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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
Form 10-K
þ | ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
for the fiscal year ended June 30, 2005
o | TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
for the transition period from .
Commission File No. 0-16203
DELTA PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Colorado (State or other jurisdiction of incorporation or organization) | 84-1060803 (I.R.S. Employer Identification No.) |
370 17th Street, Suite 4300 Denver, Colorado (Address of principal executive offices) | 80202 (Zip Code) |
Registrant’s telephone number, including area code: (303) 293-9133
Securities registered under Section 12(b) of the Act: None
Securities registered under to Section 12(g) of the Act:
Common Stock, $.01 par value
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.þ Yeso No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.o
Indicate by a check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act)þ Yes Noo
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No o
The aggregate market value as of September 12, 2005 of voting stock held by non-affiliates of the registrant was approximately $644,223,000.
As of September 12, 2005, 42,170,000 shares of registrant’s Common Stock, $.01 par value, were issued and outstanding.
Documents incorporated by reference: The information required by Part III of this Form 10-K is incorporated by reference to the Company’s Definitive Proxy Statement for the Company’s 2005 Annual Meeting of Shareholders.
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The terms “Delta,” “Company,” “we,” “our,” and “us” refer to Delta Petroleum Corporation and its subsidiaries unless the context suggests otherwise.
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CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. These statements may include projections and estimates concerning the timing and success of specific projects and our future (1) income, (2) oil and gas production, (3) oil and gas reserves and reserve replacement, (4) capital spending, and (5) other matters related to our business. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Sometimes we will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this report, the matters discussed in this report are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially.
We believe the factors discussed below are important factors that could cause actual results to differ materially from those expressed in a forward-looking statement made herein or elsewhere by us or on our behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our shareholders that they should (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere, and all of such forward-looking statements are qualified by this cautionary statement.
— | Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market demand and changes in the political, regulatory and economic climate and other factors that affect commodities markets generally and are outside of our control. | ||
— | Projecting future rates of oil and gas production is inherently imprecise. Producing oil and gas reservoirs generally have declining production rates. | ||
— | All of our reserve information is based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves. | ||
— | Changes in the legal, political and/or regulatory environment could have a material adverse effect on our future results of operations and financial condition. Our ability to economically produce and sell our oil and gas production is affected and could possibly be restrained by a number of legal, political and regulatory factors, particularly with respect to our offshore California properties which are the subject of significant political controversy due to environmental concerns. | ||
— | Our drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids. |
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PART I
Item 1. DESCRIPTION OF BUSINESS
General
Delta Petroleum Corporation (“Delta,” “we” or “us”) is 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 Rocky Mountain and Gulf Coast regions, which comprise the majority of our proved reserves, production and long-term growth prospects. We have a significant drilling inventory that consists of proved and unproved locations, the majority of which are located in our Rocky Mountain development projects. 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 three-fourths of our undeveloped acreage is located. We retain a high degree of operational control over our asset base, with an average working interest in excess of 90% as of June 30, 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 currently have an ownership interest in a drilling company, providing the benefit of a preferential right to use its drilling rigs in the Rocky Mountain region which allows us to have a priority to drill our wells. 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.
On September 14, 2005, our Board of Directors made the decision to change our year end to December 31.
Our principal executive offices are located at 370 17th Street, Suite 4300, Denver, Colorado 80202. Our telephone number is (303) 293-9133.
The following table presents information regarding our primary oil and gas areas of operations as of June 30, 2005:
Proved | % | 2005 | ||||||||||||||
Reserves | Natural | % Proved | Production | |||||||||||||
Areas of Operations | (Bcfe)(1) | Gas | Developed | (MMcfe/d) (2) | ||||||||||||
Rocky Mountain Region | 39.4 | 90.2 | % | 35.3 | % | 6.7 | ||||||||||
Gulf Coast Region | 121.6 | 50.1 | % | 49.8 | % | 17.2 | ||||||||||
Offshore California | 9.0 | — | % | 39.1 | % | 2.6 | ||||||||||
Other | 54.3 | 82.1 | % | 69.5 | % | 11.9 | ||||||||||
Total | 224.3 | 62.9 | % | 51.6 | % | 38.4 | ||||||||||
(1) | Bcfe means billion cubic feet of gas equivalent | |
(2) | MMcfe/d means million cubic feet of gas equivalent per day |
We intend to develop our primary areas of operations. For the six months ending December 31, 2005, we estimate our exploration and development capital budget to range between $50.0 — $65.0 million.
We have authorized capital of 3,000,000 shares of $.10 par value preferred stock, of which no shares were issued, and 300,000,000 shares of $.01 par value common stock, of which 42,017,000 shares were issued and outstanding as of June 30, 2005. We have outstanding options which were granted to our officers, employees and directors under our incentive plans, to purchase up to 3,501,000 shares of common stock at prices ranging from $1.13 to $15.46 per share.
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At June 30, 2005, we owned 4,277,977 shares of common stock of Amber Resources Company (“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company (registered under the Securities Exchange Act of 1934) which owns non-operated working interests in undeveloped leases offshore California, near Santa Barbara. We entered into an agreement with Amber effective October 1, 1998 which provides, in part, for the sharing of the management between the two companies and allocation of expenses related thereto.
Operations
During the year ended June 30, 2005, we were primarily engaged in only one industry, namely the acquisition, exploration, development, and production of oil and gas properties and related business activities. Our oil and gas operations have been comprised primarily of production of oil and gas, drilling exploratory and development wells and related operations and acquiring and selling oil and gas properties. Directly or through wholly-owned subsidiaries and through Amber, we currently own producing and non-producing oil and gas interests, undeveloped leasehold interests and related assets in fifteen (15) states, interests in a producing Federal unit offshore California and undeveloped offshore Federal leases near Santa Barbara, California. We intend to continue our emphasis on the drilling of exploratory and development wells primarily in Alabama, Colorado, Louisiana, New Mexico, Texas, Wyoming, and offshore California.
We intend to drill on some of our leases (presently owned or subsequently acquired); we may farm out or sell all or part of some of the leases to others; and/or we may participate in joint venture arrangements to develop certain other leases. Such transactions may be structured in a number of different manners that are in use in the oil and gas industry. Each such transaction is likely to be individually negotiated and no standard terms may be predicted.
We have oil and gas leases with governmental entities and other third parties who enter into oil and gas leases or assignments with us in the regular course of our business. We have no material patents, licenses, franchises or concessions that we consider significant to our oil and gas operations. The nature of our business is such that it is not seasonal, we do not engage in any research and development activities and we do not maintain or require a substantial amount of products, customer orders or inventory. Our oil and gas operations are not subject to renegotiations of profits or termination of contracts at the election of the federal government. We operate the majority of our properties and control the costs incurred. We have never been a party to any bankruptcy, receivership, reorganization or similar proceeding.
We currently own a 49.5% ownership interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. DHS currently has seven drilling rigs in operation that have depth ratings of approximately 7,500 to 20,000 feet. Three additional rigs are in the process of being acquired or assembled by DHS and are currently expected to become operational during the fall of 2005. We have the right to use all of the rigs on a priority basis, although approximately half will initially work for third party operators. At the outset, all of the rigs will operate in the Rocky Mountain and Columbia River basins.
Markets
The principal products produced by us are crude oil and natural gas. The products are generally sold at the wellhead to purchasers in the immediate area where the product is produced. The principal markets for oil and gas are refineries and transmission companies which have facilities near our producing properties.
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Distribution
Oil and natural gas produced from our wells is normally sold to various purchasers as discussed below. Oil is picked up and transported by the purchaser from the wellhead. In some instances we are charged a fee for the cost of transporting the oil which is deducted from or accounted for in the price paid for the oil. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas.
Competition
We encounter strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and the development and production of, natural gas and crude oil. Competition is particularly intense with respect to the acquisition of desirable undeveloped oil and gas leases. The principal competitive factors in the acquisition of undeveloped oil and gas leases include the availability and quality of staff and data necessary to identify, investigate and purchase such leases, and the financial resources necessary to acquire and develop such leases. Many of our competitors have financial resources, staffs and facilities substantially greater than ours. In addition, the producing, processing and marketing of natural gas and crude oil are affected by a number of factors which are beyond our control, the effect of which cannot be accurately predicted. See “Risk Factors.”
Raw Materials
The principal raw materials and resources necessary for the exploration and development of natural gas and crude oil are leasehold prospects under which gas and oil reserves may be discovered, drilling rigs and related equipment to drill for and produce such reserves and knowledgeable personnel to conduct all phases of gas and oil operations. Although equipment and supplies used in our business are usually available from multiple sources, there is currently a general shortage of drilling equipment and supplies. We believe that these shortages are likely to intensify. The costs and delivery times of equipment and supplies are substantially greater now than in prior periods and are currently escalating. In partial response to this trend, we engaged in a series of transactions which resulted in our current ownership interest in DHS Drilling Company to provide us with priority access to several large drilling rigs. We are also attempting to establish arrangements with others to assure adequate availability of certain other necessary drilling equipment and supplies on satisfactory terms, but there can be no assurance that we will be able to do so. Accordingly, there can be no assurance that we will not experience shortages of, or material price increases in, drilling equipment and supplies, including drill pipe, in the future. Any such shortages could delay and adversely affect our ability to meet our drilling commitments.
Major Customers
During our fiscal year ended June 30, 2005, we had only one company that purchased greater than 10% of our oil and gas production. We do not depend upon one or a few major customers for the sale of oil and gas as of the date of this report. The loss of any one or several customers would not have a material adverse effect on our business.
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Government Regulation of the Oil and Gas Industry
General
Our business is affected by numerous governmental laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial requirements, and, in less common circumstances, issuance of injunctions. Changes in any of these laws and regulations could have a material adverse effect on our business. In light of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and future expenditures for environmental compliance or remediation may be substantially more than we expect. We believe that our operations comply in all material respects with all applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry.
The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.
Environmental regulation
Our operations are subject to numerous federal, state, and local environmental laws and regulations concerning our oil and gas operations, products and other activities. In particular, these laws and regulations require the acquisition of permits; restrict the type, quantities and concentration of various substances that can be released into the environment; limit or prohibit activities on certain lands lying within wilderness, wetlands and other protected areas; regulate the generation, handling, storage, transportation, disposal and treatment of waste materials; and impose criminal or civil liabilities for pollution resulting from oil, natural gas and petrochemical operations.
Governmental approvals and permits are currently, and may in the future be, required in connection with our operations. The success of obtaining, and the duration of, such approvals are contingent upon a significant number of variables, many of which are not within our control. To the extent such approvals are required and not granted, operations may be delayed or curtailed, or we may be prohibited from proceeding with planned exploration or operation of facilities.
Environmental laws and regulations are expected to have an increasing impact on our operations, although it is impossible to predict accurately the effect of future developments in such laws and regulations on our future earnings and operations. Some risk of environmental costs and liabilities is inherent in our operations and products, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred. However, we do not currently expect any material adverse effect upon our results of operations or financial position as a result of compliance with such laws and regulations.
Although future environmental obligations are not expected to have a material adverse effect on our results of operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur substantial environmental liabilities or costs.
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Hazardous substances and waste disposal
We currently own or lease interests in numerous properties that have been used for many years for natural gas and crude oil production. Although the operator of such properties may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us. In addition, some of these properties have been operated by third parties over whom we had no control. The U.S. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liabilities on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the management and disposal of wastes. Although CERCLA currently excludes petroleum from cleanup liability, many state laws affecting our operations impose clean-up liability regarding petroleum and petroleum-related products.
In addition, although RCRA currently classifies certain exploration and production wastes as “non-hazardous,” such wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements. If such a change in legislation were to be enacted, it could have a significant impact on our operating costs, as well as the oil and gas industry in general.
Oil spills
Under the Federal Oil Pollution Act of 1990, as amended (“OPA”), (i) owners and operators of onshore facilities and pipelines, (ii) lessees or permittees of an area in which an offshore facility is located and (iii) owners and operators of tank vessels (“Responsible Parties”) are strictly liable on a joint and several basis for removal costs and damages that result from a discharge of oil into the navigable waters of the United States. These damages include, for example, natural resource damages, real and personal property damages and economic losses. OPA limits the strict liability of Responsible Parties for removal costs and damages that result from a discharge of oil to $350.0 million in the case of onshore facilities, $75.0 million plus removal costs in the case of offshore facilities, and in the case of tank vessels, an amount based on gross tonnage of the vessel. However, these limits do not apply if the discharge was caused by gross negligence or willful misconduct, or by the violation of an applicable Federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor or in certain other circumstances. To date, we have not had any material spills.
In addition, with respect to certain offshore facilities, OPA requires evidence of financial responsibility in an amount of up to $150.0 million. Tank vessels must provide such evidence in an amount based on the gross tonnage of the vessel. Failure to comply with these requirements or failure to cooperate during a spill event may subject a Responsible Party to civil or criminal enforcement actions and penalties.
Under our various agreements, we have primary liability for oil spills that occur on properties for which we act as operator. With respect to properties for which we do not act as operator, we are generally liable for oil spills as a non-operating working interest owner. We do not act as operator for any of our offshore California properties. The operators of our offshore California properties are primarily liable for oil spills and are required by the U.S. government’s Mineral Management Service (‘‘MMS’’) to carry certain types of insurance and to post bonds in that regard. There is no assurance that our insurance coverage is adequate to protect us.
Offshore production
Offshore oil and gas operations in U.S. waters are subject to regulations of the United States Department of the Interior which currently impose strict liability upon the lessee under a Federal lease for the cost of clean-up of pollution resulting from the lessee’s operations. As a result, such a lessee could be subject to possible liability for pollution damages. In the event of a serious incident of pollution, the Department of the Interior may require a lessee under Federal leases to suspend or cease operations in the affected areas.
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Because we are engaged in acquiring, operating, exploring for and developing natural resources, we are subject to various state and local provisions regarding environmental and ecological matters. Therefore, compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. At the present time, however, these laws do not materially hinder or adversely affect our business. Capital expenditures relating to environmental control facilities have not been materially significant to our operations since our inception. In addition, we do not anticipate that such expenditures will be materially significant during the six months ending December 31, 2005.
