Item 1B.
Unresolved Staff Comments.
None
Item 2.
Item 2.
Description of Property.
Development Projects
Rocky Mountain Region - Piceance, Wind River and Denver Julesburg Basins
The Rocky Mountain Region comprises approximately 38% of our estimated proved reserves as of December 31, 2005. A large portion of our undeveloped acreage and drilling inventory is located in this region, where we expect our drilling efforts and capital expenditures will be increasingly focused.
In the Rocky Mountains, our primary activities are focused in five basins that provide a large inventory of development and exploration drilling, which we anticipate will provide us with a platform for reserve and production growth in the future.
Piceance Basin. We are currently focusing our development efforts on the Vega Unit in Mesa County and the Garden Gulch Field in Garfield County, Colorado. These fields are consistent with our strategy of targeting reservoirs that demonstrate predictable per well reserve recoveries. There are 10-15 productive sands that have minimal geologic variance throughout the respective fields, which leads to predictable well results. We use our expertise in multi-zone, multi-stage frac completion technologies to accelerate production from wells which also allows for increases in recoverable reserves. The Williams Fork member of the Mesaverde formation is the primary producing sand at depths of 6,400-8,000 feet in the Vega Unit and 7,500-9,000 feet in the Garden Gulch Field. Generally, our drilling and production results from our Piceance Basin properties have been encouraging.
In the Vega Unit we have an interest in 3,130 net acres. Our working interest is 100% in this unit. Approximately 2,760 net acres were undeveloped as of December 31, 2005. Our capital budget for the Vega Unit for the year ending December 31, 2006 is $30 - $35 million. Our proved reserves are 53.6 Bcfe as of December 31, 2005 and our net productive capacity in the field was 5.0 MMcfe per day as of December 31, 2005. Most of the acreage in the Vega Unit is on federal land and is not subject to any drilling restrictions. The field is currently constrained by available pipeline capacity and as such we have entered into a gas gathering and processing agreement with a third party for the construction of a new pipeline that will ultimately provide us with sufficient transportation capacity to fully develop the Vega Unit. The pipeline project is anticipated to be operational during 2006. Our new wells will be production restricted until the pipeline project is complete. By virtue of continuing drilling activity we expect significant increases in production from the Vega Unit upon completion of the new pipeline. We have contracted DHS Rig #5 to develop the Unit.
In the Garden Gulch Field there are 6,314 acres of undeveloped leasehold in which we own a 25% non-operated working interest. This field is analogous to the Vega Unit in that current drilling activity has demonstrated repeatable and predictable results. Our capital budget for the field in the year ending December 31, 2006 is $15 - $25 million. Proved reserves for the Garden Gulch Field are 16.2 Bcfe as of December 31, 2005. Net production in the field was 650 Mcfe per day as of December 31, 2005. Most of our acreage is on fee land and is not subject to any drilling restrictions.
Wind River Basin. The primary asset in the Wind River Basin is the Howard Ranch Field in Fremont County, Wyoming. We have an interest in 6,850 net acres, where our working interest averages 90% throughout the area. At December 31, 2005, 6,110 net acres were undeveloped. This field is a project that is also characterized by multi-zone, multi-stage frac completions. The geological characteristics of the field are similar throughout our acreage with several thousand feet of gross interval containing many different gas-charged and over-pressured productive sands. Our capital budget for the field in the year ending December 31, 2006 is approximately $20 million. Approximately 88% of our acreage position in this field is on federal land, and is subject to drilling restrictions that typically do not allow us to drill in the field for approximately six months out of the year. For the combined Wind River Basin properties, we have proved reserves of 27.0 Bcfe and net production of 3.5 MMcfe per day as of December 31, 2005. We have DHS Rig #1 contracted to develop the field.
Denver-Julesburg (“D-J”) Basin. The Washington County project in Colorado is the primary asset in the D-J Basin. We have an interest in 482,148 net acres, 99.6% of which is undeveloped. Our working interest is
100% throughout the area. The main target reservoirs are the Niobrara, “D” sand and “J” sand formations at depths of between 2,800’ and 4,000’. Our proved reserves in this project area comprised 3.1 Bcfe as of December 31, 2005. Net production in the field was 1.5 MMcfe per day as of December 31, 2005. Our capital budget for the project in the year ending December 31, 2006 is $3 - $5 million.
Development Projects
Gulf Coast Region - Newton, Midway Loop and Opossum Hollow Fields
The Gulf Coast Region comprises approximately 48% of our estimated proved reserves as of December 31, 2005. In the Gulf Coast Region, our primary activities include developing the Newton, Midway Loop and Opossum Hollow Fields which provide us with a large inventory of development drilling.
Newton Field. The Newton Field is located in Newton County, Texas. We have an interest in 3,522 net acres, where our working interest is 100% throughout the field. At December 31, 2005, 1,486 net acres were undeveloped. The wells in the Newton Field produce from 13 different sands in the Wilcox formation that range in depth from 9,000 to 11,500 feet. We believe we have a competitive advantage in the Newton Field ad surrounding area through our experience in multi-zone, multi-stage frac techniques gained from our completion activities in the Rocky Mountains. Our multi-zone completion practices allow us to produce several different zones simultaneously which increases our daily production rates. The field is a large structural anticline that is defined by extensive well control and seismic information and the Wilcox sands are consistent across the structure. As of December 31, 2005, we had 27 producing wells in the Newton Field. We have planned $44 - $50 million in capital expenditures for the field in the year ending December 31, 2006. Our proved reserves in the Newton Field are 66.5 Bcfe as of December 31, 2005 and production was 11.8 MMcfe net per day as of December 31, 2005. The Newton Field represents an important growth platform for us in the Gulf Coast Region. We have a one drilling rig under a long term contract and are considering the possibility of an acceleration of activity in this area.
Midway Loop Field. The Midway Loop Field is located in Polk and Tyler Counties, Texas. We have interests in 18,000 gross acres, where our working interest averages 38%. The wells in this field produce from the C zone of the Austin Chalk and are drilled horizontally with dual laterals that reach up to 6,000’ of displacement in each lateral. The vertical depth of the Austin Chalk is approximately 13,500 feet. We have recently completed the Best Kenesson #1 and are drilling the BP America Delta #1. Production results from the Best Kenesson #1 are encouraging. As of December 31, 2005 our proved reserves totaled 11.0 Bcfe and production was 7.2 MMcfe net per day for the Midway Loop Field. Our capital budget for the field in the year ending December 31, 2006 is $12 - $16 million. DHS rig #9 is drilling the current well and will remain active in the area.
Opossum Hollow Field. The Opossum Hollow Field is located in McMullen County, Texas and we have an average working interest of 98%. The field currently produces from the Wilcox at a depth of 6,500 feet, but we have recently drilled the Morril Sligo #1 to a deeper objective and are waiting on the completion of a high pressure pipeline to begin producing the well. Based on log calculations the Morril Sligo #1 appears that it will be productive. We expect that the new well could have meaningful production rates and reserve recoveries. Upon completion of the pipeline we anticipate commencing a development drilling plan for the deeper Sligo structure. As of December 31, 2005 we had proved reserves of 6.6 Bcfe with production of 1.1 Mcfe per day. Our capital budget for the field in the year ending December 31, 2006 is up to $14 million.
Exploration Projects
Rocky Mountain Region - Paradox Basin and the central Utah Hingeline play
Paradox Basin. In the Paradox Basin we are currently focusing our exploration efforts on three different project areas in Montrose and San Miguel Counties Colorado and Grand County, Utah, where we have an interest in 58,014 net acres, all of which were undeveloped at December 31, 2005. Our working interest is approximately 70% on average. We plan to drill three exploratory wells on three different prospects in 2006.
With drilling success we would increase our drilling budget to accommodate a development program. The projects in the Paradox Basin are consistent with our strategy of targeting reservoirs that demonstrate consistent geologic attributes that exist over large areas. Our capital budget for the basin in the year ending December 31, 2006 is $6 - $8 million. We have contracted DHS Rig #6 to drill the exploratory wells.
Central Utah Hingeline Play. We plan to drill several exploration wells in the Utah Hingeline Play later this year. In February, 2006 we acquired a 65% working interest in 88,000 undeveloped acres. We have been evaluating the technical and economic merits of central Utah since an important new field (“Covenant Field”) discovery by another operator that validated the geologic premise supporting the play. Several geologic structural features have been identified under our acreage position. The structures are large in comparison to the Covenant Field discovery and have the potential to contain significant reserves. Our capital budget for the year ending December 31, 2006 is $8- $12 million. We will contract a DHS rig to drill the exploration wells.
Gulf Coast Region - Newton
Newton 3D Survey. The ongoing development project at the Newton Field is centered in a new 58 square mile 3D seismic survey that was accomplished in 2005 and has recently been processed and interpreted. We have a seismic / leasehold option on 28,000 net acres. The initial seismic review has identified additional Wilcox structures similar in appearance to the Newton Field and numerous shallow Yegua and Frio formation features. These newly identified features will be the focus of exploratory drilling in 2006 and our capital budget in the year ending December 31, 2006 is expected to be approximately $10 million. DHS Rig #10 will be contracted to drill the exploratory wells. The Wilcox formation ranges in depth from 9,000 to 12,000 feet in this area.
Exploration Projects
Other Areas - Columbia River Basin
The Columbia River Basin is located in southeast Washington and northeast Oregon. We have interests in 396,000 net acres in the basin, all of which are undeveloped. We have a 100% working interest in under 332,000 acres and a 1% overriding royalty interest convertible to a 15% back-in after project payout working interest under an additional 425,000 acres. There are other major exploration and production companies that are conducting drilling activities in the basin. Results of the current drilling activity will assist in determining the merits of a drilling program on our acreage position. The basin is characterized by overpressured, tight sand gas formations, which fall into our core competency of multi-zone, multi-stage frac completion technologies. Based upon log evaluation of older wells, well testing and core analysis, there appear to be multiple productive zones with many hydrocarbon bearing sands which lie below thick layers of basalt. The Columbia River Basin will be a long term development prospect and does not account for any of our proved reserves as of December 31, 2005. We are not budgeting any drilling capital expenditure for 2006; however, any significant drilling successes realized by other operators could cause a reallocation or an increase of our 2006 budget to allow for initial drilling activity on our Columbia River Basin leasehold. DHS Rig #7 has been contracted by a third party operator to drill in the immediate area.
