able to accomplish, and the growth should not be ignored because ultimately it will matter again.

In addition, announcements were made last week which are supportive of value growth, and should be interpreted… and should excuse me should not be interpreted as tantamount to survivor moods.

One of the announcements that we made was that our banks just this week conclude a new credit facility, with a meaningful increase in the borrowing base, evidencing good property valuation even in a declining commodity price environment, and which is also suggestive of good liquidity.

We also announced an effort to explore joint venture alternatives for our Piceance Basin asset. This is intended to be a value unlock, as it relates to current company valuations along with prudent balance sheet management. We will only transact or it is the intention of the company that we will only transact on an NAV positive basis.

With that, I am going to turn it over to Kevin Nanke, the Chief Financial Officer to reference a few of the financial metrics from the quarter, and then we'll turn it over to question and answers.

Kevin Nanke

Thank you, Roger. Net income for the quarter was $49.8 million or $0.48 per diluted share, compared to a net loss of $5 million or an $0.08 loss per diluted share in the third quarter of '07.

Oil and gas sales from continuing operations were $49 million, compared to $23.1 million in the third 2007. Continuing operations, exclude our Midway Loop Texas asset, which is held for sale and generated over $9 million of cash flow in the quarter.

We had realized oil prices of $107.76 and realized gas prices of $5.97, an increase of 53% and 67% for the third quarter… from the third quarter of '07 respectively.

Our net income was materially impacted by a $54.8 million unrealized gain on derivative instruments relating to the significant decline in oil and gas prices at the end of the quarter, 11.3 realized gain on derivative instruments from the sale of certain derivative contracts on September 30th, and $8.1 million in dry hole expense during the quarter.

Over production for the quarter was 6.6 Bcfe, an increase of 44% compared to the third quarter of '07, which was at the upper end of our guidance. Additionally we estimate 0.22 Bcfe in production was lost attributable to hurricanes Ike and Gustav.

These operating expenses from continuing operations per Mcfe the three months ended September 30 decreased to $1.26 per annum, from a $1.56 per annum in the third quarter of '07. The average LOE per Mcfe decreased due to a shift in production from higher cost, Gulf Coast properties to lower cost Rockies properties.

The depletion rate decreased… also increased $4. 28 per Mcfe for the three months from $4.35 per annum in the early year period. This decrease reflects increased reserve additions and lower cost per well in the Piceance Basin capital development program, along with a higher mix from Rocky Mountain properties.

With that I will turn it back over to Roger.

Roger Parker

Thank you, Kevin. Operator, we will go ahead and open the call up to questions and answers at this time. Thank you.

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