We are responsible for costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on our oil and natural gas properties according to our pro rata ownership. As of July 1, 2002, we adopted SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. We have an asset retirement obligation of approximately $3.7 million at June 30, 2005. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates and changes to environmental laws and regulations. Estimated asset retirement obligations are added to net unamortized historical oil and gas property costs for purposes of computing depreciation, depletion and amortization expense charges.
Employees
We have approximately 95 full time employees. Additionally, certain operators, engineers, geologists, geophysicists, landmen, pumpers, draftsmen, title attorneys and others necessary for our operations are retained on a contract or fee basis as their services are required.
Certain Risks
Owners of our common stock are subject to a variety of risks, including, without limitation, the following:
RISKS RELATED TO OUR BUSINESS AND INDUSTRY.
OIL AND NATURAL GAS PRICES ARE VOLATILE AND A DECREASE COULD ADVERSELY AFFECT OUR REVENUES, CASH FLOWS AND PROFITABILITY.
Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Sustained declines in oil and gas prices may adversely affect our financial condition, liquidity and results of operations. Factors that can cause market prices of oil and natural gas to fluctuate include:
— | relatively minor changes in the supply of and demand for oil and natural gas; | ||
— | market uncertainty; | ||
— | the level of consumer product demands; | ||
— | weather conditions; | ||
— | U.S. and foreign governmental regulations; | ||
— | the price and availability of alternative fuels; | ||
— | political and economic conditions in oil producing countries, particularly those in the Middle East, including actions by the Organization of Petroleum Exporting Countries; | ||
— | the foreign supply of oil and natural gas; and | ||
— | the price of oil and gas imports, consumer preferences and overall U.S. and foreign economic conditions. |
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We are not able to predict future oil and natural gas prices. At various times, excess domestic and imported supplies have depressed oil and gas prices. Lower prices may reduce the amount of oil and natural gas that we can produce economically and may also require us to write down the carrying value of our oil and gas properties. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices, not long-term fixed price contracts. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations.
WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES.
Our reserves will decline significantly as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves that are economically feasible and developing existing proved reserves.
IF OIL OR NATURAL GAS PRICES DECREASE OR EXPLORATION AND DEVELOPMENT EFFORTS ARE UNSUCCESSFUL, WE MAY BE REQUIRED TO TAKE WRITEDOWNS.
In the past, we have been required to write down the carrying value of our oil and gas properties. There is a risk that we will be required to take additional writedowns in the future which would reduce our earnings and stockholders’ equity. A writedown could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration and development results.
We account for our crude oil and natural gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. If the carrying amount of our oil and gas properties exceeds the estimated undiscounted future net cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value.
We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a writedown of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded carrying values associated with our oil and gas properties. As a result of our review, we did not record an impairment for fiscal 2005, 2004 or 2003.
WE MAY NOT BE ABLE TO FUND OUR PLANNED CAPITAL EXPENDITURES.
We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. Our exploration and development capital budget is expected to range between $50.0 and $65.0 million for the six months ending December 31, 2005. If low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program. In addition, if our borrowing base under our senior credit facility is re-determined to a lower amount, this could adversely affect our ability to fund our planned capital expenditures. After utilizing our available sources of financing, we may be forced to raise additional equity or debt proceeds to fund such expenditures. Additional equity or debt financing or cash flow provided by operations may not be available to meet our capital expenditure requirements.
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THE EXPLORATION, DEVELOPMENT AND OPERATION OF OIL AND GAS PROPERTIES INVOLVE SUBSTANTIAL RISKS THAT MAY RESULT IN A TOTAL LOSS OF INVESTMENT.
The business of exploring for and, to a lesser extent, developing and operating oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
— | unexpected drilling conditions; | ||
— | pressure or irregularities in formations; | ||
— | equipment failures or accidents; | ||
— | weather conditions; | ||
— | shortages in experienced labor; and | ||
— | shortages or delays in the delivery of equipment. |
The cost to develop our reserves as of June 30, 2005 is estimated to be approximately $192.4 million. We may drill wells that are unproductive or, although productive, do not produce oil and/or gas in economic quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.
OUR INDUSTRY EXPERIENCES NUMEROUS OPERATING HAZARDS THAT COULD RESULT IN SUBSTANTIAL LOSSES.
The exploration, development and operation of oil and gas properties also involve a variety of operating risks including the risk of fire, explosions, blowouts, cratering, pipe failure, abnormally pressured formations, natural disasters, acts of terrorism or vandalism, and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. These industry-operating risks can result in injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial losses.
We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. The terrorist attacks on September 11, 2001 and certain potential natural disasters may change our ability to obtain adequate insurance coverage. The occurrence of a significant event that is not fully insured or indemnified against could materially and adversely affect our financial condition and operations.
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OUR LEVEL OF INDEBTEDNESS COULD ADVERSELY AFFECT OUR ABILITY TO RAISE ADDITIONAL CAPITAL TO FUND OUR OPERATIONS, LIMIT OUR ABILITY TO REACT TO CHANGES IN THE ECONOMY OR OUR INDUSTRY AND PREVENT US FROM MEETING OUR OBLIGATIONS UNDER OUR SENIOR UNSECURED NOTES.
As of June 30, 2005, our total outstanding long term liabilities were $222.6 million. Our degree of leverage could have important consequences, including the following:
— | it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes; | ||
— | a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities; | ||
— | the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations; | ||
— | certain of our borrowings, including borrowings under our senior credit facility, are at variable rates of interest, exposing us to the risk of increased interest rates; | ||
— | it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that have less debt; and | ||
— | we may be vulnerable in a downturn in general economic conditions or in our business, or we may be unable to carry out capital spending and exploration activities that are important to our growth. |
We may be able to incur substantially more debt in the future, which may intensify the risks described herein. The indenture governing our 7% senior notes and our senior credit facility do not prohibit us from doing so. As of June 30, 2005, we had approximately $66.5 million outstanding under our senior credit facility and additional availability of approximately $8.5 million.
A DEFAULT UNDER OUR SENIOR CREDIT FACILITY COULD CAUSE US TO LOSE OUR PROPERTIES.
In order to obtain our senior credit facility, we granted first priority liens to the lending banks on most of our oil and gas properties and the related equipment, inventory, accounts and proceeds. Our senior 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 also includes financial covenants.
Under certain conditions amounts outstanding under our senior 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 senior credit facility. Subject to notice and cure periods in certain cases, other events of default under the senior credit facility will result in acceleration of the indebtedness at the option of the lending banks. Such other events of default include, among other things, non-payment, breach of warranty, non-performance of obligations under the senior 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 senior credit facility. Any of these events could potentially cause us to lose substantially all of our properties. At June 30, 2005, we were not in compliance with our quarterly debt covenants and restrictions, but have obtained a waiver from our banks.
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For so long as the revolving commitment is in existence, we will also be required to comply with loan covenants that will limit our flexibility in conducting our business and which could cause us significant problems in the event of a downturn in the oil and gas market. If an event of default occurs and continues after the expiration of any cure period that is provided for in our senior credit facility, the entire principal amount due under it, all accrued interest and any other liabilities that we might have to the lending banks under the senior credit facility will all become immediately due and payable, all without notice of default of any kind. The foregoing information is provided to alert readers that there is risk associated with our existing debt obligations. It is not intended to provide a summary of the terms of our agreements with our lenders.
ACQUISITIONS ARE A PART OF OUR BUSINESS STRATEGY AND ARE SUBJECT TO THE RISKS AND UNCERTAINTIES OF EVALUATING RECOVERABLE RESERVES AND POTENTIAL LIABILITIES.
We could be subject to significant liabilities related to acquisitions by us. The successful acquisition of producing properties requires an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. Further, even a detailed review of all properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed. We cannot assure you that our recent and/or future acquisition activity will not result in disappointing results.
In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing or regulatory approvals.
Acquisitions often pose integration risks and difficulties. In connection with recent and future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.
WE MAY NOT BE ABLE TO OBTAIN ADEQUATE FINANCING TO EXECUTE OUR OPERATING STRATEGY.
We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, the use of bank credit facilities and the issuance of equity securities. Without adequate financing, we may not be able to successfully execute our operating strategy. We continue to examine the following alternative sources of capital:
— | bank borrowings or the issuance of debt securities; and | ||
— | the issuance of common stock, preferred stock or other equity securities. |
The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices and our market value and operating performance. We may be unable to execute our operating strategy if we cannot obtain adequate capital.
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WE DEPEND ON KEY PERSONNEL.
We currently have only three employees that serve in senior management roles, and the loss of any one of them could severely harm our business. In particular, Roger A. Parker and John R. Wallace are responsible for the operation of our oil and gas business and Kevin K. Nanke is our Treasurer and Chief Financial Officer. We do not have key man insurance on the lives of any of these individuals. Furthermore, competition for experienced personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.
WE MAY NOT BE PERMITTED TO DEVELOP SOME OF OUR OFFSHORE CALIFORNIA PROPERTIES OR, IF WE ARE PERMITTED, THE SUBSTANTIAL COST TO DEVELOP THESE PROPERTIES COULD RESULT IN A REDUCTION OF OUR INTEREST IN THESE PROPERTIES OR CAUSE US TO INCUR PENALTIES.
Certain of our offshore California undeveloped properties, in which we have ownership interests ranging from 2.49% to 100.00%, are attributable to our interests in four of our five federal units (plus one additional lease) located offshore of California near Santa Barbara. These properties have a cost basis of approximately $10.9 million. The development of these properties is subject to extensive regulation and is currently the subject of litigation. Pursuant to a ruling in California v. Norton, later affirmed by the Ninth 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.
In addition, the cost to develop these properties will be substantial. The cost to develop all of these offshore California properties in which we own an interest, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated to be in excess of $3.0 billion. Our share of such costs, based on our current ownership interest, is estimated to be over $200.0 million. Operating expenses for the same properties over the same period of time, including platform operating costs, well maintenance and repair costs, oil, gas and water treating costs, lifting costs and pipeline transportation costs, are estimated to be approximately $3.5 billion, with our share, based on our current ownership interest, estimated to be approximately $300.0 million. There will be additional costs of a currently undetermined amount to develop the Rocky Point Unit. Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. If we are unable to fund our share of these costs or otherwise cover them through farm-outs or other arrangements, then we could either forfeit our interest in certain wells or properties or suffer other penalties in the form of delayed or reduced revenues under our various unit operating agreements, which could impact the ultimate realization of this investment. The estimates discussed above may differ significantly from actual results.
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YOU SHOULD NOT PLACE UNDUE RELIANCE ON RESERVE INFORMATION BECAUSE IT IS ONLY AN ESTIMATE.
There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of oil and gas reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and gas prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities, oil and gas prices and regulatory changes. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from our assumptions and estimates. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data.
The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves for the fiscal years ended June 30, 2005, 2004 and 2003 included in our periodic reports filed with the SEC were prepared by our reserve engineers in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. As required by the SEC, the estimated discounted present value of future net cash flows from proved reserves is generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. In addition, the 10% discount factor, which the SEC requires to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.
WE ARE EXPOSED TO ADDITIONAL RISKS THROUGH OUR DRILLING BUSINESS.
We currently have a 49.5% ownership interest in and management control of a drilling business. The operations of that entity will subject it to many additional hazards that are inherent to the drilling business, including, for example, blowouts, cratering, fires, explosions, loss of well control, loss of hole, damaged or lost drill strings and damage or loss from inclement weather. No assurance can be given that the insurance coverage maintained by that entity will be sufficient to protect it against liability for all consequences of well disasters, personal injury, extensive fire damage or damage to the environment. No assurance can be given that the drilling business will be able to maintain adequate insurance in the future at rates it considers reasonable or that any particular types of coverage will be available. The occurrence of events, including any of the above-mentioned risks and hazards that are not fully insured could subject the drilling business to significant liability. It is also possible that we might sustain significant losses through the operation of the drilling business even if none of such events occurs.
HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS OR CAUSE US TO LOSE MONEY.
In order to manage our exposure to price risks in the marketing of oil and gas, we periodically enter into oil and gas price hedging arrangements, typically costless collars. While intended to reduce the effects of volatile oil and gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
— | production is substantially less than expected; | ||
— | the counterparties to our futures contracts fail to perform under the contracts; or | ||
— | a sudden, unexpected event materially impacts gas or oil prices. |
WE MAY NOT RECEIVE PAYMENT FOR A PORTION OF OUR FUTURE PRODUCTION.
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Our revenues are derived principally from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. We do not attempt to obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict, however, what impact the financial difficulties of any of our purchasers may have on our future results of operations and liquidity.
WE HAVE NO LONG-TERM CONTRACTS TO SELL OIL AND GAS.
We do not have any long-term supply or similar agreements with governments or other authorities or entities for which we act as a producer. We are therefore dependent upon our ability to sell oil and gas at the prevailing wellhead market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable.
THERE IS CURRENTLY A SHORTAGE OF AVAILABLE DRILLING RIGS AND EQUIPMENT WHICH COULD CAUSE US TO EXPERIENCE HIGHER COSTS AND DELAYS THAT COULD ADVERSELY AFFECT OUR OPERATIONS.
Although equipment and supplies used in our business are usually available from multiple sources, there is currently a general shortage of drilling equipment and supplies. We believe that these shortages are likely to intensify. The costs and delivery times of equipment and supplies are substantially greater now than in prior periods and are currently escalating. In partial response to this trend, we have acquired a controlling interest in a drilling company. We believe that our ownership interest in the drilling company will allow us to have priority access to several large drilling rigs. We are also attempting to establish arrangements with others to assure adequate availability of certain other necessary drilling equipment and supplies on satisfactory terms, but there can be no assurance that we will be able to do so. Accordingly, there can be no assurance that we will not experience shortages of, or material price increases in, drilling equipment and supplies, including drill pipe, in the future. Any such shortages could delay and adversely affect our ability to meet our drilling commitments.
THE MARKETABILITY OF OUR PRODUCTION DEPENDS MOSTLY UPON THE AVAILABILITY, PROXIMITY AND CAPACITY OF GAS GATHERING SYSTEMS, PIPELINES AND PROCESSING FACILITIES, WHICH ARE OWNED BY THIRD PARTIES.