In late 2005 we transferred our 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”). Subsequent to year-end, we sold a minority interest in CRBP. We have retained the majority ownership and are the manager of CRBP. This sale did not involve any of our operated 100% leasehold of approximately 332,000 net acres in the Columbia River Basin.
Other Operations
Offshore California producing properties
Point Arguello Unit. Through a nominee we own the equivalent of a 6.07% working interest in the form of a financial arrangement termed a “net operating interest” in the Point Arguello Unit and related facilities located Offshore California in the Santa Barbara Channel. The “net operating interest” is defined as being the positive
or negative cash flow resulting to the interest from a seven step calculation which in summary subtracts royalties, operating expenses, severance taxes, production taxes and ad valorem taxes, capital expenditures, unit fees and certain other expenses from the oil and gas sales and certain other revenues that are attributable to the interest. Within this unit there are three producing platforms (Hidalgo, Harvest and Hermosa). The nominee has contractually agreed to retain all of the abandonment costs associated with our interest in the Point Arguello Unit and the related facilities.
Rocky Point Unit. We own a 6.25% interest in the development of the east half of OCS Block 451 in the Rocky Point Unit. On November 2, 2000 we entered into an agreement with all of the interest owners of the Point Arguello Unit for the development of Rocky Point and agreed, among other things, that Arguello, Inc. would become the operator of Rocky Point. As of December 31, 2005 two development wells have been drilled from Platform Hidalgo to a portion of the Rocky Point Unit structure. The Rocky Point Unit is being developed through extended-reach drilling from existing platforms located within the adjacent Point Arguello Unit. The operator has plans to drill up to eight additional extended reach wells to develop the east half of the OCS Block 451.
Offshore California non-producing properties
We have ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas units in which we have recorded aggregate carrying values of $11.0 million and $10.9 million at December 31, 2005 and June 30, 2005, respectively. These non-operated property interests are located in close 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 have been indicated. The recovery of our investment in these properties will require extensive exploration and development activities (and costs) which cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.
Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, we believe the fair values of our property interests are in excess of their carrying values at December 31, 2005 and that no impairment in the carrying values has occurred. Pursuant to a ruling in California v. Norton, later affirmed by the 9th Circuit Court of Appeals, the U.S. government was required to make a consistency determination relating to the 1999 lease suspension requests under a 1990 amendment to the Coastal Zone Management Act. In the event that there is some future adverse ruling under the Coastal Zone Management Act that we decide not to appeal or that we appeal without success, it is likely that some or all of our interests in these leases would become impaired and written off at that time. It is also possible that other events could occur during the Coastal Zone Management Act review or appellate process that would cause our interests in the leases to become impaired, and we will continuously evaluate those factors as they occur. We and our majority-owned subsidiary, Amber Resources Company of Colorado, are among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. government has materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties.
On November 15, 2005, the United States Court of Federal Claims issued a ruling in the suit granting the plaintiffs’ motion for 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. The court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold thirty six out of the total forty offshore California federal leases that are the subject of the litigation. The Court further 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.
We and Amber are among the current lessees of the thirty six leases that are the subject of the ruling. Together with Amber, our net share of the $1.1 billion award is approximately $121 million. The final ruling in the case will not be made until the Court addresses the plaintiffs’ additional claims regarding the four additional leases, as well as their claims regarding the hundreds of millions of dollars that have been spent in
the successful efforts to find oil and gas in the disputed lease area, and other matters. The final ruling, including the ruling made on November 15, will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted. See Item 3
Item 3. Legal Proceedings
We and our majority-owned subsidiary, Amber Resources Company of Colorado, are among twelve plaintiffs in a lawsuit that was filed on January 9, 2002 in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. government has materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case, that a 1990 amendment to the Coastal Zone Management Act that required the government to make a consistency determination prior to granting lease suspension requests in 1999, constitutes a material change in the procedures and standards that were in effect when the leases were issued.
The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.
The suit seeks compensation for the lease bonuses and rentals paid to the Federal government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. We own approximately 12% of the lease bonus costs that are the subject of the lawsuit. In addition, our claim for exploration costs and related expenses will also be substantial. In the event, however, that we receive any proceeds as the result of such litigation, we will be obligated to pay a portion of any amount received by us 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.
On November 15, 2005, the United States Court of Federal Claims issued a ruling in the suit granting the plaintiffs’ motion for 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. The court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold thirty six out of the total forty offshore California federal leases that are the subject of the litigation. The Court further 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.
We and Amber are among the current lessees of the thirty six leases that are the subject of the ruling. Together with Amber, our net share of the $1.1 billion award is approximately $121 million. The final ruling in the case will not be made until the Court addresses the plaintiffs’ additional claims regarding the four additional leases, as well as their claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. The final ruling, including the ruling made on November 15, will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted.
Item 4.
Item 4. Submission of Matters To a Vote of Security Holders
No matter was submitted to a vote of security holders during the quarter ended December 31, 2005.
Item 4A. Directors And Executive Officers
Our executive officers and members of our Board of Directors, and their respective ages are as follows:
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 of 1987 and Chief Executive Officer since April of 2002. He served as our President from May of 1987 until February of 2006 when he resigned to accommodate the appointment of John Wallace to that position. He was named Chairman of the Board on July 1, 2005. Since April 1, 2005, he also serves as Executive Vice President and Director of DHS Drilling 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 member of the Rocky Mountain Oil and Gas Association and is a board member of the Independent Producers 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 and was appointed President in February 2006. Since April 1, 2005, he also serves as Executive Vice President and Director of DHS Drilling Company. Mr. Wallace was Vice President of Exploration and Acquisitions for United States Exploration, Inc. (“UXP”), a publicly-held oil and gas exploration company, from May 1998 to October 2003, when he became employed by Delta. Prior to UXP, Mr. Wallace served as president of various different 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 Rocky Mountain Oil and Gas Association, the American Association of Petroleum Geologists and the
Independent Producers Association of the Mountain States. Mr. Wallace is the son of John B. Wallace, a Director of the Company.
Kevin K. Nanke, Treasurer and Chief Financial Officer, joined Delta in April 1995. Since April 1, 2005 he has also served as Chief Financial Officer, Treasurer and Director of DHS Drilling 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 our subsidiary, DHS Drilling Company, since the same date. 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 in Denver, Colorado.
Kevin R. Collins is Executive Vice President, Finance and Strategy of Kfx Inc. From 1995 until 2004 he was Executive Vice President and Chief Financial Officer of Evergreen Resources, Inc., having served in various management capacities. Evergreen Resources was acquired by Pioneer Natural Resources in September 2004. Mr. Collins became a Certified Public Accountant in 1983 and has over 13 years of 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, Director of Pegasus Technologies, Inc. and Board Member and Chairman of the Finance Committee of Independent Petroleum Association of Mountain States. He received his B.S. 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 present, Mr. Eckelberger has been engaged in the private practice of law and is presently a member of the law firm of Eckelberger & Jackson, LLC. 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, 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. 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 is 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 Petroleum Corporation 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. Previously 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 serves on the board of directors of Castle Energy Corporation (NASDAQ: CECX) and Advanced Aerations Systems, a privately held
firm engaged in the subsurface soil treatment. Mr. Lewis has a BA degree in Economics from Haverford College and an MBA from the Harvard School of Business.
Jordan R. Smith is President of Ramshorn Investments, Inc., a wholly owned subsidiary of Nabors Drilling USA LP, 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. 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. Pure Energy Services Ltd. debuted on the Toronto Stock Exchange in February 2006 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.
James P. Van Blarcom has been Managing Director of The Payne Castle Group, LLC, which has provided sales solutions business development and government affairs services in the cable, high-speed internet and communications industries since 2004. From 1998 to 2004, he was employed by Comcast Cable Communications Management, LLC, a division of Comcast Corporation, where he served as National Telecommunications Manager, Corporate Telecommunications Manager, and finally as Commercial Development Manager, Comcast High-Speed Internet. Mr. Van Blarcom received a B.A. degree in History from Hobart College in 1984.
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 currently serves as a member of the Board of Directors and formerly served as the Chairman of Tom Brown, Inc., an oil and gas exploration company then listed on the New York Stock Exchange. 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 of Delta.
At the present time Messrs. Collins, Eckelberger, Lewis, and Smith serve as the Audit Committee; Messrs. Eckelberger, Collins, Lewis, and Smith serve as the Compensation Committee; and Messrs. Smith, Collins, Eckelberger, Lewis and Stanley serve as the Nominating & Governance Committee.
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.
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 National 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.
On February 28, 2006, the closing price of our common stock was $19.51. We have not paid dividends on our common stock and we do not expect to do so in the foreseeable future.
Approximate Number of Holders of Common Stock
The number of holders of record of our common stock at February 28, 2006 was approximately 800 which does not include an estimated 2,500 additional holders whose stock is held in “street name.”
Recent Sales of Unregistered Securities
During the six months ended December 31, 2005, 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, 2005.
Item 6.
Item 6. Selected Financial Data
The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are a Denver, Colorado based independent energy 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 Gulf Coast and Rocky Mountain 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, 2005, we had estimated proved reserves that totaled 269.4 Bcfe, of which 38.5% were proved developed, with an after-tax PV-10 value of $760.6 million. As of December 31, 2005, we achieved net production of 56.0 Mmcfe per day.