The marketability of our production depends upon the availability, operation and capacity of gas gathering systems, pipelines and processing facilities, which are owned by third parties. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. We currently own several wells that are capable of producing but are currently shut-in pending the construction of gas gathering systems, pipelines and processing facilities. United States federal, state and foreign regulation of oil and gas production and transportation, tax and energy policies, damage to or destruction of pipelines, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors changed dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.
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OUR INDUSTRY IS HIGHLY COMPETITIVE, MAKING OUR RESULTS UNCERTAIN.
We operate in the highly competitive areas of oil and gas exploration, development and production. We compete for the purchase of leases from the U.S. government and from other oil and gas companies. These leases include exploration prospects as well as properties with proved reserves. We face competition in every aspect of our business, including, but not limited to:
— | acquiring reserves and leases; | ||
— | obtaining goods, services and employees needed to operate and manage our business; | ||
— | access to the capital necessary to drill wells and acquire properties; and | ||
— | marketing oil and natural gas. |
Competitors include multinational oil companies, independent production companies and individual producers and operators. Many of our competitors have greater financial, technological and other resources than we do.
NEW TECHNOLOGIES MAY CAUSE OUR CURRENT EXPLORATION AND DRILLING METHODS TO BECOME OBSOLETE, RESULTING IN AN ADVERSE EFFECT ON OUR PRODUCTION.
The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete, and we may be adversely affected.
TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.
The United States has been the target of terrorist attacks of unprecedented scale. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our business.
WE OWN PROPERTIES IN THE GULF COAST REGION THAT COULD BE SUSCEPTIBLE TO DAMAGE BY SEVERE WEATHER.
Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our properties in the Gulf Coast Region are located in areas that could cause them to be susceptible to damage by these storms. Damage caused by high winds and flooding could potentially cause us to curtail operations and/or exploration and development activities on such properties for significant periods of time until damage can be repaired. Moreover, even if our properties are not directly damaged by such storms, we may experience disruptions in our ability to sell our production due to damage to pipelines, roads and other transportation and refining facilities in the area. Our production and operations were not impacted by hurricane Katrina.
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WE MAY INCUR SUBSTANTIAL COSTS TO COMPLY WITH THE VARIOUS U.S. FEDERAL, STATE AND LOCAL LAWS AND REGULATIONS THAT AFFECT OUR OIL AND GAS OPERATIONS.
Our oil and gas operations are subject to stringent U.S. federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection or the oil and gas industry generally. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Compliance with such laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory or remedial obligations, or the imposition of injunctive relief.
The environmental laws and regulations to which we are subject may:
— | require applying for and receiving a permit before drilling commences; | ||
— | restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; | ||
— | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and | ||
— | impose substantial liabilities for pollution resulting from our operations. |
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Over the years, we have owned or leased numerous properties for oil and gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA and analogous state laws, we could be held strictly liable for the removal or remediation of previously released materials or property contamination at such locations regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.
RISKS RELATED TO OUR STOCK.
WE MAY ISSUE SHARES OF PREFERRED STOCK WITH GREATER RIGHTS THAN OUR COMMON STOCK.
Although we have no current plans, arrangements, understandings or agreements to issue any preferred stock, our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our shareholders. Any preferred stock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights.
THERE MAY BE FUTURE DILUTION OF OUR COMMON STOCK.
To the extent options to purchase common stock under our employee and director stock option plans are exercised, holders of our common stock will incur dilution. Further, if we sell additional equity or convertible debt securities, such sales could result in increased dilution to our shareholders.
WE DO NOT EXPECT TO PAY DIVIDENDS ON OUR COMMON STOCK.
We do not expect to pay any dividends, in cash or otherwise, with respect to our common stock in the foreseeable future. We intend to retain any earnings for use in our business. In addition, the credit agreement relating to our credit facility prohibits us from paying any dividends until the loan is retired.
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THE COMMON STOCK IS AN UNSECURED EQUITY INTEREST IN OUR COMPANY.
As an equity interest, the common stock will not be secured by any of our assets. Therefore, in the event we are liquidated, the holders of the common stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of the common stock.
OUR SHAREHOLDERS DO NOT HAVE CUMULATIVE VOTING RIGHTS.
Holders of our common stock are not entitled to accumulate their votes for the election of directors or otherwise. Accordingly, the holders of more than 50% of our outstanding common stock will be able to elect all of our directors. As of June 30, 2005, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 23% of our outstanding common stock.
OUR ARTICLES OF INCORPORATION MAY HAVE PROVISIONS THAT DISCOURAGE CORPORATE TAKEOVERS AND COULD PREVENT SHAREHOLDERS FROM REALIZING A PREMIUM ON THEIR INVESTMENT.
Certain provisions of our Articles of Incorporation and the provisions of the Colorado Business Corporation Act may discourage persons from considering unsolicited tender offers or other unilateral takeover proposals. Such persons might choose to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions could have the effect of preventing shareholders from realizing a premium on their investment.
Our Articles of Incorporation authorize our Board of Directors to issue preferred stock without shareholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as the Board may determine. In addition, our Articles of Incorporation authorize a substantial number of shares of common stock in excess of the shares outstanding. These provisions may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to shareholders for their common stock.
Item 2. DESCRIPTION OF PROPERTY
Rocky Mountain Region — Wind River, Piceance and Denver Julesburg Basins
The Rocky Mountain Region comprises approximately 17.6% of our estimated proved reserves as of June 30, 2005. The majority 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 on three fields 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.
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 4,428 net acres, where our working interest is 90% throughout the field with a 72% net revenue interest. At June 30, 2005, 4,308 net acres were undeveloped. This field is an example of the type of project that we strive to develop because of our expertise in multi-zone, multi-stage frac completion technology. The field has consistent geological characteristics 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 six months ending December 31, 2005 is $18 — $22 million. Approximately 88% of our acreage position in this field is on federal land, and it is possible that we could be subject to drilling restrictions that would 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 25 Bcfe and net production of 2.5 MMcfe per day as of June 30, 2005.
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Piceance Basin. Within our acreage position in the Piceance Basin, we are currently focusing our development efforts on the Vega Unit in Mesa County, Colorado, where we have an interest in 3,280 net acres. Our working interest is 100% in this unit with an associated 80% net revenue interest. Approximately 3,120 net acres were undeveloped as of June 30, 2005. We have been acquiring acreage in this area for the past 10 years. This field is also consistent with our strategy of targeting reservoirs that demonstrate predictable geologic attributes. There are 10-15 productive sands that have little geologic or geographic variance throughout the field, which lead to very predictable wells. We use our expertise in multi-zone, multi-stage frac completion technologies to accelerate the production from the wells, therefore increasing the present value of the production. The Mesaverde is the primary producing sand at a depth of 6,400-8,000 feet. There are also coal seams in this area that offer coal-bed methane production (“CBM”); however, we do not have plans to develop the CBM reserves, nor are the CBM reserves included in our proved reserve base. Our capital budget for the field in the Piceance Basin in the six months ending December 31, 2005 is $12 — $15 million. Our proved reserves in this field comprised 9.7 Bcfe as of June 30, 2005. Net production in the field was 500 Mcfe per day as of June 30, 2005. Throughout the Piceance Basin most of our acreage is on federal land and is not subject to any drilling restrictions. There are currently no constraints on our ability to transport production, but once we have more fully developed the acreage, we will likely reach or surpass the existing transportation capacity. In anticipation of this marketing constraint, we have entered into a gas gathering and processing agreement with a third party that will create enough excess pipeline capacity to fully 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 385,257 net acres, 90% of which is undeveloped. Our working interest is 100% throughout the field with an 85% net revenue interest. This field targets the Niobrara formation that lies at a depth of 2,800 feet. Our proved reserves in this project area comprised 2.3 Bcfe as of June 30, 2005. Net production in the field was 1.7 MMcfe per day as of June 30, 2005.
Gulf Coast Region — South Texas and South Louisiana Basins
The Gulf Coast Region comprises approximately 54.2% of our estimated proved reserves as of June 30, 2005. In the Gulf Coast Region, our primary activities focus is developing the Opposum Hollow/Caballos Creek area and the prolific Newton Field which provides Delta with a large inventory of development drilling resulting in near term reserve and production growth. The producing fields in the Gulf Coast Region are Newton, South Angleton, North Hagist, Laurel Ridge, Speary, Caballos Creek/Opossum Hollow and Baffin Bay.
Newton Field. The Newton Field is located in Newton County, Texas. We have an interest in 2,357 net acres, where our working interest is 100% throughout the field with a 73% net revenue interest. At June 30, 2005, 1,627 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 through our experience in multi-zone, multi-stage frac technologies gained from our completion experience in the Rocky Mountains. Our multi-zone completion practices allow us to complete several different zones simultaneously which significantly increases our economic returns. The field is characterized as a large structural anticline and is defined by extensive well control and seismic information. The different Wilcox sands are very consistent across the structure. A new reservoir simulation model based on well control from recently drilled wells reveals that the highest return undeveloped drilling locations will be developed over the next two years. As of June 30, 2005, we had 21 producing wells in the Newton Field. We have planned $14 — 18 million in capital expenditures for the field in the six months ending December 31, 2005. Our proved reserves in the Newton Field comprised 55 Bcfe as of June 30, 2005. Net production in the field was 7.6 MMcfe per day as of June 30, 2005. We believe the Newton Field will be a significant growth platform for us in the Gulf Coast Region.
South Angleton Field. The South Angleton Field is located in Brazoria County, Texas. We have interests in 1,536 net acres, where our working interest is 100% throughout the field, with a 79% net revenue interest. The wells in this field produce from the Frio and Anomalina sands that range in depth from 10,100 to 12,200 feet. We have recently drilled and are in the process of completing a new well in the field. As of June 30, 2005 our proved reserves totaled 7.7 Bcfe and production was 1.9 MMcfe per day for the South Angleton Field.
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North Hagist Field. The North Hagist Ranch Field is located in McMullen County, Texas. We have interests in 983 net acres where our working interest is 100% throughout the field with a net revenue interest of 75%. The North Hagist wells produce from the Wilcox formation at a depth of 8,500 feet. As of June 30, 2005 we had proved reserves of 3.7 Bcfe with production of 1.9 Mcfe per day.
Laurel Ridge Field. The Laurel Ridge Field is located in Iberville Parish, Louisiana. We currently have three producing wells in the Laurel Ridge Field. As of June 30, 2005 we had proved reserves of 8.2 Bcfe with production of 0.1 Mcfe per day.
Speary Field. The Speary Field is located in Karnes County, Texas. The wells in this field produce from the Wilcox formation; however, there are significant proved reserves that are at shallower depths behind pipe in the Upper Wilcox formation. Our development plans are to re-complete up to six different zones in five of the existing wells in the field. As of June 30, 2005, we had proved reserves of 4.5 Bcfe with production of 553 Mcfe per day.
Caballos Creek / Opossum Hollow (“CCOH”) Fields.The CCOH Fields are located in McMullen and Atascosa Counties, Texas. We have an average of 98.5% net working interest with a 72% net revenue interest in the fields. The wells in these fields produce from the Wilcox formation. The individual fields are fault traps that are generally small in areal extent, and therefore are drained with only one or two wells per field. In addition to the shallow Wilcox production, we have targeted a deep Sligo feature that has significant proven undeveloped reserves. As of June 30, 2005 we had proved reserves of 15.8 Bcfe with production of 2.4 MMcfe per day.
Baffin Bay Field. The Baffin Bay Field is located in Kenedy County, Texas. This field is predominantly non-operated and we have net revenue interests ranging from 6% to 73%. The field is mostly operated by Exxon Mobil; however, we operate one well in the field that has significant proved developed non-producing reserves behind pipe. As of June 30, 2005, we had proved reserves of 15.8 Bcfe with production of 5.0 MMcfe per day.
Other Operations
Offshore California producing properties
Point Arguello Unit. We own through a nominee 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. In layman’s terms, the “net operating interest” is defined in our agreement with Whiting Petroleum Corporation 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) that are operated by Arguello, Inc., a subsidiary of Plains Resources Corporation. Our 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 June 30, 2005 two development wells have been drilled from Platform Hidalgo to the Rocky Point unit structure. The Rocky Point Unit is being developed through extended-reach drilling from the existing platforms located within the adjacent Point Arguello Unit. The technology of extended-reach drilling has dramatically advanced. The operator has plans to drill up to eight additional extended reach wells to develop the structure.
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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 $10.9 million and $10.8 million at June 30, 2005 and 2004, 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 June 30, 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. On January 9, 2002, we and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. government has materially breached the terms of 40 undeveloped federal leases, some of which are part of our offshore California properties. See “Legal Proceedings.”
Columbia River
The Columbia River Basin is located in southeast Washington and northeast Oregon. We have interests in 164,289 net acres in the basin, all of which are undeveloped. We have a 50% working interest and 40% net revenue interest. We are the operator on the acreage in which we own an interest. There are other major exploration and production companies that are conducting drilling activities in the basin. We plan on observing the results of their drilling activity before we determine our drilling and development 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 well testing and core analysis, there appear to be multiple productive zones with over 1,000 feet of hydrocarbon bearing sands which lie below approximately 6,000 feet of basalt. The Columbia River Basin remains a long term development prospect and does not account for any of our proved reserves as of June 30, 2005. We are not budgeting any capital expenditure for 2006, however, any significant drilling successes by other operators would cause us to reallocate our 2006 budget to allow for development of our Columbia River Basin assets.
Other Fields
We derive meaningful oil and gas production from fields in non-core regions that will not constitute a significant portion of our capital budget in the future. These fields are the Padgett Field in South Central Kansas; the Eland Field in Stark County, North Dakota; and other fields in Panola County, Texas and Colusa County, California. Our interest in these fields provided aggregate net daily production of approximately 4.2 MMcfe per day and had approximately 12.8 Bcfe in proved reserves as of June 30, 2005.
Office Facilities
Our offices are located at 370 Seventeenth Street, Suite 4300, Denver, Colorado 80202. We lease approximately 32,000 square feet of office space. Our current monthly payment approximates $64,000 per month and our lease will expire in November 2015.