As of December 31, 2005, our reserves were comprised of approximately 181.2 Bcf of natural gas and 14.7 Mmbbls of crude oil, or 67.2% gas on an equivalent basis. Approximately 48% of our proved reserves were located in the Gulf Coast, 38% in the Rocky Mountains, and 14% in other locations. We expect that our drilling efforts and capital expenditures will focus increasingly on the Rockies, where approximately two-thirds of our fiscal 2006 capital budget is allocated and more than one-half of our undeveloped acreage is located. As of December 31, 2005, we controlled approximately 990,000 undeveloped acres, representing in excess of 96% 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 90% as of December 31, 2005. 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 11 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.
For calendar year 2006, we have preliminarily established a drilling budget of approximately $150.0 to $195.0 million. We are concentrating a substantial portion of this budget on the development of our Newton, Opossum Hollow, and Midway Loop Fields in the Gulf Coast region, the Howard Ranch Field in the Wind River Basin in central Wyoming, the Vega Unit and PGR properties of the Piceance Basin in western Colorado, and our central Utah play acquired subsequent to year-end. State of the art geologic and seismic geophysical modeling indicates that these fields have target geologic formations containing substantial hydrocarbon deposits that can be economically developed. Recently completed successful wells in several of these 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 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 is 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 while containing costs 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 involve 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. Our current derivative contracts cover approximately 32% of our estimated 2006 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, allowing us to grow reserves and replace and expand production organically without having to rely solely on acquisitions.
Recent developments
During the six months ended December 31, 2005, we achieved the following:
Results of Operations
The following discussion and analysis relates to items that have affected our results of operations for the six months ended December 31, 2005 and 2004, and the fiscal years ended June 30, 2005, 2004 and 2003. 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 Transition Report on Form 10-K.
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 $9.9 million non-cash loss for ineffective hedges, $8.0 million of realized losses on hedging contracts, higher exploration and dry hole costs, increased general and administrative expenses of $8.1 million due to the growth in the Company’s operations and activities, and increased interest and financing costs of $6.8 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 53% to $60.7 million, as compared to $39.7 million for the six months ended December 31, 2004. The increase was the result of (i) an average onshore gas price received during the six months ended December 31, 2005 of $8.82 per Mcf compared to $5.83 per Mcf received in the six months ended December 31, 2004, (ii) an increase in average onshore oil price received in the six months ended December 31, 2005 of $59.42 per Bbl compared to $44.64 per Bbl during the same period in 2004, (iii) an increase in offshore oil price received of $48.98 per Bbl during the six months ended December 31, 2005 compared to $30.66 during the six months ended December 31, 2004, and (iv) a 7.6% increase in average daily production over the six months ended December 31, 2004.
Cash payments required on our hedging activities impacted revenues during the six months ended December 31, 2005 and 2004. The cost of settling our hedging activities was $8.0 million and $93,000 during the six months ended December 31, 2005 and 2004, respectively.
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 addition, 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 are currently working for third party operators.
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.
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:
Lease Operating Expense. Lease operating expenses for the six months ended December 31, 2005 were $9.4 million compared to $6.1 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 $1.17 per Mcfe as compared to $0.78 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 $3.57 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. Recently, Newton has 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 112% to $17.6 million in the six months ended December 31, 2005, as compared to $8.3 million for
the six months ended December 31, 2004. Depreciation, depletion and amortization expenses for our onshore properties increased to $2.24 per Mcfe during the six months ended December 31, 2005 from $1.33 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 drilling costs relative to reserve additions. We also incurred higher depletion rates caused by lower proved developed producing reserves in our South Angleton and Padgett fields. The reduction in the South Angleton field was from unsuccessful drilling results, while the reduction in reserves in the Padgett field was from a seismic survey that indicated a smaller reservoir than originally anticipated.
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.
Dry Hole Costs. 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.
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 $3.4 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 will assist us in prioritizing our drilling locations and identifying new target formations in 2006. 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.
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 was recorded. Included in our exploration expense for the six months ended December 31, 2005 is $1.3 million 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.
Professional Fees. Professional fees include corporate legal costs, accounting fees, shareholder relations consultants and legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to our undeveloped offshore California leases. Our professional fees increased 167% to $2.3 million for the six months ended December 31, 2005, as compared to $847,000 for the six months ended December 31, 2004. The increase in professional fees can be attributed largely to compliance with the Sarbanes-Oxley Act and also to annual fees incurred over the shorter six month transition period ended December 31, 2005 without a corresponding reduction in fees.
General and Administrative Expense. General and administrative expense increased 133% to $14.2 million for the six months ended December 31, 2005 as compared to $6.1 million for the six months ended December 31, 2004. The increase in general and administrative expenses is primarily attributed to (i) $2.1 million of stock option compensation expense related to the adoption of SFAS No. 123R, (ii) a 60% increase in technical and administrative staff and related personnel costs, (iii) the expansion of our office facility and (iv) $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.
Unrealized Losses on Derivative Contracts, 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 an $9.9 million non-cash 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.
Interest and Financing Costs. Interest and financing costs increased 306% to $9.1 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 prospect in Washington completed in April 2005. In addition, borrowings of $35.0 million by DHS have 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 $7.6 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. The results of operations on these assets during the six months ended December 31, 2005 was $501,000. During October 2005, we sold at auction our interests in several non-strategic fields for proceeds of $5.3 million and a gain of $1.6 million.
Fiscal 2005 Compared to Fiscal 2004
Net Income. Net income increased $10.0 million to $15.1 million or $.36 per diluted common share for fiscal 2005, an increase of 198% as compared to $5.1 million or $.17 per diluted common share for fiscal 2004. This increase was primarily due to a 91% increase in production relating to the Alpine acquisition completed during fiscal 2004, the Manti acquisition completed during fiscal 2005 and the development of our undeveloped properties.
Revenue. During fiscal 2005, oil and natural gas revenue from continuing operations increased 144% to $90.9 million, as compared to $37.2 million in fiscal 2004. The increase was the result of (i) an average onshore gas price received in fiscal 2005 of $5.79 per Mcf compared to $5.27 per Mcf in 2004, (ii) an increase in average onshore oil price received in fiscal 2005 of $47.05 per Bbl compared to $33.09 per Bbl in 2004, (iii) an increase in offshore oil price received of $33.37 per Bbl in fiscal 2005 compared to $22.11 in 2003, and (iv) a 91% increase in average daily production over the prior year.
Cash payments required on our hedging activities impacted revenues in 2005 and 2004. The cost of settling our hedging activities was $960,000 in fiscal 2005 and $859,000 in fiscal 2004.
Production volumes, average prices received and cost per equivalent Mcf for the years ended June 30, 2005 and 2004 are as follows:
Lease Operating Expense. Lease operating expenses for the year ended June 30, 2005 were $15.6 million compared to $7.5 million for the same period a year earlier. Lease operating expense from continuing operations for onshore properties for the year ended June 30, 2005 was $.92 per Mcfe as compared to $.70 per Mcfe for the same period a year earlier. Lease operating expense from continuing operations for offshore properties was $4.00 per Mcfe for the year ended June 30, 2005 and $3.76 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 completion of the Manti acquisition in January 2005 and the Alpine acquisition in June 2004. The assets acquired in these two transactions have higher production costs than the asset base previously owned.
Depreciation and Depletion Expense. Depreciation and depletion expense increased 134% to $23.2 million in fiscal 2005, as compared to $9.9 million in fiscal 2004. Depreciation and depletion expenses for our onshore properties increased to $1.57 per Mcfe during fiscal 2005 from $1.46 per Mcfe in fiscal 2004. Depletion rates have increased based on the higher amounts paid to acquire reserves in the ground and the increase in drilling costs. In addition, we incurred higher depletion rates caused by lower proved developed producing reserves in our South Angleton and Padgett fields. The reduction in the South Angleton field was from unsuccessful drilling results, while the reduction in reserves in the Padgett field was from a seismic survey that indicated a smaller reservoir than originally anticipated. Our depletion rate in our Newton field also increased as a result of drilling and completing inefficiencies and under-performing wells. Our last two wells which were completed in late June were on budget and had predictable initial results. We anticipate overall depletion rates for us and our competitors to increase under the current pricing environment.
Dry Hole Costs. We incurred dry hole costs of approximately $2.8 million for the year ended June 30, 2005 compared to $2.1 million for the same period a year ago. A significant portion of these costs relate to our Trail Blazer prospect in Laramie County, Wyoming. Included in the dry holes were four non-Niobrara formation dry holes in Washington County, Colorado.
Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the year ended June 30, 2005 were $6.2 million compared to $2.4 million for the prior year. Current year activities include newly acquired seismic information in Washington County, Colorado, Polk County, Texas and Laramie County, Wyoming.
Drilling and Trucking Operations. We had drilling and trucking operations of $4.7 million during the year ended June 30, 2005 compared to $232,000 during the year ended June 30, 2004. The significant increase in
expenses was due to an increase in the number of rigs in operation.
Professional Fees. Professional fees include corporate legal costs, accounting fees, shareholder relations consultants and legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to our undeveloped offshore California leases. Our professional fees increased 71% to $2.0 million for fiscal 2005, as compared to $1.2 million for fiscal 2004. The increase in professional fees can be attributed largely to compliance with the Sarbanes-Oxley Act.
General and Administrative Expense. General and administrative expense increased 116% to $14.9 million in fiscal 2005, as compared to $6.9 million in fiscal 2004. The increase in general and administrative expenses is primarily attributed to (i) the 95% increase in technical and administrative staff and related personnel costs, (ii) the expansion of our office facility and (iii) $824,000 of vested restricted stock and option awards granted to officers, directors and management.
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.
Interest and Financing Costs. Interest and financing costs increased 352% to $8.0 million in fiscal 2005, as compared to $1.8 million in fiscal 2004. The increase is primarily related to the $150.0 million senior note offering completed in March 2005 and 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 prospect in Washington completed in April 2005.
Fiscal 2004 Compared to Fiscal 2003
Net income. Net income increased $3.8 million to $5.1 million or $.17 per diluted common share for fiscal 2004, an increase of 302% as compared to $1.3 million or $.05 per diluted common share for fiscal 2003. This increase was primarily due to a 40% increase in production from fiscal 2003 relating to acquisitions completed during fiscal 2004 and 2003, the development of undeveloped properties associated with these acquisitions and an increase in average oil and natural gas prices received by Delta.