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Acquisition History
On September 7, 2005 we entered into an agreement to purchase an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington, and to purchase 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, on or before September 30, 2005. 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 consolidates our current leasehold position, whereby subsequent to the acquisition we will own a 100% working interest in approximately 350,000 net acres. This acquisition also includes a small portion of acreage that is subject to an agreement with EnCana Oil & Gas (USA) Inc., whereby we will have the right to convert an overriding royalty interest to a working interest at project payout. In the Piceance Basin, we are acquiring Savant’s interest in an entity that owns a 25% interest in approximately 6,314 gross acres that is currently being developed.
Through a series of transactions that occurred during the spring and summer of 2005, we have acquired a 49.5% ownership interest in DHS Drilling Company for an aggregate investment of $15.0 million. DHS currently has seven drilling rigs in operation that have depth ratings of approximately 7,500 to 20,000 feet. Three additional rigs are in the process of being acquired or assembled by DHS and are currently expected to become operational during the fall of 2005. We have the right to use all of the rigs on a priority basis, although approximately half will initially work for third party operators. At the outset, all of the rigs will operate in the Rocky Mountain basins. We believe that our ownership interest in DHS gives us a competitive advantage because it enables us to have access to drilling rigs on a priority basis and allows us to better control the timing of our drilling operations.
On May 4, 2005, we purchased from Savant 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 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 full working interest by paying our proportionate share of the costs incurred in the project.
On January 21, 2005, we closed the acquisition of certain properties located in McMullen, Kenedy and Atascosa Counties in Texas from Manti Resources, Inc. The effective date of this transaction was December 1, 2004. The purchase price of the properties was $59.7 million in cash, net of downward purchase price adjustments. As of June 30, 2005, the properties had approximately 31.6 Bcfe of proved reserves, and have additional unproved development opportunities. As of June 30, 2005, the Manti assets produce an average net to us of 8 MMcfe per day.
On June 29, 2004, we acquired substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc., a privately held exploration and production company, for a total purchase price of $120.6 million in cash, net of a $1.9 million downward purchase price adjustment. The Alpine assets included 79 producing wells, 16 shut-in wells and numerous proved undeveloped drilling and re-completion opportunities. Of the proved reserves acquired, 55% are located in the Newton field and approximately 13% are located in the South Angleton field. These fields also represent a significant portion of our budgeted drilling program for fiscal 2006.
During the period from September of 2003 through July of 2004 we completed a series of transactions with Edward Mike Davis and certain unrelated individuals which resulted in our acquisition of a producing property and approximately 360,000 acres of undeveloped properties in our 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 we 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 our common stock.
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On June 20, 2003, we acquired producing oil and gas interests and related undeveloped acreage in Kansas from JAED Production Company for total consideration of $8.7 million net of normal closing adjustments. On the date of acquisition, we estimated proved reserves to be approximately 9.9 Bcfe.
On May 31, 2002, we acquired all of the domestic oil and gas properties of Castle Exploration Company (“Castle”) for total consideration of $40.8 million, net of $5.8 million in closing adjustments. The properties acquired from Castle consisted of interests in numerous producing wells located in fourteen (14) states, plus associated undeveloped acreage. On the date of acquisition, we estimated proved reserves to be approximately 62 Bcfe, of which 32 Bcfe was considered to be proved developed producing reserves.
On February 19, 2002, we completed the acquisition of Piper Petroleum Company (“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. We issued 1,377,240 shares of our restricted common stock for 100% of the shares of Piper. The 1,377,240 shares of restricted common stock were valued at approximately $5.2 million.
During fiscal 2004, we 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 June 30, 2005, the limited liability company had not yet engaged in any revenue producing activities.
Production
During the years ended June 30, 2005, 2004 and 2003 we have not had, nor do we now have, any long-term supply or similar agreements with governments or authorities under which we acted as producer.
Impairment of Long Lived Assets
We annually compare our historical cost basis of each proved developed and undeveloped oil and gas property to its expected future undiscounted cash flow from each property (on a field by field basis). Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the property, no impairment is recognized. If the carrying value of the property exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset.
We had no impairment provision attributed to producing properties during the years ended June 30, 2005, 2004 and 2003.
Any impairment provisions recognized for developed and undeveloped properties are permanent and may not be restored in future periods.
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Production Volumes, Unit Prices and Costs
The following table sets forth certain information regarding our volumes of production sold and average prices received associated with our production and sales of natural gas and crude oil for each of the years ended June 30, 2005, 2004 and 2003.
Years Ended June 30, | ||||||||||||||||||||||||
2005 | 2004 (1) | 2003 (1) | ||||||||||||||||||||||
Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||||||||
Production volume — continuing operations: | ||||||||||||||||||||||||
Oil (MBbls) | 899 | 156 | 552 | 180 | 217 | 227 | ||||||||||||||||||
Natural Gas (MMcf) | 7,501 | — | 2,842 | — | 2,292 | — | ||||||||||||||||||
Net average daily production-continuing operations: | ||||||||||||||||||||||||
Oil (Bbl) | 2,463 | 427 | 1,512 | 493 | 595 | 621 | ||||||||||||||||||
Natural Gas (Mcf) | 20,551 | — | 7,786 | — | 26,827 | — | ||||||||||||||||||
Average sales price: | ||||||||||||||||||||||||
Oil (per barrel) | $ | 47.05 | $ | 33.37 | $ | 33.09 | $ | 22.11 | $ | 28.82 | $ | 20.21 | ||||||||||||
Natural Gas (per Mcf) | $ | 5.79 | $ | — | $ | 5.27 | $ | — | $ | 4.71 | $ | — | ||||||||||||
Hedge effect (per Mcfe) | $ | (.07 | ) | $ | — | $ | (.14 | ) | $ | — | $ | (.49 | ) | $ | — | |||||||||
Lease operating costs — (per Mcfe) | $ | .92 | $ | 4.00 | $ | .70 | $ | 2.98 | $ | .99 | $ | 2.35 |
(1) | 2004 and 2003 information has changed to comply with FAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” |
Productive Wells and Acreage
The table below shows, as of June 30, 2005, the approximate number of gross and net producing oil and gas wells by state and their related developed acres owned by us. Calculations include 100% of wells and acreage owned by us and our subsidiaries. Productive wells are producing wells capable of production, including shut-in wells. Developed acreage consists of acres spaced or assignable to productive wells.
Oil (1) | Gas | Developed Acres | ||||||||||||||||||||||
Location | Gross (2) | Net (3) | Gross (2) | Net (3) | Gross (2) | Net (3) | ||||||||||||||||||
Alabama | — | — | 71 | 70.7 | 3,646 | 3,646 | ||||||||||||||||||
California: | ||||||||||||||||||||||||
Offshore | 39 | 2.4 | — | — | 11,042 | 669 | ||||||||||||||||||
Onshore | 2 | .1 | 17 | 4.4 | 1,160 | 586 | ||||||||||||||||||
Colorado | 15 | 12.6 | 17 | 14.8 | 4,190 | 3,572 | ||||||||||||||||||
Kansas | 29 | 26.44 | 1 | .63 | 840 | 808 | ||||||||||||||||||
Louisiana | 15 | 8.4 | 4 | .04 | 5,968 | 3,737 | ||||||||||||||||||
Michigan | 1 | .01 | — | — | 40 | — | ||||||||||||||||||
Mississippi | 7 | .32 | 4 | 1.0 | 1,440 | 332 | ||||||||||||||||||
Montana | 11 | 3.64 | 1 | .48 | 964 | 241 | ||||||||||||||||||
Nebraska | 1 | .0625 | — | — | 40 | 3 | ||||||||||||||||||
New Mexico | 12 | 1.21 | 26 | 8.25 | 9,280 | 3,284 | ||||||||||||||||||
North Dakota | 18 | 1.25 | — | — | 9,950 | 2,326 | ||||||||||||||||||
Oklahoma | 9 | 7.68 | 4 | .42 | 3,665 | 463 | ||||||||||||||||||
Texas (4) | 100 | 54.5 | 150 | 47.02 | 35,053 | 20,556 | ||||||||||||||||||
Wyoming | 1 | 1.0 | 12 | 9.8 | 7,745 | 6,979 | ||||||||||||||||||
260 | 119.6 | 307 | 157.54 | 95,023 | 47,202 | |||||||||||||||||||
(1) | All of the wells classified as “oil” wells also produce various amounts of natural gas. | |
(2) | A “gross well” or “gross acre” is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned. | |
(3) | A “net well” or “net acre” is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof. | |
(4) | This does not include varying very small interests in approximately 666 gross wells (5.2 net) located primarily in Texas which are owned by our subsidiary, Piper Petroleum Company. |
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Undeveloped Acreage
At June 30, 2005, we held undeveloped acreage by state as set forth below:
Undeveloped Acres (1) (2) | ||||||||
Location | Gross | Net | ||||||
Alabama | 200 | 200 | ||||||
California, onshore | 2,880 | 770 | ||||||
Colorado | 619,865 | 524,843 | ||||||
Kansas | 629 | 629 | ||||||
Montana | 24,019 | 19,435 | ||||||
Texas | 5,710 | 4,307 | ||||||
Utah | 68,567 | 26,241 | ||||||
Washington | 720,999 | 164,289 | ||||||
Wyoming | 10,887 | 5,807 | ||||||
Total | 1,453,756 | 746,521 | ||||||
(1) | Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves. | |
(2) | Includes acreage owned by Amber. |
Drilling Activity
During the years indicated, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells:
Years Ended June 30, | ||||||||||||||||||||||||
2005 | 2004 | 2003 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Exploratory Wells (1): | ||||||||||||||||||||||||
Productive: | ||||||||||||||||||||||||
Oil | 5 | 3.94 | 3 | 1.40 | 0 | 0.00 | ||||||||||||||||||
Gas | 3 | 1.15 | 1 | .25 | 0 | 0.00 | ||||||||||||||||||
Nonproductive | 8 | 7.15 | 5 | 3.25 | 3 | 1.55 | ||||||||||||||||||
Total | 16 | 12.24 | 9 | 4.90 | 3 | 1.55 | ||||||||||||||||||
Development Wells (1): | ||||||||||||||||||||||||
Productive: | ||||||||||||||||||||||||
Oil | 6 | 4.90 | 3 | 2.81 | 0 | 0.00 | ||||||||||||||||||
Gas | 82 | 68.80 | 22 | 9.46 | 6 | 5.15 | ||||||||||||||||||
Nonproductive | 7 | 7.00 | 3 | 3.00 | 0 | 0.00 | ||||||||||||||||||
Total | 95 | 80.70 | 28 | 15.27 | 6 | 5.15 | ||||||||||||||||||
Total Wells (1): | ||||||||||||||||||||||||
Productive: | ||||||||||||||||||||||||
Oil | 11 | 8.84 | 6 | 4.21 | 0 | 0.00 | ||||||||||||||||||
Gas | 85 | 69.95 | 23 | 9.71 | 6 | 5.15 | ||||||||||||||||||
Nonproductive | 15 | 14.15 | 8 | 6.25 | 3 | 1.55 | ||||||||||||||||||
Total Wells | 111 | 92.94 | 37 | 20.17 | 9 | 6.70 | ||||||||||||||||||
(1) | Does not include wells in which we had only a royalty interest. |
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Present Drilling Activity
The following represents our planned exploration and development activities for the six months ending December 31, 2005:
Areas of Operations | Drilling Locations | Budget | |||||||||||||||||||
(In millions) | |||||||||||||||||||||
Gulf Coast Region | 7 | — | 9 | $ | 14 | — | $ | 19 | |||||||||||||
Rocky Mountain Region | 22 | — | 27 | $ | 34 | — | $ | 42 | |||||||||||||
Offshore California | 2 | — | 2 | $ | 1 | — | $ | 2 | |||||||||||||
Other | 1 | — | 2 | $ | 1 | — | $ | 2 | |||||||||||||
Total | 32 | — | 40 | $ | 50 | — | $ | 65 | |||||||||||||
Item 3. LEGAL PROCEEDINGS
On January 9, 2002, we and several other plaintiffs filed a lawsuit 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.
The Federal government has not yet filed an answer in this proceeding pending its motion to dismiss the lawsuit, and the plaintiffs have filed a motion for summary judgment as to certain aspects related to their claims. The Court has not yet ruled on either motion.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter of our fiscal year.
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Item 4A. DIRECTORS AND EXECUTIVE OFFICERS
The following information with respect to Executive Officers and Directors is furnished pursuant to Item 401(a) of Regulation S-K.
Name | Age | Positions | Period of Service | |||||
Roger A. Parker | 43 | President, Chief Executive Officer and a Director | May 1987 to Present | |||||
Kevin K. Nanke | 40 | Treasurer and Chief Financial Officer | December 1999 to Present | |||||
John R. Wallace | 44 | Executive V.P., Exploration and Chief Operating Officer | October 2003 to Present | |||||
Kevin R. Collins | 48 | Director | March 2005 to Present | |||||
Jerrie F. Eckelberger | 61 | Director | September 1996 to Present | |||||
Aleron H. Larson, Jr. | 60 | Director | May 1987 to Present | |||||
Russell S. Lewis | 50 | Director | June 2002 to Present | |||||
Jordan R. Smith | 70 | Director | October 2004 to Present | |||||
Neal A. Stanley | 58 | Director | October 2004 to Present | |||||
James P. Van Blarcom | 43 | Director | July 2005 to Present | |||||
James B. Wallace | 75 | Director | November 2001 to Present |
The following is biographical information as to the business experience of each of our current officers and directors.
Roger A. Parker has been our President and a Director since May of 1987 and Chief Executive Officer since April of 2002. He was named Chairman of the Board on July 1, 2005. Since April 1, 2005, he has also served as a 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.
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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.
John R. Wallace, Executive Vice President, Exploration and Chief Operating Officer, joined Delta in October 2003. Since April 1, 2005 he has also served as Executive Vice President and Director of DHS Drilling Company. Mr. Wallace was Vice President of Exploration and Acquisitions for United States Exploration, Inc. (“USX”), a publicly-held oil and gas exploration company, from May 1998 to October 2003, when he became employed by Delta. For more than five years prior to joining USX, Mr. Wallace was President of The Esperanza Corporation, a privately held oil and gas acquisition company, and Vice President of Dual Resources, Inc., a privately held oil and gas exploration company. Esperanza effected more than 25 acquisitions of producing properties throughout the United States. In addition, Esperanza formed and administered royalty programs for private investors, primarily in the Rocky Mountain region, and has participated in a number of international exploration projects. Dual Resources is in the business of engineering and selling exploration prospects, several of which have resulted in new field discoveries. Mr. Wallace is the son of John B. Wallace, a Director of the Company.
Kevin R. Collins was most recently Executive Vice President and Chief Financial Officer of Evergreen Resources, Inc., having served in various management capacities with that company from 1995 until 2004. 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.
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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 since June 2003. From 1996 to June 2003, he was Senior Vice President — Western Region for Forest Oil Corporation. 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 Executive Vice President, Exploration and Chief Operating Officer of Delta.
At the present time Messrs. Collins, Eckelberger, Lewis, Smith and Stanley serve as the Audit Committee; Messrs. Eckelberger, Collins, Lewis, Smith and Stanley serve as the Compensation Committee; and Messrs. Smith, Collins, Eckelberger, Lewis and Stanley serve as the Nominating & Governance Committee.
All directors will hold office until the next annual meeting of shareholders.
All of our officers will hold office until the next annual directors’ meeting. 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.
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PART II
Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Market Information
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.
Quarter Ended | High | Low | ||||||
September 30, 2003 | $ | 5.73 | $ | 4.12 | ||||
December 31, 2003 | 6.30 | 4.75 | ||||||
March 31, 2004 | 11.19 | 6.04 | ||||||
June 30, 2004 | 15.93 | 10.00 | ||||||
September 30, 2004 | $ | 15.47 | $ | 10.01 | ||||
December 31, 2004 | 16.11 | 12.67 | ||||||
March 31, 2005 | 17.07 | 12.87 | ||||||
June 30, 2005 | 14.95 | 8.99 |
On September 12, 2005, the closing price of the Common Stock was $19.84.
Approximate Number of Holders of Common Stock
The number of holders of record of our common stock at September 12, 2005 was approximately 800 which does not include an estimated 2,500 additional holders whose stock is held in “street name.”
Dividends
We have not paid dividends on our common stock and we do not expect to do so in the foreseeable future.
Recent Sales of Unregistered Securities
During the quarter ended June 30, 2005, we issued securities in transactions that were not registered under the Securities Act of 1933 as follows:
On June 30, 2005, we issued a total of 50,243 shares of our common stock as restricted stock grants to 15 new employees under our 2005 New Hire Plan. We intend to register these shares for resale by the employees under the Securities Act of 1933, as amended, in a Form S-8 registration statement.
In connection with these transactions we relied on the exemption provided by Section 4(2) of the Securities Act of 1933. We reasonably believe that the employees were sophisticated investors when the transactions occurred. The employees had access to complete information about Delta. The employees acquired the shares for investment purposes. Restrictive legends were placed on the certificates issued to the employees and stop transfer orders were given to our transfer agent.
Issuer Purchases of Equity Securities
We did not repurchase any of our shares of common stock during the quarter ended June 30, 2005.
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Item 6. SELECTED FINANCIAL DATA
The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.
Years Ended June 30, | ||||||||||||||||||||
2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||||||
Total Revenues | $ | 94,707 | $ | 36,367 | $ | 20,718 | $ | 8,052 | $ | 12,712 | ||||||||||
Income from | ||||||||||||||||||||
Continuing Operations | $ | 11,276 | $ | 2,297 | $ | (241 | ) | $ | (6,156 | ) | $ | 345 | ||||||||
Net Income (Loss) | $ | 15,050 | $ | 5,056 | $ | 1,257 | $ | (6,253 | ) | $ | 345 | |||||||||
Income/(Loss) | ||||||||||||||||||||
Per Common Share | ||||||||||||||||||||
Basic | $ | .37 | $ | .19 | $ | .05 | $ | (.49 | ) | $ | .03 | |||||||||
Diluted | $ | .36 | $ | .17 | $ | .05 | $ | (.49 | ) | $ | .03 | |||||||||
Total Assets | $ | 512,983 | $ | 272,704 | $ | 86,847 | $ | 74,077 | $ | 29,832 | ||||||||||
Total Liabilities | $ | 276,746 | $ | 86,462 | $ | 38,944 | $ | 29,161 | $ | 11,551 | ||||||||||
Minority Interest | $ | 14,614 | $ | 245 | $ | — | $ | — | $ | — | ||||||||||
Stockholders’ Equity | $ | 221,623 | $ | 185,997 | $ | 47,903 | $ | 44,916 | $ | 18,281 | ||||||||||
Total Long-Term Liabilities | $ | 226,073 | $ | 72,386 | $ | 33,082 | $ | 24,939 | $ | 9,434 |
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Fiscal 2005 Accomplishments
• | Increased reserves to 224.3 Bcfe at June 30, 2005, an increase of 33.7% compared to fiscal 2004. | ||
• | Increased production to 14.0 Bcfe for the year ended June 30, 2005, an increase of 84.3% compared to the same period in 2004. | ||
• | Issued $150.0 million in Senior Notes, unsecured, which mature in 2015. | ||
• | Successfully acquired 41.6 Bcfe of proven reserves for $69.0 million. | ||
• | Formed DHS Drilling Company which now has a total of ten drilling rigs with depth ratings from 7,500 – 20,000 feet. |
The following discussion and analysis relates to items that have affected our results of operations for the three years ended June 30, 2005, 2004 and 2003. This analysis should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.
Results of Operations
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.
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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:
Years Ended June 30, | ||||||||||||||||
2005 | 2004 | |||||||||||||||
Onshore | Offshore | Onshore | Offshore | |||||||||||||
Production: | ||||||||||||||||
Oil (MBbl) | 899 | 156 | 552 | 180 | ||||||||||||
Gas (MMcf) | 7,501 | — | 2,841 | — | ||||||||||||
Production – Discontinued Operations: | ||||||||||||||||
Oil (MBbl) | 2 | — | 16 | — | ||||||||||||
Gas (MMcf) | 174 | — | 269 | — | ||||||||||||
Average Price – Continuing Operations: | ||||||||||||||||
Oil (per barrel) | $ | 47.05 | $ | 33.37 | $ | 33.09 | $ | 22.11 | ||||||||
Gas (per Mcf) | $ | 5.79 | $ | — | $ | 5.27 | $ | — | ||||||||
Costs per Mcfe | ||||||||||||||||
Hedge effect | $ | (.07 | ) | $ | — | $ | (.14 | ) | $ | — | ||||||
Lease operating expense | $ | .92 | $ | 4.00 | $ | .70 | $ | 2.98 | ||||||||
Production taxes | $ | .46 | $ | .21 | $ | .31 | $ | .04 | ||||||||
Transportation costs | $ | .04 | $ | — | $ | .04 | $ | — | ||||||||
Depletion expense | $ | 1.57 | $ | .77 | $ | 1.46 | $ | .65 |
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 periods 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
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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. Currently, we are obtaining seismic information on 22.75 square miles in Washington County, Colorado on our North Tongue Prospect and will be expanding our South Tongue Prospect shoot to include a 46 square mile shoot during fiscal 2006.
Drilling and Trucking Operations.In March 2004, we acquired a 50% interest in both the Big Dog Drilling Company and Shark Trucking Company to enable us to have access to drilling rigs and rig transportation facilities on a priority basis. On March 31, 2005, we purchased the remaining interest in Big Dog Drilling Co., LLC (“Big Dog”) for our interest in Shark Trucking, LLC (“Shark”), one of Big Dog’s rigs and related equipment and 100,000 shares of our stock valued at $1.4 million, based on the average stock price five days before and after the announcement of the transaction. On April 15, 2005, we conveyed our interest in Big Dog to DHS Drilling Company in exchange for 4,500,000 shares of DHS Drilling Company’s restricted stock, or 90% of its issued and outstanding shares. The remaining 10% was then owned by two officers of DHS who will earn their interest over five years of employment. Effective May 1, 2005, DHS sold 45% of its restricted stock to Chesapeake Energy, Inc. for $15.0 million. Delta currently owns 49.5% of DHS and controls both the board of directors, access to all drilling rigs for company use and operations. We had drilling and trucking income of $4.8 million offset by drilling and trucking expenses of $4.7 million during the year ended June 30, 2005.
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.
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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:
Years Ended June 30, | ||||||||||||||||
2004 | 2003(1) | |||||||||||||||
Onshore | Offshore | Onshore | Offshore | |||||||||||||
Production: | ||||||||||||||||
Oil (MBbl) | 552 | 180 | 217 | 227 | ||||||||||||
Gas (MMcf) | 2,841 | — | 2,492 | — | ||||||||||||
Production – Discontinued Operations: | ||||||||||||||||
Oil (MBbl) | 16 | — | 35 | — | ||||||||||||
Gas (MMcf) | 269 | — | 446 | — | ||||||||||||
Average Price – Continuing Operations: | ||||||||||||||||
Oil (per barrel) | $ | 33.09 | $ | 22.11 | $ | 28.82 | $ | 20.21 | ||||||||
Gas (per Mcf) | $ | 5.27 | $ | — | $ | 4.71 | $ | — | ||||||||
Costs per Mcfe | ||||||||||||||||
Hedge effect | $ | (.14 | ) | $ | — | $ | (.49 | ) | $ | — | ||||||
Lease operating expense | $ | .70 | $ | 2.98 | $ | .99 | $ | 2.35 | ||||||||
Production taxes | $ | .31 | $ | .04 | $ | .30 | $ | .05 | ||||||||
Transportation costs | $ | .04 | $ | — | $ | .06 | $ | — | ||||||||
Depletion expense | $ | 1.46 | $ | .65 | $ | 1.02 | $ | .79 |
(1) | 2003 information has changed to comply with FAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” |
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.
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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. Currently, we are obtaining seismic information on 22.75 square miles in Washington County, Colorado on our North Tongue Prospect and will be expanding our South Tongue Prospect shoot to include a 75 square mile shoot during fiscal 2005.
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 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 permitted, and through cash provided by operating activities and sale of oil and gas properties. On March 15, 2005, we issued 7% senior notes, unsecured, for an aggregate amount of $150.0 million. At the same time, we also increased our credit facility to $200.0 million with an available borrowing base of $75.0 million, $8.5 million of which is not drawn at June 30, 2005. Subsequent to year end on September 2, 2005 we sold our non-core Deerlick Field located in Tuscaloosa, Alabama for $30.0 million, subject to adjustments.
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.
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We continue to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of 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 that borrowings under the Revolving Credit Facility, projected operating cash flows 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 fiscal 2005, we completed the following transactions:
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% shareholder (“Davis”), 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.
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 November 4, 2004, we entered into an agreement with Davis to acquire the balance of his 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 which is a newly drilled 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 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 January 4, 2005 we acquired additional interests in the South Tongue area of Washington County and also entered into an exploration agreement with Davis in Los Angeles and Orange Counties, California. We paid Davis $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.
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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 use their rigs. As such, the operations of DHS have been consolidated into ours.
On May 4, 2005, we purchased from Savant 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 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 September 7, 2005 we entered into an agreement to purchase an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington, and to purchase an interest in undeveloped acreage in the Piceance Basin in Colorado from Savant for an aggregate purchase price of $85.0 million, on or before September 30, 2005. 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 consolidates our current leasehold position, whereby subsequent to the acquisition we will own a 100% working interest in approximately 310,000 net acres. This acquisition also includes a small portion of acreage that is subject to an agreement with EnCana Oil & Gas (USA) Inc., whereby we will have to a working interest at project payout. In the Piceance Basin, we are acquiring Savant’s interest in an entity that owns a 25% interest in approximately 6,314 gross acres that is currently being developed. The financing alternatives for this acquisition are still being investigated.
Historical Cashflow
Our cashflow 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. Cashflow 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.
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Capital and Exploration Expenditures and Financing
Our capital and exploration expenditures and sources of financing for the years ended June 30, 2005, 2004 and 2003 are as follows:
Year Ended June 30, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
(In thousands) | ||||||||||||
CAPITAL AND EXPLORATION EXPENDITURES: | ||||||||||||
Acquisitions: | ||||||||||||
Manti | $ | 59,700 | $ | — | $ | — | ||||||
Columbia River Basin | 18,255 | — | — | |||||||||
Washington, County South and North Tongue | 10,571 | 30,406 | — | |||||||||
Sacramento Basin | 10,400 | — | — | |||||||||
Karnes County, Texas | 5,000 | — | — | |||||||||
Alpine Resources | — | 120,655 | — | |||||||||
Padgett | — | — | 9,631 | |||||||||
Other | 2,718 | — | — | |||||||||
Development costs | 102,216 | 37,969 | 8,468 | |||||||||
Drilling and trucking companies | 32,690 | 3,965 | — | |||||||||
Exploration costs | 6,155 | 2,406 | 140 | |||||||||
$ | 247,705 | $ | 195,401 | $ | 18,239 | |||||||
FINANCING SOURCES: | ||||||||||||
Cash flow provided by operating activities | $ | 44,862 | $ | 9,623 | $ | 7,999 | ||||||
Stock issued for cash upon exercised options | 132 | 3,563 | 975 | |||||||||
Issuance of common stock for cash | — | 97,902 | — | |||||||||
Net long-term borrowings | 139,051 | 37,157 | 6,921 | |||||||||
Proceeds from sale of oil and gas properties | 18,721 | 10,787 | 850 | |||||||||
Other | 14,863 | (721 | ) | 139 | ||||||||
$ | 217,629 | $ | 158,311 | $ | 16,884 | |||||||
We anticipate our capital and exploration expenditures to range between $50.0 and $65.0 million for the six months ending December 31, 2005. 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, which closed on June 29, 2004, to Whiting Petroleum Corporation 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 9, 2005, we completed the sale of our interest in the Deerlick Field located in Tuscaloosa, Alabama, for cash consideration of $30.0 million and an effective date of July 1, 2005. We expect to record a gain on sale of oil and gas properties of approximately $18.9 million. Revenues from these oil and gas properties were approximately $4.9 million, $3.3 million and $3.0 million for the years ended June 30, 2005, 2004 and 2003, respectively.