Revenue. During fiscal 2004, oil and natural gas revenue from continuing operations increased 65% to $37.2 million, as compared to $22.6 million in fiscal 2003. The increase was the result of (i) an average for onshore gas price received in fiscal 2004 of $5.27 per Mcf compared to $4.71 per Mcf in 2003, (ii) an increase in average onshore oil price received in fiscal 2004 of $33.09 per Bbl compared to $28.82 per Bbl in 2003, (iii) a slight increase in offshore oil price received of $22.11 per Bbl in fiscal 2004 compared to $20.21 in 2003 and (iv) a 40% increase in average daily production during the fiscal year previously discussed above.
Cash payments required on our hedging activities impacted revenues in 2004 and 2003. The cost of settling our hedging activities was $859,000 in fiscal 2004 and $1.9 million in fiscal 2003.
Production volumes, average prices received and cost per equivalent Mcf for the years ended June 30, 2004 and 2003 were as follows:
Lease Operating Expense. Lease operating expense increased 8% to $7.5 million for fiscal 2004, as compared to $7.0 million for 2003; however, onshore lease operating costs per Mcfe decreased from $.99 per Mcfe in fiscal 2003 to $.70 per Mcfe in fiscal 2004. This decrease in production cost per Mcfe can primarily be attributed to our Padgett Field acquisition completed during fiscal 2003. The Padgett Field added an additional 1.2 Bcfe to current year production with an associated cost of $.22 per Mcfe.
Depreciation and Depletion Expense. Depreciation and depletion expense increased 96% to $9.9 million in fiscal 2004, as compared to $5 million in fiscal 2003. Depreciation and depletion expenses per Mcfe for our onshore properties increased to $1.46 per Mcfe during fiscal 2004 from $1.02 per Mcfe in fiscal 2003. This increase can be attributed to the acquisition of our Christensen Field in Washington County which had a depreciation and depletion expense of $2.40 per Mcfe and the acquisition of our Eland and Stadium fields which had depreciation and depletion expense of $2.74 per Mcfe.
Dry Hole Costs. We incurred dry hole costs of $2.1 million on five exploratory wells in fiscal 2004 and $537,000 on three exploratory wells in fiscal 2003.
Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Our exploration costs for fiscal 2004 of $2.4 million included an extensive 78 square mile seismic shoot in Washington County, Colorado on our South Tongue Prospect.
Drilling and Trucking Operations. In March 2004, we acquired a 50% interest in both the Big Dog Drilling Co., LLC and Shark Trucking Co., LLC. We began drilling our first well with a Big Dog rig in August 2004 and will primarily drill on our acreage. The cost associated with these two entities represents start up costs incurred through year end.
Professional Fees. Professional fees include corporate legal costs, accounting fees, shareholder relations consultants and legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to our undeveloped offshore California leases. Our professional fees increased 43% to $1.2 million for fiscal 2004, as compared to $842,000 for fiscal 2003. The increase in professional fees can be attributed largely to the compliance with the Sarbanes-Oxley Act.
General and Administrative Expense. General and administrative expense increased 60% to $6.9 million in fiscal 2004, as compared to $4.3 million in fiscal 2003. The increase in general and administrative expenses is primarily attributed to (i) the increase in technical and administrative staff and related personnel costs, (ii) the expansion of our office facility and (iii) additional bonuses earned by officers and management.
Interest and Financing Costs. Interest and financing costs remained consistent with fiscal 2003. We expensed $1.8 million for both fiscal 2004 and 2003. The decrease in interest rates during fiscal 2004 was offset by the increase in long-term debt obligations during the year.
Discontinued Operations. Included in discontinued operations are (i) income (loss) from operations of properties sold and (ii) gain (loss) on sale of oil and gas properties. We are required to re-class related revenue and expenses relating to sales of our oil and gas properties for all periods presented. During fiscal 2004, we sold our Pennsylvania properties which resulted in a gain on sale of $1.9 million. During fiscal 2003, we sold some non-strategic oil and gas properties which resulted in a gain of $277,000.
Liquidity and Capital Resources
Liquidity is a measure of a company’s ability to access cash. 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 and the sale of oil and gas properties, and through borrowings under our credit facility. On March 15, 2005, we issued 7% senior notes, unsecured, for aggregate net proceeds of $149.3 million. At the same time, we also increased our credit facility to $200.0 million with an available borrowing base of $75.0 million, $10.7 million of which was not drawn at December 31, 2005. On September 27, 2005, we completed a private placement of 5,405,418 shares of our 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 $95.0 million. The majority of the proceeds were immediately used to acquire additional oil and gas properties. On September 2, 2005 we sold our non-core Deerlick Field located in Tuscaloosa, Alabama for $28.9 million, subject to certain normal closing adjustments and on September 30, 2005, DHS completed a five-year financing arrangement for $35.0 million. Subsequent to year end, we sold certain non-operated properties (subject to certain normal closing adjustments) and issued common stock for net proceeds of $37.0 million.
The prices we receive for future oil and natural gas production and the level of production have a significant impact on 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.
We continue to examine alternative sources of long-term capital, including bank borrowings, 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, some of which are beyond our control.
We believe the availability under our Revolving Credit Facility, projected operating cash flows, additional debt and equity financings and cash on hand will be sufficient to meet the requirements of our business; however, future cash flows are subject to a number of variables, including the level of production and oil and natural gas prices. We cannot give assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to, drilling results, product pricing and future acquisition and divestitures of properties.
Company Acquisitions and Growth
We continue to evaluate potential acquisitions and property development opportunities. During the last eighteen months ended December 31, 2005, we completed the following transactions:
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 a newly created wholly owned subsidiary, CRB Partners, LLC (“CRBP”). In January 2006, Delta sold a minority interest in CRBP to a small group of investors. The Company expects to record a gain during the first quarter of 2006 as a result of closing this transaction. The Company plans to use the proceeds from such sale to initially reduce borrowings under its senior secured debt facility and to later accelerate its rate of development drilling. As a result of the transaction, Delta now owns a net interest of just over 40,000 acres in the Columbia River Basin through its remaining ownership of CRBP and additional interests in 332,000 net acres in the Columbia River Basin from previous transactions.
On November 9, 2005, DHS acquired 100% of Chapman Trucking (“Chapman”) for $4,500,000 in cash and the results of operations of the entity is included in the Company’s consolidated statement of operations since that date. The purchase was for 18 trucks and 37 trailers. Chapman will continue to market trucking services in the Casper, Wyoming area, as well as enter the rig moving market for DHS and third party drilling rigs.
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. The majority of the acquired acreage in the Columbia River Basin consolidates the Company’s current leasehold position. 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 below.
On September 27, 2005, we completed a private placement of 5,405,418 shares of our 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 $95.0 million. The proceeds were primarily used to fund the Savant transaction discussed above.
On May 4, 2005, we purchased from Savant a 14.25% back-in after project payout 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 our 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. We can, however, at any time and at our discretion, convert the interest to a cost bearing working interest by paying our proportionate share of the costs incurred in the project.
On March 31, 2005, we purchased the remaining interest in Big Dog in exchange for our interest in Shark, one of Big Dog’s rigs, certain related equipment and 100,000 shares of our restricted stock valued at $1.4 million. On April 15, 2005, we conveyed our interest in Big Dog to DHS in exchange for 4,500,000 shares of DHS restricted stock, or 90% of its issued and outstanding shares. On May 16, 2005, DHS sold 45% of its restricted stock to Chesapeake Energy, Inc. for $15 million. We currently own 49.5% of DHS. We control the board of directors and operations and have a right to the use of their rigs. As such, the operations of DHS have been consolidated into the Company.
On January 4, 2005 we acquired additional interests in the South Tongue area of Washington County and also entered into an exploration agreement for properties in Orange County, California. We paid $400,000 in cash and 135,836 shares of our common stock valued at $2.0 million, of which $1.1 million was attributable to South Tongue.
On December 15, 2004, we 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 was $59.7 million. The entire amount of the purchase price was paid in cash at the closing of the transaction, which occurred on January 21, 2005. The purchase price for the Manti properties was determined through arms-length negotiations. The purchase price was paid with increased borrowings from our existing bank credit facility. Substantially all of the assets that we acquired from Manti have been pledged as collateral under our credit facility.
On November 4, 2004, we entered into an agreement with Edward Mike Davis, LLC to acquire the balance of its back-in working interest and his overriding royalty interest in all of his ownership to the base of the Niobrara formation in the South Tongue interests in Washington County, Colorado. This agreement eliminated all future drilling commitments in Washington County. This included approximately 260,000 acres of leasehold. In addition, we acquired a 100% working interest with a 70% net revenue interest in the Magers 1-9 well in Colusa County, California. Total consideration was 650,000 shares of our common stock valued at approximately $9.4 million. Also on November 4, 2004, we entered into an agreement with Davis to acquire and possibly develop certain areas in Elbert County, Colorado. The initial cost of this transaction was 25,000 shares of our common stock valued at approximately $363,000.
On September 15, 2004, we 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, we 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, which was then a greater than 5% stockholder, for 760,000 shares of our common stock valued at $10.4 million using the five-day closing price before and after the terms of the agreement were agreed and closed, which was $13.63.
Historical Cash Flow
Our cash flow from operating activities increased 28% to $24.9 million for the six months ended December 31, 2005 compared to $19.4 million for the same period a year earlier, primarily as a result of a 53% increase in revenue and a 137% increase in non-cash depletion expense. Our net cash used in investing activities increased by 341% to $146.5 million for the six months ended December 31, 2005 compared to $33.2 million for the same period a year earlier. The increase in cash used for investing activity can be attributed to the expansion of our drilling programs in both the Rocky Mountain and Gulf Coast regions along with additional drilling rig acquisitions. Cash flow from financing activities increased to $124.9 million for the six months ended December 31, 2005 compared to $13.5 million for the same period the prior year. During the six months ended December 31, 2005, we financed our operations, acquisitions, and capital expenditures primarily with net proceeds of $95.0 million in newly issued equity and $29.2 million in net debt additions.