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Contractual and Long-Term Debt Obligations
Payments Due by Period | ||||||||||||||||||||
Less than | After | |||||||||||||||||||
Contractual Obligations at June 30, 2005 | 1 year | 2-3 Years | 4-5 Years | 5 Years | Total | |||||||||||||||
(In thousands) | ||||||||||||||||||||
7% Senior unsecured notes | $ | — | $ | — | $ | — | $ | 150,000 | $ | 150,000 | ||||||||||
Interest on 7% Senior unsecured notes | 10,500 | 21,000 | 21,000 | 48,511 | 101,011 | |||||||||||||||
Credit facility | — | — | 66,500 | — | 66,500 | |||||||||||||||
Abandonment retirement obligation | 716 | 123 | 935 | 6,515 | 8,289 | |||||||||||||||
Derivative liability | 7,241 | 3,620 | — | — | 10,861 | |||||||||||||||
Operating leases | 1,998 | 1,643 | 1,542 | 3,564 | 8,747 | |||||||||||||||
Other debt obligations | 143 | 221 | 8 | — | 372 | |||||||||||||||
Total contractual cash obligations | $ | 20,598 | $ | 26,607 | $ | 89,985 | $ | 208,590 | $ | 345,780 | ||||||||||
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
On June 30, 2005, we amended our credit facility with Bank One, N.A., Bank of Oklahoma N.A., U.S. Bank National Association and Hibernia National Bank (the “Banks”). At June 30, 2005, the $200.0 million credit facility had an available borrowing base of approximately $75.0 million and $66.5 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 loan was 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 June 30, 2005, we were not in compliance with our quarterly debt covenants and restrictions, but have obtained a waiver from our banks for the quarter ended June 30, 2005.
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.
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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.
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.
Our corporate office in Denver, Colorado is under an operating lease which will expire in fiscal 2015. Our average yearly payments approximate $772,000 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 June 30, 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, which were all designated as hedges at June 30, 2005:
Price Floor / | Fair Value | |||||||||||||||||||||||||||||||||||||||
Commodity | Volume | Price Ceiling | Term | Index | at June 30, 2005 | |||||||||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||||||||||
Crude oil | 6,000 | Bbls / month | $ | 35.00 | / | $ | 49.75 | Apr ’05 | — | Dec ’05 | NYMEX-WTI | $ | 335 | |||||||||||||||||||||||||||
Crude oil | 40,000 | Bbls / month | $ | 40.00 | / | $ | 50.34 | July ’05 | — | June ’06 | NYMEX-WTI | 4,629 | ||||||||||||||||||||||||||||
Crude oil | 10,000 | Bbls / month | $ | 45.00 | / | $ | 56.90 | July ’05 | — | June ‘06 | NYMEX-WTI | 599 | ||||||||||||||||||||||||||||
Crude oil | 25,000 | Bbls / month | $ | 35.00 | / | $ | 61.80 | July ’06 | — | June ‘07 | NYMEX-WTI | 1,681 | ||||||||||||||||||||||||||||
Natural gas | 3,000 | MMBtu / day | $ | 5.00 | / | $ | 7.85 | Apr ’05 | — | Oct ‘05 | NYMEX-H HUB | 40 | ||||||||||||||||||||||||||||
Natural gas | 10,000 | MMBtu / day | $ | 5.00 | / | $ | 9.60 | July ’05 | — | June ‘06 | NYMEX-H HUB | 995 | ||||||||||||||||||||||||||||
Natural gas | 3,000 | MMBtu / day | $ | 6.00 | / | $ | 9.35 | July ’05 | — | June ‘06 | NYMEX-H HUB | 255 | ||||||||||||||||||||||||||||
Natural gas | 13,000 | MMBtu / day | $ | 5.00 | / | $ | 10.20 | July ’06 | — | June ‘07 | NYMEX-H HUB | 1,466 | ||||||||||||||||||||||||||||
$ | 10,000 | |||||||||||||||||||||||||||||||||||||||
The fair value of our derivative instruments obligation was $10.0 million at June 30, 2005 and $23.3 million on September 12, 2005.
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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 that 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.
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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. We did not record an impairment during the years ended June 30, 2005, 2004 or 2003.
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. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices we receive.
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On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133 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. At June 30, 2005, $6.0 million is in accumulated other comprehensive income and represents the potential reduction in future net revenue and cashflow. 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 current expense or income 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 (CPRM) activities.
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 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 December 2004, the FASB issued its final standard on accounting for employee stock options, FAS No. 123 (Revised 2004), “Share-Based Payment” (“FAS123(R)”). FAS 123(R) replaces FAS No. 123, “Accounting for Stock-Based Compensation” (“FAS 123”), and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” FAS 123(R) requires companies to measure compensation costs for all share-based payments, including grants of employee stock options, based on the fair value of the awards on the grant date and to recognize such expense over the period during which an employee is required to provide services in exchange for the award. The pro forma disclosures previously permitted under FAS 123 will no longer be an alternative to financial statement recognition. FAS 123(R) is effective for all awards granted, modified, repurchased or cancelled after, and to unvested portions of previously issued and outstanding awards vesting after, interim or annual periods, beginning after June 15, 2005, which for us will be the first quarter of fiscal 2006. We are currently evaluating the effect of adopting FAS 123(R) on our financial position and results of operations, and we have not yet determined whether the adoption of FAS 123(R) will result in expenses in amounts that are similar to the current pro forma disclosures under FAS 123.
In February 2005, the staff of the Securities and Exchange Commission sent a letter to oil and gas registrants regarding situations that require additional financial statement disclosures, pending final resolution of accounting treatment. The following are items related to registrants using the successful efforts method of accounting:
• | Companies may enter concurrent commodity buy/sale arrangements, or transactions in contemplation of other transactions, often to assure that the commodity is available at a specific location. Pending resolution of accounting questions with the Emerging Issues Task Force, the Commission staff has requested additional disclosures for any such material arrangements, including separate disclosure on the face of the income statement of any related proceeds and costs reported on a gross basis. These disclosures are not applicable to us since we have not entered any significant transactions of this nature. |
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• | Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, 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. In April 2005, the FASB issued FASB Staff Position 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. FSP 19-1 is effective for all reporting periods beginning after April 4, 2005, however, early application is permitted. Pending adoption of FSP 19-1, the Commission staff has requested additional disclosures be included in registrants’ financial statements regarding their accounting policy for capitalization of exploratory drilling costs, as well as disclosure of capitalized exploratory drilling cost amounts included in the financial statements. We generally pursue development of proved reserves as opposed to exploration activities, and our drill well costs are generally transferred to producing properties within one month of the well completion date. |
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 40% of our current daily production. Assuming production and the percent of oil and gas hedged and the average realized market price of the unhedged oil and gas sold remained unchanged from the year ended June 30, 2005, a hypothetical 10% decline in the average market price the Company realized during the year ended June 30, 2005 on unhedged production would reduce the Company’s oil and natural gas revenues by approximately $9.1 million on an annual basis.
Interest Rate Risk
We were subject to interest rate risk on $66.5 million of variable rate debt obligations at June 30, 2005. The annual effect of a ten percent change in interest rates would be approximately $333,000. The interest rate on these variable rate debt obligations approximates current market rates as of June 30, 2005.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements are included and begin on page F-1. There are no financial statement schedules since they are either not applicable or the information is included in the notes to the financial statements.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
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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 June 30, 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 of 1934, as amended), 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 June 30, 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 June 30, 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.
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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.
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PART III
The information required by Part III, Item 10 “Directors and Executive Officers of the Registrant,” Item 11 “Executive Compensation,” Item 12 “Security Ownership of Certain Beneficial Owners and Management,” Item 13 “Certain Relationships and Related Transactions” and Item 14 “Principal Accounting Fees and Services” is incorporated by reference to the Company’s definitive Proxy Statement which will be filed with the Securities and Exchange Commission in connection with the 2005 Annual Meeting of Shareholders. For information concerning Item 10 “Directors and Executive Officers of the Registrant,” see Part I – Directors and Executive Officers.
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PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)(1) | Financial Statements. |
Page No. | ||||
F-1,2 | ||||
F-3 | ||||
F-4 | ||||
F-5 | ||||
F-6 | ||||
F-7 |
(a)(2) | Financial Statement Schedules. None. | |||
(a)(3) | Exhibits. The Exhibits listed in the Index to Exhibits appearing at page 46 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with a “*”. |
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INDEX TO EXHIBITS
2. | Plans of Acquisition, Reorganization, Arrangement, Liquidation, or Succession. Not applicable. | |
3. | Articles of Incorporation and By-laws. | |
3.1 | Articles of Incorporation and Articles of Amendment to Articles of Incorporation. Incorporated by reference from Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended June 30, 2004. | |
3.2 | By-laws. Incorporated by reference from Exhibit 3.3 to the Company’s Form 10 Registration Statement under the Securities Exchange Act of 1934, filed September 9, 1987. | |
4. | Instruments Defining the Rights of Security Holders. | |
4.1 | Purchase Agreement dated March 9, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.1 to the Company’s Form 8-K dated March 15, 2005. | |
4.2 | Registration Rights Agreement dated March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.2 to the Company’s Form 8-K dated March 15, 2005. | |
4.3 | Indenture dated as of March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and US Bank National Association, as Trustee. Incorporated by reference from Exhibit 4.3 to the Company’s Form 8-K dated March 15, 2005. | |
4.4 | Form of 7% Series A Senior Notes due 2015 with attached notation of Guarantees. Incorporated by reference from Exhibit 4.4 to the Company’s Form 8-K dated March 15, 2005. | |
9. | Voting Trust Agreement. Not applicable. | |
10. | Material Contracts. | |
10.1 | Burdette A. Ogle “Assignment, Conveyance and Bill of Sale of Federal Oil and Gas Leases Reserving a Production Payment,” “Lease Interests Purchase Option Agreement” and “Purchase and Sale Agreement.” Incorporated by reference from Exhibit 28.1 to the Company’s Form 8-K dated January 3, 1995. | |
10.2 | Delta Petroleum Corporation 1993 Incentive Plan, as amended. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1996. * | |
10.3 | Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement dated June 1, 1999. * | |
10.4 | Agreement between Burdette A. Ogle and Delta Petroleum Corporation effective December 17, 1998. Incorporated by reference from Exhibit 99.2 to the Company’s Form 10-QSB for the quarterly period ended December 31, 1998. | |
10.5 | Agreement between Whiting Petroleum Corporation and Delta Petroleum Corporation (including amendment) dated June 8, 1999. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated June 9, 1999. | |
10.6 | Purchase and Sale Agreement dated October 13, 1999 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1999. |
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10.7 | Agreement between Delta Petroleum Corporation, Roger A. Parker and Aleron H. Larson, Jr. dated November 1, 1999. Incorporated by reference from Exhibit 99.3 to the Company’s Form 8-K dated November 1, 1999.* | |
10.8 | Conveyance and Assignment from Whiting Petroleum Corporation dated December 1, 1999. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated December 1, 1999. | |
10.9 | Agreement dated December 30, 1999 between Burdette A. Ogle and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.4 to the Company’s Form 8-K dated January 4, 2000. | |
10.10 | Purchase and Sale Agreement dated June 1, 2000 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated July 10, 2000. | |
10.11 | Delta Petroleum Corporation 2001 Incentive Plan. Incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement dated July 26, 2001 for fiscal year 2000 ended June 30, 2000.* | |
10.12 | Employment Agreements with Aleron H. Larson, Jr., Roger A. Parker and Kevin K. Nanke, from Exhibit 10.4 a, b, and c to the Company’s Form 8-K dated October 25, 2001. * | |
10.13 | Delta Petroleum Corporation 2002 Incentive Plan incorporated by reference from Exhibit A to the Company’s definitive proxy statement filed May 1, 2002. * | |
10.14 | Agreement between Delta Petroleum Corporation and Amber Resources Company dated July 1, 2001, incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated October 25, 2001. | |
10.15 | Letter agreement dated December 3, 2001 between Delta Petroleum Corporation and Ogle Properties LLC, incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K dated October 25, 2001. | |
10.16 | Purchase and Sale Agreement between Castle Energy Company and Delta Petroleum Corporation dated December 31, 2001 incorporated by reference from Exhibit 2.1 to the Company’s Form 8-K dated January 15, 2002. | |
10.17 | Purchase and Sale Agreement between Delta Petroleum Corporation and Tipperary Oil & Gas Corporation dated May 8, 2002 incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated April 30, 2002. | |
10.18 | Credit Agreement dated May 31, 2002 by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated May 24, 2002. | |
10.19 | First Amendment to Credit Agreement dated June 20, 2003 by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated June 20, 2003. | |
10.20 | Agreement with Arguello, Inc. Incorporated by reference from Exhibit 10.22 to the Company’s Form 10-K for the fiscal year ended June 30, 2003. | |
10.21 | Purchase and Sale Agreement dated as of June 5, 2003 between JAED Production Company, Inc. and Delta Petroleum Corporation. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 20, 2003. |
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10.22 | Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated September 19, 2003. | |
10.23 | First Amendment to Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated September 19, 2003. | |
10.24 | Amended and Restated Credit Agreement dated December 30, 2003, by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.1 to the Company’s Form 10-Q dated December 31, 2003. | |
10.25 | Second Amendment to Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K dated April 23, 2004. | |
10.26 | Purchase and Sale Agreement dated June 10, 2004 with various sellers related to Alpine Resources, Inc. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 29, 2004. | |
10.27 | Second Amendment of Amended and Restated Credit Agreement dated June 29, 2004 with Bank of Oklahoma, N.A., US Bank National Association and Hibernia National Bank. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated June 29, 2004. | |
10.28 | Amendment No. 1 to Purchase and Sale Agreement dated July 7, 2004 with Edward Mike Davis and entities controlled by him. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated June 29, 2004. | |
10.29 | Third Amendment to Credit Agreement between Delta Petroleum Corporation and the banks named therein, dated June 30, 2005. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 29, 2005. | |
10.30 | Delta Petroleum Corporation 2005 New-Hire Equity Incentive Plan. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 17, 2005.* | |
10.31 | Amendment No. 1 to Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated June 17, 2005.* | |
10.32 | Employment Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated May 5, 2005.* | |
10.33 | Employment Agreement with Kevin K. Nanke dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.34 | Employment Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.35 | Change in Control Executive Severance Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.36 | Change in Control Executive Severance Agreement with Kevin K. Nanke dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.37 | Change in Control Executive Severance Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.38 | Asset Purchase Agreement dated December 15th, 2004, with Manti Resources, Inc., a Texas corporation, Manti Operating Company, a Texas corporation, Manti Caballos Creek, LTD., a Texas |
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limited partnership, Manti Opossum Hollow, LTD., a Texas limited partnership, J&P Oil and Gas, Inc., a Texas corporation, Lara Energy, Inc., a Texas corporation, and SofRoc Fuel Co., a Texas corporation. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated January 21, 2005. | ||
10.39 | First Amendment to Credit Agreement dated as of January 21, 2005 with JP Morgan Chase Bank, N.A., U.S. Bank N.A., Bank of Oklahoma and Hibernia Bank. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated January 21, 2005. | |
10.40 | Credit Agreement dated November 5, 2004, by and among Delta Petroleum Corporation, Bank One, NA, Bank of Oklahoma, N.A., and U.S. Bank National Association. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated November 5, 2004. | |
10.41 | Fourth Amendment to Purchase and Sale Agreement with Edward Mike Davis, et al. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated November 4, 2004. | |
11. | Statement Regarding Computation of Per Share Earnings. Not applicable. | |
12. | Statement Regarding Computation of Ratios. Not applicable. | |
13. | Code of Ethics. The Company’s Code of Business Conduct and Ethics is posted on the Company’s website at www.deltapetro.com. | |
16. | Letter re: change in certifying accountant. Not applicable. | |
18. | Letter re: change in accounting principles. Not applicable. | |
21. | Subsidiaries of the Registrant. Filed herewith electronically. | |
22. | Published report regarding matters submitted to vote of security holders. Not applicable. | |
23. | Consents of experts and counsel. | |
23.1 | Consent of KPMG LLP. Filed herewith electronically. | |
23.2 | Consent of Ralph E. Davis Associates, Inc. Filed herewith electronically. | |
23.3 | Consent of Mannon Associates. Filed herewith electronically. | |
24. | Power of attorney. Not applicable. | |
31. | Rule 13a-14(a)/ 15d-14(a) Certifications. | |
31.1 | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically. | |
31.2 | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically. | |
32. | Section 1350 Certifications. | |
32.1 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically. | |
32.2 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically. |
* | Management contracts and compensatory plans. |
53
Table of Contents
Report of Independent Registered Public Accounting Firm
The Board of Directors
Delta Petroleum Corporation:
Delta Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation and subsidiaries as of June 30, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for the 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 June 30, 2005 and 2004, and the results of their operations and their cash flows for 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 June 30, 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 September 15, 2005 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.