Our cash flow from operating activities increased 366% to $44.9 million for the year ended June 30, 2005 compared to $9.6 million for the same period a year earlier, primarily as a result of a 161% increase in revenue and a 134% increase in non cash depletion expense. Our net cash used in investing activities increased by 24% to $183.9 million for the year ended June 30, 2005 compared to $148.4 million for the same period a year earlier. The increase in cash used for investing activity can be attributed to the expansion of our drilling programs in both the Rocky Mountain and Gulf Coast regions along with additional drilling rig acquisitions. Cash flow from financing was $139.2 million for the year ended June 30, 2005 which was consistent with $138.6 for the same period the prior year. During fiscal 2005, we financed our operations primarily with debt. On March 15, 2005, we issued 7% senior unsecured notes for an aggregate amount of $150.0 million. During fiscal 2004, we financed our operations with the issuance of $98.0 million in equity and an increase in our bank credit facility.
Capital and Exploration Expenditures and Financing
Our capital and exploration expenditures and sources of financing for the six months ended December 31, 2005 and years ended June 30, 2005, 2004 and 2003 are as follows:
We anticipate our capital and exploration expenditures to range between $150.0 and $195.0 million for the year ended December 31, 2006. The timing of most of our capital expenditures is discretionary.
Sale of Oil and Gas Properties - Discontinued Operations
On August 19, 2004, we completed the sale of our interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition for $18.7 million, net of commission. We paid $8.8 million on our credit facility balance from the sale of these properties. No gain or loss was recognized on this transaction.
On September 2, 2005, we completed the sale of our interest in the Deerlick Field located in Tuscaloosa, Alabama, for net cash proceeds of $28.9 million and an effective date of July 1, 2005. We recorded a gain on sale of oil and gas properties of approximately $10.2 million. Revenues from these oil and gas properties were approximately $1.3 million, $4.9 million, $3.3 million and $3.0 million for the six months ended December 31, 2005 and the years ended June 30, 2005, 2004 and 2003, respectively.
During October 2005, we sold at auction our interest in several non-strategic fields for proceeds of $5.3 million and a gain of $1.6 million.
Contractual and Long-Term Debt Obligations
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 semiannually 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. 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.
Credit Facility
At December 31, 2005, our $200.0 million credit facility had an available borrowing base of approximately $75.0 million and $64.3 million outstanding. The temporary reduction in available borrowing base was established until certain drilling results were attained. We anticipate our available borrowing base to increase 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 facility is collateralized by substantially all of our oil and gas properties. Currently, 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) of less than 3.5 to 1. The financial covenants only include subsidiaries which we own 100%. At December 31, 2005, the Company was not in compliance with its quarterly debt covenants and restrictions, but obtained a waiver from the banks for the quarter ended December 31, 2005. In addition, the credit agreement was amended to exclude the quarter ended March 31, 2006 from the current ratio requirement.
Subsequent determinations of the borrowing base will be made by the lending banks at least semi-annually on April 1 and October 1 of each year, or as special re-determinations. 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, and (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.
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.
Term Loan - DHS
On September 30, 2005, DHS completed a financing arrangement with Guggenheim Corporate Funding, LLC (“Guggenheim”) for $35.0 million due September 30, 2010, with principal and interest payments due on the first calendar day of each quarter. The note bears interest at the Prime Rate plus 3.0%, or 10.0% at December 31, 2005. The note contains quarterly financial covenants applied to DHS on a stand-alone basis including a maximum leverage ratio of 2.5 to 1 (declining to 2.0 to 1.0 at June 30, 2006), a minimum current ratio of 1.25 to 1.0 and a minimum interest coverage ratio of 2.50 to 1, each as defined in the agreement. At December 31, 2005, DHS was not in compliance with its quarterly debt covenants and restrictions; however, on January 6, 2006 the note was amended with revised covenants effective as of December 31, 2005.
Other Contractual Obligations
Our abandonment retirement obligation arises from the plugging and abandonment liabilities for our oil and gas wells. The majority of this obligation will not occur over the next five years.
We lease our corporate office in Denver, Colorado under an operating lease which will expire in fiscal 2015. Our average yearly payments approximate $864,000 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.
Derivative instruments represent the net estimated unrealized losses for our oil and gas hedges at December 31, 2005. The ultimate settlement amounts of these hedges are unknown because they are subject to continuing market risk.
The following table summarizes our derivative contracts outstanding at December 31, 2005:
The fair value of our derivative instruments obligation was $18.2 million at December 31, 2005 and $9.2 million on February 28, 2006.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations were based upon 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 1 to our consolidated financial statements. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” 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 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 incurred to select development locations within an oil and gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to 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 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 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.
Commodity Derivative Instruments and Hedging Activities
We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize future 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. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as other expense or income in the consolidated statement of operations.
Asset Retirement Obligation
We account for our asset retirement obligations under SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting principle on prior years related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. 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 No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 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
The Company follows SFAS No. 109, “Accounting for Income Taxes,” to account for its deferred tax assets and liabilities. Under SFAS No. 109, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carry forwards. 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, the Company maintains a valuation allowance against a portion of its deferred tax assets. The Company will continue to monitor facts and circumstances in its reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, the Company 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.
Recently Issued Accounting Standards and Pronouncements
In May 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“Statement 154”). SFAS 154 requires retrospective application to prior periods’ financial statements for changes in accounting principle, 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 FAS 154 is not expected to have a material impact on our condensed consolidated results of operations, financial position or cash flows.
In April 2005, the FASB issued Staff Position 19-1, (“FSP 19-1”) “Accounting for Suspended Well Costs”. 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.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange and interest rates and commodity prices. We do not use financial instruments to any degree to manage foreign currency exchange and interest rate risks and do not hold or issue financial instruments to any degree for trading purposes. All of our revenue and related receivables are payable in U.S. dollars.
Market Rate and Price Risk
We began to hedge a portion of our oil and gas production using swap and collar agreements. The purpose of these hedge agreements is to provide a measure of stability to our cash flow in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk.
The current derivative contracts cover approximately 32% of our estimated 2006 production. Assuming production and the percent of oil and gas sold remained unchanged from the six months ended December 31, 2005, a hypothetical 10% decline in the average market price the Company realized during the six months ended December 31, 2005 on unhedged production would reduce the Company’s oil and natural gas revenues by approximately $6.2 million on an annual basis.
Interest Rate Risk
We were subject to interest rate risk on $99.3 million of variable rate debt obligations at December 31, 2005. The annual effect of a ten percent change in interest rates would be approximately $782,000. The interest rate on these variable rate debt obligations approximates current market rates as of December 31, 2005.
Item 8.
Item 8. Financial Statements and Supplementary Data
Financial Statements are included and begin on page. 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.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
None.
Item 9A.
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, 2005. 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.
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, 2005, 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, 2005, 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 management’s assessment 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.
PART III
The information required by Part III, Item 10
Item 11 “Executive Compensation,” Item 12
Item 15. Exhibits, Financial Statement Schedules
(a)(1)
Financial Statements.
(a)(2)
Financial Statement Schedules. None.
(a)(3)
Exhibits. The Exhibits listed in the Index to Exhibits appearing at page 57 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with a “*”.
EXHIBITS LIST
*
Management contracts and compensatory plans.
Report of Independent Registered Public Accounting Firm
The Board of Directors
Delta Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation and subsidiaries as of December 31, 2005 and June 30, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for the six months ended December 31, 2005 and years ended June 30, 2005, 2004 and 2003. 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, 2005 and June 30, 2005 and 2004, and the results of their operations and their cash flows for the six months ended December 31, 2005 and each of the years ended June 30, 2005, 2004 and 2003, 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), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of the Sponsoring Organizations of the Treadway Commission, and our report dated March 9, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
As discussed in footnote 2 to the consolidated financial statements, Delta Petroleum Corporation adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of July 1, 2002.
As also discussed in footnote 2 to the consolidated financial statements, Delta Petroleum Corporation adopted Statement of Financial Accounting Standards No. 123(R), Share Based Payment, as of July 1, 2005.
KPMG
Denver, Colorado
March 9, 2006
Report of Independent Registered Public Accounting Firm
The Board of Directors
Delta Petroleum Corporation:
We have audited management’s assessment, included in Item 9A, Management’s Report on Internal Control over Financial Reporting, that Delta Petroleum Corporation and subsidiaries (Delta or the Company) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Delta’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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe 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, management’s assessment that Delta maintained effective internal control over financial reporting as of December 31, 2005 is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Delta maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Delta and subsidiaries as of December 31, 2005 and June 30, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for the six months ended December 31, 2005 and the years ended June 30, 2005, 2004 and 2003 and our report dated March 9, 2006 expressed an unqualified opinion on those consolidated financial statements.
KPMG
Denver, Colorado
March 9, 2006
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’
EQUITY AND COMPREHENSIVE INCOME (LOSS)
See accompanying notes to consolidated financial statements.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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 and 2005, owns a 49.5% interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. Delta has the right to use all of the rigs on a priority basis, although approximately half 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.
At December 31, 2005, 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 we transferred our 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”). Subsequent to year-end, we sold a minority interest in CRBP. We have retained the majority ownership in, and are the manager of, CRBP. This sale did not involve any of our operated 100% leasehold of approximately 332,000 net acres in the Columbia River Basin.
(2) Summary of Significant Accounting Policies
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of Delta, Amber, Piper, CRBP and DHS (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation. As Amber is in a net stockholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods. The Company has no interests in any unconsolidated entities other than its investment in a liquid natural gas LLC which is recorded at its cost, nor does it have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.
Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures. 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 2005 presentation. Such reclassifications had no effect on net income.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
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 is a transitional report, and includes information for the six-month transitional period ended December 31, 2005 and for the twelve-month periods ended June 30, 2005, 2004 and 2003. The unaudited financial information for the six-month period ended December 31, 2004 is as follows:
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
The Company classifies its investment securities as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 115 (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.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
Assets Held for Sale
Assets held for sale as of December 31, 2005 represent the cost basis related to the 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin that were transferred during December 2005 to a newly created wholly owned subsidiary, CRB Partners, LLC. In January 2006, Delta sold a minority interest in CRB Partners, LLC to a small group of investors. The Company expects to record a gain of during the first quarter of 2006 as a result of closing the transaction.
Inventories
Inventories consist of pipe, other production equipment and natural gas placed in storage. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value.
Minority Interest
Minority interest represents the 50.5% (45% for Chesapeake Energy Corporation, 5.5% for DHS executive officers and management) investors of DHS Drilling Company at December 31, 2005 and June 30, 2005. Prior to forming DHS, the Company owned a 50% interest in Big Dog Drilling Co., LLC (“Big Dog”) and a 50% interest in Shark Trucking Co., LLC (“Shark”). The remaining net assets of Big Dog were ultimately acquired and, together with the interest previously owned, were contributed to DHS.
Revenue Recognition
Oil and Gas
Revenues are recognized when title to the products transfer 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. To the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves, a receivable or liability is recognized. As of December 31, 2005 and June 30, 2005 and 2004, 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.
Drilling and Trucking
We earn our contract drilling revenues under daywork. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. The cost 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.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
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 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 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.
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.
Depreciation, depletion and amortization of property and equipment for the six months ended December 31, 2005 and the fiscal years ended June 30, 2005, 2004 and 2003 were $20.4 million, $23.2 million, $9.9 million and $5.0 million, respectively.
Drilling equipment and other property and equipment are 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.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 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 No. 144 are permanent and may not be restored in the future.
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 years ended June 30, 2005, 2004 and 2003.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
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 June 30, 2005, 2004 and 2003.
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, included in exploration expenses, for the full impairment of the remaining leasehold costs related to the prospect.
Goodwill
Goodwill represents the excess of the cost of the acquisition of Chapman Trucking in November 2005 over the fair value of the assets acquired. For goodwill and intangible assets recorded in the financial statements, an impairment test will be performed at least annually in accordance with the provisions of SFAS No. 142.
Asset Retirement Obligations
In July 2001, the Financial Accounting Standards Board (“FASB”) approved for issuance SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting principle on prior years of $20,000, net of tax effects, related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. 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 six months ended December 31, 2005 and fiscal years ended June 30, 2005 and 2004.
In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 143. The Company applied the guidance of FIN 47 beginning July 1, 2005 resulting in no impact on its financial statements.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
Comprehensive Income (Loss)
Comprehensive income (loss) includes all changes in equity during a period. The components of comprehensive income (loss) for the six months ended December 31, 2005 and fiscal years ended June 30, 2005, 2004 and 2003 are as follows (in thousands):
Financial Instruments
The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents 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 long-term debt was 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.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
Stock Option Plans
The Company previously 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 No. 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 No. 123R effective July 1, 2005 using the modified prospective method and recognized compensation expense related to stock options of $2.0 million, relating to employee provided services during the six months ended December 31, 2005.
For fiscal years prior to the adoption of SFAS No. 123R, had compensation cost for the Company’s stock-based compensation plan been determined using the fair value of the options at the grant date, the Company’s net income for the fiscal years ended June 30, 2005, 2004 and 2003 on a pro forma basis would have been as follows:
Income Taxes
The Company uses the asset and liability method of accounting for income taxes as set forth in Statement of Financial Accounting Standards No. 109 (SFAS No. 109), “Accounting for Income Taxes.” 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 No. 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.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
Earnings (Loss) per Common Share
Basic earnings (loss) per share is computed by dividing net earnings (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, stock options 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 impact 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.
Recently Issued Accounting Standards and Pronouncements
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 (“Statement 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 FAS 154 is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.
In April 2005, the Financial Accounting Standards Board (“FASB”) issued Staff Position 19-1, (“FSP 19-1”) “Accounting for Suspended Well Costs.” 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 six months ended December 31, 2005:
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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 $11.0 million, $10.9 million and $10.8 million at December 31, 2005, June 30, 2005 and 2004, 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 the Company’s 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.
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 intend to proceed with exploration and development plans under the terms and conditions of the operating agreement.
Even though the Company is not the designated operator of the properties and regulatory approvals have not been obtained, the Company believes exploration and development activities on these properties will occur and is committed to expend funds attributable to its interests in order to proceed with obtaining the approvals for the exploration and development activities.
Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair value of its property interests are in excess of their carrying value at December 31, 2005, June 30, 2005 and June 30, 2004 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 forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. 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 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.
On June 22, 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. The delays have prevented the property owners from submitting for approval an exploration plan on four of the properties. If and when plans are submitted for approval, they are subject to review for consistency with the CZMA, and by the MMS for other technical requirements.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(3) Oil and Gas Properties, Continued
As the ruling in the Norton case currently stands, the United States has made a consistency determination under the CZMA in accordance with the Court’s order and the leases are still valid. If the leases are found not to be valid for some reason in the future, it would appear that the leases would become impaired even though the Company would undoubtedly proceed with its litigation. 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.
None of these leases is currently impaired, but in the event that there is some 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.
Delta and its majority-owned subsidiary, Amber Resources Company of Colorado, are among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. government has materially breached the terms of forty undeveloped federal leases, some of which are part of Delta’s offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case, that a 1990 amendment to the Coastal Zone Management Act that required the government to make a consistency determination prior to granting lease suspension requests in 1999, constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.
The suit seeks compensation for the lease bonuses and rentals paid to the Federal government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. The company owns approximately 12% of the lease bonus costs that are the subject of the lawsuit. In addition, the Company’s claim for exploration costs and related expenses will also be substantial. In the event, however, that Delta receives any proceeds as the result of such litigation, it will be obligated to pay a portion of any amount received by it 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.
On November 15, 2005, the United States Court of Federal Claims issued a ruling in the suit granting the plaintiffs’ motion for 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. The court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold thirty six out of the total forty offshore California federal leases that are the subject of the litigation. The Court further 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.
Delta and Amber are among the current lessees of the thirty six leases that are the subject of the ruling. Together with Amber, Delta’s net share of the $1.1 billion award is approximately $121 million. The final ruling in the case will not be made until the Court addresses the plaintiffs’ additional claims regarding the four additional leases, as well as their claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(3) Oil and Gas Properties, Continued
in the disputed lease area, and other matters. The final ruling, including the ruling made on November 15, will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted.
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.
Fiscal 2005 - Acquisitions
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. The purchase price for the Manti properties was determined through arms-length negotiations. The purchase price was paid with increased borrowings on the Company’s bank credit facility. Substantially all of the assets that were acquired from Manti have been pledged as collateral for the bank credit facility.
On June 29, 2004, the Company completed the acquisition of substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc. (“Alpine”) for $122.5 million, which was funded with $68.4 million in net proceeds that the Company received from a $72.0 million private placement of 6 million shares of its restricted common stock to institutional investors at a purchase price of $12.00 per share, and from borrowings of $54.1 million under its senior credit facility. On August 19, 2004 the Company sold a portion of these assets to Whiting Petroleum Corporation for $18.7 million in net proceeds. There was no gain or loss on the sale of these assets.
The following unaudited pro forma condensed consolidated statement of operations information assumes that the Manti and Alpine property acquisitions occurred as of July 1, 2003:
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(3) Oil and Gas Properties, Continued
The above unaudited condensed pro forma consolidated statements of operations information, based on the historical producing property operating results of Manti, Alpine and Delta, are not necessarily indicative of the results of operations if Delta would have acquired the Manti and Alpine properties at July 1, 2003.
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.
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.
Fiscal 2004 - Acquisitions
During fiscal 2004 the Company made other producing property acquisitions in North Dakota of approximately 2.4 Bcfe for a total consideration of $4.2 million through the issuance 773,500 shares of the Company’s common stock.
During the period from September of 2003 through July of 2004 the Company completed a series of transactions with Edward Mike Davis and certain unrelated individuals which resulted in an acquisition of a producing property and approximately 360,000 acres of undeveloped properties in the Company’s North and South Tongue prospects located in Washington and Yuma Counties, Colorado, and an interest in producing and non-producing properties located in Colusa, Orange and Los Angeles Counties, California. Through these acquisitions the Company obtained an aggregate of approximately 6 Bcfe in proved producing reserves and a significant drilling inventory for a total consideration of approximately $8.0 million in cash and 2,551,000 shares of the Company’s common stock.
During fiscal 2004, the Company invested an aggregate of $1.0 million for a 6.25% interest as a member of Crystal Energy, LLC, which is an unaffiliated Delaware limited liability company that is currently in the process of attempting to obtain the rights to own and operate a liquid natural gas facility from Platform Grace, which is an existing platform located offshore California. If the limited liability company is successful in obtaining these rights, it intends to engage in the business of accepting and vaporizing liquid natural gas delivered by liquid natural gas tankers, transporting the vaporized liquid natural gas through proprietary gas pipelines and selling the vaporized natural gas to third party customers located in California. As of December 31, 2005, the limited liability company had not yet engaged in any revenue producing activities.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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.
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.
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. The net profit earned on these assets during the six months ended December 31, 2005 was $501,000 and has been presented in discontinued operations.
On August 19, 2004, the Company completed the sale of certain interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $18.7 million, net of certain commissions. The Company paid $8.8 million toward its credit facility from the proceeds of the sale of these properties. There was no gain or loss on this sale transaction and the net profit earned on these assets during the quarter, since the acquisition, of $729,000 has been shown in discontinued operations net of taxes of $280,000.
On March 31, 2004, the Company completed the sale of all of its Pennsylvania properties to Castle Energy Corporation, a 25% stockholder of Delta at March 31, 2004, for cash consideration of $8 million with an effective date of January 1, 2004 and resulted in a gain on sale of oil and gas properties of $1.9 million. Revenues from the sale of these oil and gas properties were approximately $1.2 million for the year ended June 30, 2004 and $1.8 million for the year ended June 30, 2003.