/s/ KPMG
Denver, Colorado
September 15, 2005
September 15, 2005
F-1
Table of Contents
Report of Independent Registered Public Accounting Firm
The Board of Directors
Delta Petroleum Corporation:
Delta Petroleum Corporation:
We have audited management’s assessment, included in Item 9AManagement’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 June 30, 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 June 30, 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 June 30, 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 June 30, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years ended June 30, 2005, 2004 and 2003 and our report dated September 15, 2005 expressed an unqualified opinion on those consolidated financial statements.
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.
/s/ KPMG
Denver, Colorado
September 15, 2005
September 15, 2005
F-2
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, | June 30, | |||||||
2005 | 2004 | |||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 2,241 | $ | 2,078 | ||||
Marketable securities available for sale | 1,764 | 912 | ||||||
Trade accounts receivable, net of allowance for doubtful accounts, of $100 and $50, respectively | 10,512 | 9,092 | ||||||
Prepaid assets | 2,980 | 1,136 | ||||||
Inventory | 5,062 | 1,350 | ||||||
Deferred tax asset | 2,676 | — | ||||||
Derivative instruments | 378 | — | ||||||
Other current assets | 1,421 | 385 | ||||||
Total current assets | 27,034 | 14,953 | ||||||
Property and equipment: | ||||||||
Oil and gas properties, successful efforts method of accounting: | ||||||||
Unproved | 101,935 | 49,747 | ||||||
Proved | 365,306 | 223,145 | ||||||
Drilling equipment, including deposits on equipment of $7.5 million | 40,031 | 3,965 | ||||||
Other | 10,412 | 1,147 | ||||||
Total property and equipment | 517,684 | 278,004 | ||||||
Less accumulated depreciation and depletion | (44,134 | ) | (21,665 | ) | ||||
Net property and equipment | 473,550 | 256,339 | ||||||
Long-term assets: | ||||||||
Investment in LNG project | 1,022 | 1,022 | ||||||
Deferred financing costs | 5,825 | 131 | ||||||
Deferred tax assets | 4,887 | — | ||||||
Derivative instruments | 469 | — | ||||||
Other long-term assets | 196 | 259 | ||||||
Total long-term assets | 12,399 | 1,412 | ||||||
Total assets | $ | 512,983 | $ | 272,704 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 3,477 | $ | 109 | ||||
Accounts payable | 38,151 | 12,326 | ||||||
Other accrued liabilities | 5,281 | 1,855 | ||||||
Derivative instruments | 7,241 | — | ||||||
Total current liabilities | 54,150 | 14,290 | ||||||
Long-term liabilities: | ||||||||
7% Senior notes, unsecured | 149,272 | — | ||||||
Credit facility | 66,500 | 69,375 | ||||||
Asset retirement obligation | 2,975 | 2,542 | ||||||
Derivative instruments | 3,620 | — | ||||||
Other debt, net | 229 | 255 | ||||||
Total long-term liabilities | 222,596 | 72,172 | ||||||
Minority interest | 14,614 | 245 | ||||||
Commitments | ||||||||
Stockholders’ equity: | ||||||||
Preferred stock, $.10 par value: authorized 3,000,000 shares, none issued | — | — | ||||||
Common stock, $.01 par value; authorized 300,000,000 shares, issued 42,017000 shares at June 30, 2005 and 38,447,000 shares at June 30, 2004 | 420 | 384 | ||||||
Additional paid-in capital | 235,300 | 207,811 | ||||||
Unearned compensation | (1,382 | ) | — | |||||
Accumulated other comprehensive (loss) income | (5,225 | ) | 342 | |||||
Accumulated deficit | (7,490 | ) | (22,540 | ) | ||||
Total stockholders’ equity | 221,623 | 185,997 | ||||||
Total liabilities and stockholders’ equity | $ | 512,983 | $ | 272,704 | ||||
See accompanying notes to consolidated financial statements.
F-3
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended June 30, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Revenue: | ||||||||||||
Oil and gas sales | $ | 90,871 | $ | 37,226 | $ | 22,576 | ||||||
Drilling and trucking | 4,796 | — | — | |||||||||
Realized loss on derivative instruments, net | (960 | ) | (859 | ) | (1,858 | ) | ||||||
Total revenue | 94,707 | 36,367 | 20,718 | |||||||||
Operating expenses: | ||||||||||||
Lease operating expense | 15,566 | 7,530 | 6,966 | |||||||||
Transportation expense | 575 | 259 | 230 | |||||||||
Production taxes | 6,128 | 1,978 | 1,214 | |||||||||
Depreciation and depletion | 23,207 | 9,914 | 4,999 | |||||||||
Exploration expense | 6,155 | 2,406 | 140 | |||||||||
Dry hole costs | 2,771 | 2,132 | 537 | |||||||||
Drilling and trucking operations | 4,666 | 232 | — | |||||||||
Professional fees | 2,010 | 1,174 | 842 | |||||||||
General and administrative | 14,920 | 6,875 | 4,295 | |||||||||
Total operating expenses | 75,998 | 32,500 | 19,223 | |||||||||
Operating income | 18,709 | 3,867 | 1,495 | |||||||||
Other income and (expense): | ||||||||||||
Other income (expense) | (492 | ) | 122 | 31 | ||||||||
Minority interest | 1,017 | 70 | — | |||||||||
Interest and financing costs | (7,958 | ) | (1,762 | ) | (1,767 | ) | ||||||
Total other expense | (7,433 | ) | (1,570 | ) | (1,736 | ) | ||||||
Income (loss) from continuing operations | 11,276 | 2,297 | (241 | ) | ||||||||
Income tax expense (benefit): | ||||||||||||
Current | — | — | — | |||||||||
Deferred | (3,325 | ) | — | — | ||||||||
Total income tax (benefit) | (3,325 | ) | — | — | ||||||||
Net earnings from continuing operations | 14,601 | 2,297 | (241 | ) | ||||||||
Income from discontinued operations of properties sold, net of tax | 449 | 872 | 1,241 | |||||||||
Gain on sale of discontinued operations, net of tax | — | 1,887 | 277 | |||||||||
Cumulative effect of change in accounting principle, net of tax | — | — | (20 | ) | ||||||||
Net income | $ | 15,050 | $ | 5,056 | $ | 1,257 | ||||||
Basic income (loss) per common share: | ||||||||||||
Net income (loss) from continuing operations | $ | .36 | $ | .09 | $ | (.01 | ) | |||||
Discontinued operations, net of tax | .01 | .10 | .06 | |||||||||
Cumulative effect of change in accounting principle, net of tax | — | — | * | |||||||||
Basic net income per share | $ | .37 | $ | .19 | $ | .05 | ||||||
Diluted income per common share: | ||||||||||||
Net earnings (loss) from continuing operations | $ | .36 | $ | .08 | $ | (.01 | ) | |||||
Discontinued operations, net of tax | .01 | .09 | .06 | |||||||||
Cumulative effect of change in accounting principle | — | — | * | |||||||||
Diluted net income per share | $ | .36 | $ | .17 | $ | .05 | ||||||
* | Less than $.01 per common share |
See accompanying notes to consolidated financial statements.
F-4
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Consolidated Statement of Changes in Stockholders’
Equity and Comprehensive Income (Loss)
Equity and Comprehensive Income (Loss)
Accumulated | ||||||||||||||||||||||||||||||||||||
Additional | other | |||||||||||||||||||||||||||||||||||
Common stock | paid-in | comprehensive | Comprehensive | Unearned | Accumulated | |||||||||||||||||||||||||||||||
Shares | Amount | capital | income/(loss) | income (loss) | Compensation | deficit | Total | |||||||||||||||||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||||||||||||||||||||||
Balance, July 1, 2002 | 22,618 | $ | 226 | $ | 76,514 | $ | (85 | ) | $ | (28,853 | ) | $ | 44,916 | |||||||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||||||||||||
Net income | — | — | — | — | $ | 1,257 | 1,257 | 1,257 | ||||||||||||||||||||||||||||
Other comprehensive income, net of tax | ||||||||||||||||||||||||||||||||||||
Change in fair value of derivative hedging instruments | — | — | — | (468 | ) | (468 | ) | — | (468 | ) | ||||||||||||||||||||||||||
Unrealized gain on marketable securities, net | — | — | — | 177 | 177 | — | 177 | |||||||||||||||||||||||||||||
Comprehensive income | — | — | — | — | $ | 966 | ||||||||||||||||||||||||||||||
Stock options granted as compensation | — | — | 124 | — | 124 | |||||||||||||||||||||||||||||||
Put option on Delta Stock | — | — | (2,886 | ) | — | |||||||||||||||||||||||||||||||
Shares issued for oil and gas properties | 200 | 2 | 920 | — | — | 922 | ||||||||||||||||||||||||||||||
Shares issued for cash upon exercise of options | 468 | 5 | 970 | — | — | 975 | ||||||||||||||||||||||||||||||
Balance, June 30, 2003 | 23,286 | 233 | 75,642 | (376 | ) | (27,596 | ) | 47,903 | ||||||||||||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||||||||||||
Net income | — | — | — | — | $ | 5,056 | 5,056 | 5,056 | ||||||||||||||||||||||||||||
Other comprehe- nsive gain, net of tax | ||||||||||||||||||||||||||||||||||||
Change in fair value of derivative hedging instruments | — | — | — | 468 | 468 | — | 468 | |||||||||||||||||||||||||||||
Unrealized gain on market- able securities, net | — | — | — | 250 | 250 | — | 250 | |||||||||||||||||||||||||||||
Comprehensive income | — | — | — | — | $ | 5,774 | ||||||||||||||||||||||||||||||
Stock options granted as compensation | 329 | — | — | 329 | ||||||||||||||||||||||||||||||||
Shares issued for cash, net | 10,000 | 100 | 97,802 | — | — | 97,902 | ||||||||||||||||||||||||||||||
Shares issued for oil and gas properties | 3,728 | 37 | 30,489 | — | — | 30,526 | ||||||||||||||||||||||||||||||
Shares issued for cash upon exercise of options | 1,433 | 14 | 3,549 | — | — | 3,563 | ||||||||||||||||||||||||||||||
Balance, June 30, 2004 | 38,447 | 384 | 207,811 | 342 | (22,540 | ) | 185,997 | |||||||||||||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||||||||||||
Net income | — | — | — | — | $ | 15,050 | 15,050 | 15,050 | ||||||||||||||||||||||||||||
Other comprehensive gain, net of tax | ||||||||||||||||||||||||||||||||||||
Change in fair value of derivative hedging instruments, net of tax benefit of $3,722 | — | — | — | (5,961 | ) | (5,961 | ) | — | (5,961 | ) | ||||||||||||||||||||||||||
Unrealized gain on marketable securities, net of tax expense of $458 | — | — | — | 394 | 394 | — | 394 | |||||||||||||||||||||||||||||
Comprehensive income | — | — | — | — | $ | 9,483 | ||||||||||||||||||||||||||||||
Shares issued for oil and gas properties | 1,571 | 16 | 22,175 | — | — | 22,191 | ||||||||||||||||||||||||||||||
Shares issued for drilling equipment | 131 | 1 | 1,892 | — | — | 1,893 | ||||||||||||||||||||||||||||||
Shares issued for cash upon exercise of options, net | 1,793 | 18 | 114 | — | — | 132 | ||||||||||||||||||||||||||||||
Tax benefit on options exercised | — | — | 1,255 | — | — | 1,255 | ||||||||||||||||||||||||||||||
Issuance of options below market | — | — | 346 | — | $ | (346 | ) | — | — | |||||||||||||||||||||||||||
Issuance of restricted options | 75 | 1 | 1,707 | — | (1,708 | ) | — | — | ||||||||||||||||||||||||||||
Amortization of unearned option compensation | — | — | — | — | 672 | — | 672 | |||||||||||||||||||||||||||||
Balance, June 30, 2005 | 42,017 | $ | 420 | $ | 235,300 | $ | (5,225 | ) | $ | (1,382 | ) | $ | (7,490 | ) | $ | 221,623 | ||||||||||||||||||||
See accompanying notes to consolidated financial statements.