On December 5, 2003, the Company completed the sale of certain properties located in Texas to Sovereign Holdings, LLC for cash consideration of $2.6 million. The effective date of the transaction was January 1, 2004 and it resulted in a loss on the sale of oil and gas properties of $28,000. Revenues attributed to the sale of these oil and gas properties were approximately $537,000 for the year ended June 30, 2004 and $1.2 million for the year ended June 30, 2003.
During the year ended June 30, 2003, the Company disposed of additional non-strategic oil and gas properties and related equipment to unaffiliated entities in addition to the dispositions described above. The Company has received proceeds from these sales of $850,000 and such sales resulted in a net gain on sale of oil and gas properties of $277,000 for the year ended June 30, 2003.
(4) DHS Drilling Company
On April 15, 2005, the Company acquired a 49.5% 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 the Delta’s common stock valued at $1.4 million based on the closing stock price on March 31, 2005, its 50% interest in Shark and certain drilling equipment. Delta has the right to use all of the rigs on a priority basis, although approximately half are currently working for third party operators.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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 Delta’s 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, make certain
investments, sell assets, consolidate, merge or transfer all or substantially all of the assets of the Company and restricted subsidiaries. These covenants may limit the discretion of the Company’s management in operating the Company’s business. The Company was in compliance with these covenants as of December 31, 2005. The notes have been guaranteed by certain of the Company’s subsidiaries (See Footnote 12, “Guarantor Financial Information”). The fair value of the Company’s senior notes at December 31, 2005 was $138.4 million.
Credit Facility
On June 30, 2005, the Company amended its credit facility with Bank One, N.A., Bank of Oklahoma N.A., U.S. Bank National Association and Hibernia National Bank (the “Banks”). At December 31, 2005, the $200.0 million credit facility had an available borrowing base of approximately $75.0 million and $64.3 million outstanding. The reduction in available borrowing base was established until certain drilling results were attained. 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 rate at December 31, 2005 approximated 7%. The loan was collateralized by substantially all of the Company’s oil and gas properties. Currently, the Company is required to meet certain financial covenants which include a current ratio of 1 to 1, net of derivative instruments of $12.4 million and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 3.5 to 1. The financial covenants only include subsidiaries which the Company owns 100%. At December 31, 2005, the Company was not in compliance with its quarterly debt covenants and restrictions, but obtained a waiver from the banks for the quarter ended December 31, 2005. In addition, the credit agreement was amended to exclude the quarter ended March 31, 2006 from the current ratio requirement.
Kaiser Francis Oil Company - Debt
On December 1, 1999, the Company borrowed $8 million at prime plus 1-1/2% from Kaiser Francis Oil Company. The proceeds from this loan were used to pay off existing debt and the balance of the Point Arguello Unit and New Mexico acquisitions. During the third quarter of fiscal 2004, the loan was paid in full.
Term Loan - DHS
On September 30, 2005, DHS completed a financing arrangement with Guggenheim Corporate Funding, LLC (“Guggenheim”) for $35.0 million due September 30, 2010, with principal and interest payments due on the first calendar day of each quarter. The note bears interest at the Prime Rate plus 3.0%, or 10.25% at December 31, 2005. The note contains quarterly financial covenants applied to DHS on a stand-alone basis including a maximum leverage ratio of 2.5 to 1 (declining to 2.0 to 1.0 at June 30, 2006), a minimum current ratio of 1.25 to 1.0 and a minimum interest coverage ratio of 2.50 to 1, each as defined in the agreement. At December 31, 2005, DHS was not in compliance with its quarterly debt covenants and restrictions; however, on January 6, 2006 the note was amended with revised covenants effective as of December 31, 2005 and additional funds were borrowed (See Note 18, Subsequent Events).
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(5) Long Term Debt, Continued
Maturities of long-term debt, in thousands of dollars based on contractual terms are as follows:
(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, 2005, June 30, 2005 and June 30, 2004, 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 six months ended December 31, 2005 and fiscal years ended June 30, 2005, 2004 and 2003, the Company acquired oil and gas properties for 50,000, 1,571,000, 3,728,000, and 200,000 shares of the Company’s common stock, respectively. The shares were valued at $799,000, $22.2 million, $30.5 million and $922,000, respectively, based on the market price of the shares at the time of issuance.
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.
The Company raised additional capital through the sale of 10,000,000 shares of its common stock, net of commissions, of $97.9 million for the year ended June 30, 2004. Offering costs of $6.1 million consisted of cash commissions and legal services relating to the transactions and were accounted for as an adjustment to stockholders’ equity.
Non-Qualified Stock Options - Directors and Employees
On May 31, 2002 at the annual meeting of the shareholders, the shareholders ratified the Company’s 2002 Incentive Plan (the “Incentive Plan”) under which it reserved up to an additional 2,000,000 shares of common stock. This plan supersedes the Company’s 1993 and 2001 Incentive Plans.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(6) Stockholders’ Equity, Continued
Incentive awards under the Incentive 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. Options are generally issued at market price at the date of grant with various vesting and expiration terms based on the discretion of the Incentive Plan Committee.
A summary of the stock option activity under the Company’s various plans and related information for the six months ended December 31, 2005 follows:
The total intrinsic value of options exercised during the six months ended December 31, 2005 and the years ended June 30, 2005, 2004 and 2003 were $3.2 million, $24.9 million, $3.4 million, and $688,000, respectively.
A summary of Company’s non-vested stock options and related information for the six months ended December 31, 2005 follows:
The weighted average remaining requisite service period of the non-vested stock options was 1.35 years.
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 years ended June 30, 2005, 2004 and 2003, respectively, risk-free interest rates of 4.28%, 4.32% and 2.84%, dividend yields of 0%, 0% and 0%, volatility factors of the expected market price of the Company’s common stock of 43.97%, 50.43% and 65.32% and a weighted-average expected life of the options of 4.76, 5.56 and 4.16 years. The fair value of the options granted at the grant date is $8.0 million, $10.2 million and $713,000 for the years ended June 30, 2005, 2004 and 2003, respectively. No options were granted during the six months ended December 31, 2005.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(6) Stockholders’ Equity, Continued
The Company has issued options to its non-employee Directors and recorded stock option expense in the amount of $329,000 and $114,000 for years ended June 30, 2004 and 2003, respectively, for options issued below market prices.
Restricted Stock - Directors and Employees
A summary of the restricted stock activity under the Company’s plan and related information for the six months ended December 31, 2005 follows:
The total fair value of restricted stock vested during the six months ended December 31, 2005 was $697,000. No restricted stock vested during any of the prior periods presented.
At December 31, 2005, the total unrecognized compensation cost related to the non-vested portion of restricted stock and stock options was $5.8 million which is expected to be recognized over a weighted average period of 4.75 years.
Cash received from exercises under all share-based payment arrangements for the six months ended December 31, 2005 and years ended June 30, 2005, 2004, and 2003 was $625,000, $132,000, $3.6 million and $975,000, respectively. Tax benefits realized from the stock options exercised during the six months ended December 31, 2005 and years ended June 30, 2005, 2004, and 2003, was zero, $1.3 million, zero and zero, respectively. During the six months ended December 31, 2005, $6.6 million 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.
Non-Qualified Stock Options - Non-Employees
Previously, the Company had also issued options to non-employees and recorded stock option expense in the amount of $10,000 to non-employees for the year ended June 30, 2003. As of June 30, 2005, all such options had expired or been exercised.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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.
The Company adopted a 401k 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 401k 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.
For the six months ended December 31, 2005 and fiscal years ended June 30, 2005, 2004 and 2003 the Company contributed $240,000, $291,000, $262,000 and $147,000, respectively, under the plans.
(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 SFAS No. 133. Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss, to the extent the hedge is effective, and such amounts are reclassified to realized gain (loss) on derivative instruments as the associated production occurs.
At December 31, 2005, all of the Company’s derivative contracts are 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 forgoing the benefit of price increases in excess of the ceiling price on the hedged production.
Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk management.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(8) Commodity Derivative Instruments and Hedging Activities, Continued
The following table summarizes our derivative contracts outstanding at December 31, 2005:
The fair value of the Company’s net derivative instruments obligation was a liability of approximately $18.2 million at December 31, 2005 and $9.2 million on February 28, 2006.
The net realized losses from hedging activities recognized in the Company’s statements of operations were $8.0 million, $960,000, $859,000 and $1.9 million for the six months ended December 31, 2005 and years ended June 30, 2005, 2004 and 2003, respectively. These losses are recorded as a decrease in revenues.
During the six months ended December 31, 2005, the Company’s gas derivatives became ineffective under SFAS No. 133 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 the Company’s oil and gas production. The change in fair value of our gas contracts during the six months ended December 31, 2005 are reflected in earnings, as opposed to previously being disclosed in other comprehensive income (loss), a component of stockholders’ equity. As a result, the Company recorded a $9.9 million unrealized loss in its statement of operations as a component of other income (expense). Based on the estimated fair value of the derivative contracts at December 31, 2005, the Company expects to reclassify net losses of $6.0 million into earnings related to derivative contracts during the next twelve months; however, actual gains and losses recognized may differ materially.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(9) Income Taxes
The Company accounts for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes (“SFAS” 109). Income tax expense (benefit) attributable to income from continuing operations consisted of the following for the six months ended December 31, 2005 and fiscal years ended June 30, 2005, 2004 and 2003.
Income from continuing operations before taxes consists of the following for the six months ended December 31, 2005 and the fiscal years ended June 30, 2005, 2004 and 2003.
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:
Included in the consolidated statement of operations as a component of discontinued operations for the six months ended December 31, 2005 is a $7.4 million deferred tax provision on the sale and operations of properties that were sold during the period.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(9) Income Taxes, Continued
Deferred tax assets (liabilities) are comprised of the following at December 31, 2005, June 30, 2005 and June 30, 2004:
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, 2005 is approximately $6.6 million 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.
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 taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future table income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 2005. The valuation allowance at December 31, 2005 relates primarily to a subsidiary’s net operating loss that cannot be used to reduce taxable income generated by other members of the consolidated tax group and a deferred tax asset generated by a subsidiary that is not consolidated for
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(9) Income Taxes, Continued
tax purposes and does not have a history of earnings. The amount of the deferred tax asset considered realizable could be reduced if estimates of future taxable income during the carry-forward period are reduced.
At December 31, 2005, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes as follows:
Regular tax net operating loss
$ 57,680
Alternative minimum tax net operating loss
54,600
If not utilized, the tax net operating loss carryforwards will expire for 2006 through 2025. At December 31, 2005, the Company had $1.1 million of net operating loss carryforward in Australia with no expiration date.
The Company’s net operating losses are scheduled to expire as follows (in thousands):
(10) Related Party Transactions
Transactions with 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. James Wallace, one of our directors, 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 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 upon completion of the Guggenheim financing discussed in Footnote 5, Long Term Debt.
Until March 12, 2003, the Company’s Board of Directors had granted each of our officers the right to participate in the drilling, on the same terms as the Company, in up to a five percent (5%) working interest in any well drilled, re-entered, completed or re-completed by the Company on its acreage (provided that any well to be re-entered or re-completed was then producing economic quantities of hydrocarbons). On March 12, 2003, the Board of Directors rescinded this right. The officers did not participate in any Company wells since fiscal 2003.
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 $58,000, $100,000, $66,000 and $108,000 for their respective 1% ORRI during the six months ended December 31, 2005 and fiscal 2005, 2004 and 2003, respectively.
The Company’s officers have employment agreements which, among other things, include termination and change of control clauses.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(10) Related Party Transactions, Continued
Accounts Receivable Related Parties
At December 31, 2005, the Company had $54,000 of receivables from related parties. 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:
(12) Guarantor Financial Information
Delta (“Issuer”) issued 7% Senior Notes (“Bond Offering”) on March 15, 2005, for the aggregate amount of $150.0 million, which pay interest semiannually on April 1st and October 1st and mature in 2015. The proceeds were used to refinance debt outstanding under the Company’s credit facility. This Bond Offering is guaranteed by all of the 100% owned subsidiaries of the Company at the time of the Bond Offering (“Guarantors”). The Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantee the performance and payment when due of all the obligations under the Bond Offering. Big Dog, Shark, DHS and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Bond Offering.
The following financial information sets forth the Company’s condensed consolidating balance sheets as of December 31, 2005 and June 30, 2005 and 2004, the condensed consolidating statements of operations for the six months ended December 31, 2005 and the years ended June 30, 2005, 2004 and 2003 and the condensed consolidating statements of cash flows for the six months ended December 31, 2005 and years ended June 30, 2005, 2004 and 2003 (in thousands).
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(12) Guarantor Financial Information, Continued
Condensed Consolidated Balance Sheet
December 31, 2005
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Operations
Six Months Ended December 31, 2005
Condensed Consolidated Statement of Cash Flows
Six Months Ended December 31, 2005
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(12) Guarantor Financial Information, Continued
Condensed Consolidated Balance Sheet
June 30, 2005
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Operations
Year Ended June 30, 2005
Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2005
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(12) Guarantor Financial Information, Continued
Condensed Consolidated Balance Sheet
Year Ended June 30, 2004
Condensed Consolidated Statement of Operations
Year Ended June 30, 2004
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2004
Condensed Consolidated Statement of Operations
Year Ended June 30, 2003
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2003
(13) Commitments
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 six months ended December 31, 2005 and years ended June 30, 2005, 2004 and 2003 was approximately $432,000, $491,000, $311,000 and $210,000, respectively. The following table summarizes the future minimum payments under all non-cancelable operating lease obligations:
The Company has entered into agreements with four executive officers which provide for severance payments, two 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. The agreements expire no later than December 31, 2006, subject to automatic annual one-year renewals until cancelled by the Company.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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 six months ended December 31, 2005 and year ended June 30, 2005. Prior to the fiscal year ended June 30, 2005, the Company only operated in the Oil and Gas segment.
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.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(15) Selected Quarterly Financial Data (Unaudited)
(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.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(16) Disclosures About Capitalized Costs, Costs Incurred and Major Customers
Capitalized costs related to oil and gas activities are as follows:
Costs incurred (1) in oil and gas activities are as follows:
(1) Included in costs incurred are asset retirement obligation costs for all periods presented.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(16) Disclosures About Capitalized Costs, Cost Incurred and Major Customers, Continued
A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, is as follows:
The Company’s sales of oil and gas to individual customers which exceeded 10% of the Company’s total oil and gas sales for the six months ended December 31, 2005 and the years ended June 30, 2005, 2004 and 2003 were:
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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.
Estimates of our oil and natural gas reserves and present values as of December 31, 2005, and June 30, 2005, 2004 and 2003 are derived from reserve reports prepared by Ralph E. Davis Associates, Inc., our independent reserve engineers with respect to onshore reserves, or Mannon Associates, our independent reserve engineers with respect to offshore reserves.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(17) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
A summary of changes in estimated quantities of proved reserves for the six months ended December 31, 2005 and the years ended June 30, 2005, 2004 and 2003 is as follows:
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(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 six months ended December 31, 2005 and the fiscal years ended June 30, 2005, 2004 and 2003 are as follows:
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(18) Subsequent Events
Castle Acquisition
As announced on November 8, 2005, Delta has entered into a merger agreement with Castle Energy Corporation (“Castle”) that has been approved by both Boards of Directors. Delta will acquire Castle, which holds 6,700,000 shares of Delta, and would issue 8,500,000 shares of its common stock to Castle’s stockholders, for a net issuance of 1,800,000 shares of common stock. Castle also has additional assets of approximately $22.4 million which is comprised of cash, producing oil and gas properties located in Pennsylvania and West Virginia, and certain other assets. The merger is subject to the approval of the Castle stockholders and is expected to close during the first half of 2006. On February 17, 2006, Delta and Castle amended the merger agreement to extend the merger completion date from April 1, 2006 to May 1, 2006.
DHS Term Loan Amendment
On January 6, 2006, DHS amended its Guggenheim note to provide for an additional $10.0 million in borrowings and amend certain of the financial covenants as follows. The covenant for Maximum Consolidated Leverage Ratio of 2.5 to 1 (declining to 2.0 to 1.0 at June 30, 2006) was amended to a ratio of 3.0 to 1, 2.75 to 1, and 2.50 to 1 for the quarters ending December 31, 2005, March 31, 2006, and June 30, 2006 respectively. For subsequent quarters, the ratio is 2.00 to 1, as per the original covenants. Additionally, the current ratio covenant was modified, eliminating the current portion of long term debt from the current liabilities component of the ratio. The Minimum Consolidated Interest Coverage Ratio was not amended. The amended note remains due on September 30, 2010, with quarterly principal payments of $2.25 million beginning April 1, 2006, and one balloon payment on September 30, 2010 of $2.75 million. The interest rate on the note was modified to Prime plus 3.5% until such time as, one, the Maximum Consolidated Leverage Ratios complies with the original ratios, and, two, the ratio of the long term debt to the appraised value of the Company’s equipment is equal to or less than 55%. When the additional $10 million was secured, the ratio was 57% ($45 million outstanding on loan/$78.95 million appraised value). After the first quarterly payment in January 2006, the ratio dropped to 55% ($43.25 million outstanding on loan/$78.95 million appraised value). When the ratios on the original covenant are achieved and the appraised value ratio is 55% or lower, the interest rate will change to the original rate (Prime plus 3.0%). Financing costs of $100,000 were incurred in conjunction with the amendment, and will be amortized over the remaining life of the note.
CRB Sale
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 a newly created wholly owned subsidiary, CRB Partners, LLC. In January 2006, Delta sold a minority in CRB Partners, LLC. The Company expects to record a gain of during the first quarter of 2006 as a result of the transaction. The Company plans to use the proceeds from such sale to initially reduce borrowings under its senior secured debt facility and to later accelerate its rate of development drilling. As a result of the transaction, Delta now owns a net interest of just over 40,000 acres in the Columbia River Basin through its remaining ownership of CRB Partners, LLC and additional interests in 332,000 net acres in the Columbia River Basin from previous transactions.
DHS Rig Acquisitions
On January 26, 2006, Delta Petroleum purchased Rooster Drilling Company for 350,000 shares of Delta common stock valued at $8.2 million. Delta plans to contribute Rooster Drilling to DHS Drilling Company. Rooster Drilling owns one drilling rig, which will become DHS Drilling Company Rig 15. The rig is an Oilwell 66, with a depth capacity of 12,000 feet. The rig is located in Wyoming and is under contract to drill 9 wells (or minimum 100 days), in the Big Piney area of Wyoming.
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005 and June 30, 2005, 2004 and 2003
(18) Subsequent Events, Continued
In February 2006, DHS committed to purchase a Kremco 750G drilling rig for $4.75 million. The rig is a 500 horsepower rig, with a depth rating of 10,000 feet. The rig, currently located in Canada, will be purchased from a dealer in Casper, Wyoming, with delivery expected in March 2006. DHS will take delivery of the rig in Casper, Wyoming, and after upgrades in the DHS yard in Casper, the rig is scheduled to commence work in the Rocky Mountain region in the second quarter, 2006.
Central Utah Acquisition
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 acres in the central Utah hingeline play for a purchase price of $24 million in cash and 673,000 shares of common stock. The agreement is effective for all purposes as of January 26, 2006. Armstrong will retain the remaining 35% working interest in the acreage. As part of the transaction, Delta will 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 is expected to begin during 2006. In conjunction with the Central Utah Acquisition, Delta filed a registration statement with the Securities and Exchange Commission and sold 1.5 million shares of common stock. The net proceeds of $33.9 million from the offering were used to fund the cash portion of the acquisition purchase price and for general corporate purposes.
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.
Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
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 7th day of March, 2006.
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.
INDEX TO EXHIBITS
*
Management contracts and compensatory plans.