F-5
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended June 30, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
(In thousands) | ||||||||||||
Cash flows operating activities: | ||||||||||||
Net income | $ | 15,050 | $ | 5,056 | $ | 1,257 | ||||||
Adjustments to reconcile net income to cash used in operating activities: | ||||||||||||
Depreciation and depletion | 22,954 | 9,854 | 4,942 | |||||||||
Depreciation and depletion – discontinued operations | 208 | 328 | 791 | |||||||||
Accretion of abandonment obligation | 253 | 60 | 57 | |||||||||
Stock compensation expense | 672 | 329 | 124 | |||||||||
Amortization of financing costs | 858 | 324 | 456 | |||||||||
Minority interest | (1,017 | ) | (70 | ) | — | |||||||
Gain on sale of oil and gas properties | — | (1,887 | ) | (277 | ) | |||||||
Unrealized loss on derivative instruments, net | 331 | — | — | |||||||||
Deferred income tax benefit, net | (3,045 | ) | — | — | ||||||||
Other | 394 | — | 20 | |||||||||
Net changes in operating assets and operating liabilities: | ||||||||||||
Increase in trade accounts receivable | (1,586 | ) | (4,878 | ) | (101 | ) | ||||||
(Increase) decrease in prepaid assets | (1,844 | ) | (372 | ) | 21 | |||||||
Increase in inventory | (5,062 | ) | (1,350 | ) | — | |||||||
(Increase) decrease in other current assets | (225 | ) | 205 | (78 | ) | |||||||
Increase in accounts payable | 14,004 | 1,361 | 116 | |||||||||
Increase in other accrued liabilities | 2,917 | 663 | 671 | |||||||||
Net cash provided by operating activities | 44,862 | 9,623 | 7,999 | |||||||||
Cash flows from investing activities: | ||||||||||||
Additions to property and equipment, net | (186,669 | ) | (158,504 | ) | (15,637 | ) | ||||||
Additions to drilling and trucking equipment, net | (30,797 | ) | — | — | ||||||||
Proceeds from sale of oil and gas properties | 18,721 | 10,787 | 850 | |||||||||
Minority interest contributions, net | 14,800 | 315 | — | |||||||||
Payment on investment transaction | — | (1,022 | ) | — | ||||||||
Increase (decrease) in long term assets | 63 | (14 | ) | 139 | ||||||||
Net cash used in investing activities | (183,882 | ) | (148,438 | ) | (14,648 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Stock issued for cash upon exercise of options | 132 | 3,563 | 975 | |||||||||
Issuance of common stock for cash | — | 97,902 | — | |||||||||
Proceeds from borrowings | 361,016 | 69,979 | 9,000 | |||||||||
Payment of financing fees | (7,370 | ) | (368 | ) | (354 | ) | ||||||
Repayment of borrowings | (214,595 | ) | (32,454 | ) | (1,725 | ) | ||||||
Net cash provided by financing activities | 139,183 | 138,622 | 7,896 | |||||||||
Net increase (decrease) in cash and cash equivalents | 163 | (193 | ) | 1,247 | ||||||||
Cash at beginning of period | 2,078 | 2,271 | 1,024 | |||||||||
Cash at end of period | $ | 2,241 | $ | 2,078 | $ | 2,271 | ||||||
Supplemental cash flow information: | ||||||||||||
Cash paid for interest and financing costs | $ | 11,420 | $ | 1,818 | $ | 1,312 | ||||||
Non-cash financing activities: | ||||||||||||
Common stock issued for the purchase of oil and gas properties | $ | 22,191 | $ | 30,526 | $ | 922 | ||||||
Common stock issued for the purchase of drilling equipment | $ | 1,893 | $ | — | $ | — | ||||||
See accompanying notes to consolidated financial statements.
F-6
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
June 30, 2005, 2004 and 2003
(1) Nature of Organization
Delta Petroleum Corporation (“Delta” or the “Company”) was organized December 21, 1984 and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. The core areas of operation are the Rocky Mountain and Gulf Coast regions, which comprise the majority of our proved reserves, production and long-term growth prospects. 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 late fiscal 2005, owns a 49.5% (Delta effectively owns an additional portion of DHS’s interest until such time as the officers of DHS earn their 5.5% interest over the next five years) interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. DHS currently has seven drilling rigs in operation that have depth ratings of approximately 7,500 to 20,000 feet. Three additional rigs are in the process of being acquired or assembled by DHS and are currently expected to become operational during the summer and fall of 2005. The Company has the right to use all of the rigs on a priority basis, although approximately half will initially work for third party operators. At the outset, all of the rigs will operate in the Rocky Mountain basins.
At June 30, 2004, the Company owned 4,277,977 shares of the common stock of Amber Resources Company (“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.
(2) Summary of Significant Accounting Policies
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of Delta, Amber, Piper and DHS (collectively, the Company). All inter-company balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods. Certain reclassifications have been made to amounts reported in previous years to conform to the 2004 presentation. The Company has no interests in any other 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. Partnership net assets represent the Company’s share of net working capital in such entities.
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.
F-7
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
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.
Unrealized | Estimated | |||||||||||
Cost | Gain (Loss) | Market Value | ||||||||||
(In thousands) | ||||||||||||
June 30, 2005 | ||||||||||||
Bion Environmental Technologies, Inc. | $ | 152 | $ | (140 | ) | $ | 12 | |||||
Tipperary Oil & Gas Company | 418 | 1,334 | 1,752 | |||||||||
$ | 570 | $ | 1,194 | $ | 1,764 | |||||||
June 30, 2004 | ||||||||||||
Bion Environmental Technologies, Inc. | $ | 152 | $ | (138 | ) | $ | 14 | |||||
Tipperary Oil & Gas Company | 418 | 480 | 898 | |||||||||
$ | 570 | $ | 342 | $ | 912 | |||||||
June 30, 2003 | ||||||||||||
Bion Environmental Technologies, Inc. | $ | 152 | $ | (140 | ) | $ | 12 | |||||
Tipperary Oil & Gas Company | 418 | 232 | 650 | |||||||||
$ | 570 | $ | 92 | $ | 662 | |||||||
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% Chesapeake Energy Corporation, 2.75% each for William E. Sauer, Jr. and Harold D. Hastings) investors of DHS Drilling Company at June 30, 2005 and the 50% investor in Big Dog Drilling Co., LLC (“Big Dog”) and Shark Trucking Co., LLC (“Shark”) at June 30, 2004.
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. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of 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 has been collected subsequent to year end.
F-8
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
Drilling
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. Individual wells are usually completed in less than 60 days. The cost of drilling the Company’s own oil and gas properties are capitalized in oil and gas properties as the expenditures are incurred.
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 years ended June 30, 2005, 2004 and 2003 were $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 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 years ended June 30, 2005, 2004 and 2003.
F-9
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
For undeveloped properties, the need for an impairment reserve 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.
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 years ended June 30, 2005 and 2004.
Years Ended June 30, | ||||||||
2005 | 2004 | |||||||
(In thousands) | ||||||||
Asset retirement obligation — beginning of period | $ | 2,647 | $ | 868 | ||||
Accretion expense | 253 | 60 | ||||||
Change in estimate | — | 438 | ||||||
Obligations acquired | 1,153 | 1,522 | ||||||
Obligations settled | — | (3 | ) | |||||
Obligations on sold properties | (362 | ) | (238 | ) | ||||
Asset retirement obligation — end of period | 3,691 | 2,647 | ||||||
Less: Current asset retirement obligation | (716 | ) | (105 | ) | ||||
Long-term asset retirement obligation | $ | 2,975 | $ | 2,542 | ||||
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.
F-10
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
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.
In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS 133 establishes accounting and reporting standards requiring 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. It also requires 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.
Stock Option Plans
The Company accounts 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, 2002 the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure.” SFAS 148 amends FASB Statement No. 123, “Accounting for Stock-Based Compensation” to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provision of SFAS 148 has no material impact on the Company, as we do not plan to adopt the fair-value method of accounting for stock options at the current time. Accordingly, no compensation cost is recognized for options granted at a price equal to or greater than the fair market value of the common stock.
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 years ended June 30, 2005, 2004 and 2003 on a proforma basis would have been as follows:
Years Ended June 30, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Net income | $ | 15,050 | $ | 5,056 | $ | 1,257 | ||||||
Equity compensation booked | 306 | — | — | |||||||||
FAS 123 compensation effect | (2,759 | ) | (4,316 | ) | (209 | ) | ||||||
Proforma net Income after FAS 123 compensation effect | $ | 12,597 | $ | 740 | $ | 1,048 | ||||||
Proforma income per common share: | ||||||||||||
Basic | $ | .31 | $ | .03 | $ | .05 | ||||||
Diluted | $ | .30 | $ | .02 | $ | .04 | ||||||
F-11
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
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.
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 include oil and gas reserves, bad debts, oil and gas properties, depletion and impairment, marketable securities, income taxes, derivatives, asset retirement obligations, contingencies and litigation. 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 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 the Company’s consolidated results of operations, financial position or cash flows.
F-12
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
In December 2004, the FASB issued its final standard on accounting for employee stock options, FAS No. 123 (Revised 2004), “Share-Based Payment” (“FAS123(R)”). FAS 123(R) replaces FAS No. 123, “Accounting for Stock-Based Compensation” (“FAS 123”), and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” FAS 123(R) requires companies to measure compensation costs for all share-based payments, including grants of employee stock options, based on the fair value of the awards on the grant date and to recognize such expense over the period during which an employee is required to provide services in exchange for the award. The pro forma disclosures previously permitted under FAS 123 will no longer be an alternative to financial statement recognition. FAS 123(R) is effective for all awards granted, modified, repurchased or cancelled after, and to unvested portions of previously issued and outstanding awards vesting after, interim or annual periods, beginning after June 15, 2005, which for us will be the first quarter of fiscal 2006. The Company is currently evaluating the effect of adopting FAS 123(R) on its financial position and results of operations, and have not yet determined whether the adoption of FAS 123(R) will result in expenses in amounts that are similar to the current pro forma disclosures under FAS 123.
In February 2005, the staff of the Securities and Exchange Commission sent a letter to oil and gas registrants regarding situations that require additional financial statement disclosures, pending final resolution of accounting treatment. The following are items related to registrants using the successful efforts method of accounting:
• | Companies may enter concurrent commodity buy/sale arrangements, or transactions in contemplation of other transactions, often to assure that the commodity is available at a specific location. Pending resolution of accounting questions with the Emerging Issues Task Force, the Commission staff has requested additional disclosures for any such material arrangements, including separate disclosure on the face of the income statement of any related proceeds and costs reported on a gross basis. These disclosures are not applicable to the Company since we have not entered any significant transactions of this nature. | ||
• | Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, 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. In April 2005, the FASB issued FASB Staff Position 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. FSP 19-1 is effective for all reporting periods beginning after April 4, 2005, however, early application is permitted. Pending adoption of FSP 19-1, the Commission staff has requested additional disclosures be included in registrants’ financial statements regarding their accounting policy for capitalization of exploratory drilling costs, as well as disclosure of capitalized exploratory drilling cost amounts included in the financial statements. The Company generally pursues development of proved reserves as opposed to exploration activities, and drill well costs are generally transferred to producing properties within one month of the well completion date. |
F-13
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(2) Summary of Significant Accounting Policies, Continued
In December 2004, the FASB issued its final standard on accounting for employee stock options, FAS No. 123 (Revised 2004), “Share-Based Payment” (“FAS123(R)”). FAS 123(R) replaces FAS No. 123, “Accounting for Stock-Based Compensation” (“FAS 123”), and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”. FAS 123(R) requires companies to measure compensation costs for all share-based payments, including grants of employee stock options, based on the fair value of the awards on the grant date and to recognize such expense over the period during which an employee is required to provide services in exchange for the award. The pro forma disclosures previously permitted under FAS 123 will no longer be an alternative to financial statement recognition. FAS 123(R) is effective for all awards granted, modified, repurchased or cancelled after, and to unvested portions of previously issued and outstanding awards vesting after, interim or annual periods beginning after June 15, 2005, which for us will be the first quarter of fiscal 2006. We are currently evaluating the effect of adopting FAS 123(R) on our financial position and results of operations, and we have not yet determined whether the adoption of FAS 123(R) will result in expenses in amounts that are similar to the current pro forma disclosures under FAS 123.
(3) Oil and Gas Properties
Unproved Undeveloped Offshore California Properties
The Company has ownership interests ranging from 2.49% to 75% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $10.9 million and $10.8 million at 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 as discussed herein.
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.
F-14
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(3) Oil and Gas Properties, Continued
Based on the preliminary indicated 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 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.
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.
On January 9, 2002, the Company and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of the forty undeveloped federal leases, some of which are part of the Company’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 Norton case that a 1990 amendment to the CZMA required the DELTA 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.
F-15
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(3) Oil and Gas Properties, Continued
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’s claim for lease bonuses and rentals paid by it and its predecessors is in excess of $152.0 million. In addition, the Company’s claim for exploration costs and related expenses will also be substantial. In the event, however, that the Company 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, and to pay expenses of litigation and to fulfill certain pre-existing contractual commitments to third parties.
Fiscal 2005 and 2004 — Significant 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 we acquired from Manti have been pledged as collateral for we 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:
Years Ended June 30, | ||||||||
2005 | 2004 | |||||||
(In thousands) | ||||||||
Oil and gas sales | $ | 113,059 | $ | 86,272 | ||||
Net earnings from continuing operations, net of tax | $ | 19,142 | $ | 15,514 | ||||
Net earnings from continuing operations per common share, net of tax: | ||||||||
Basic | $ | .47 | $ | .47 | ||||
Diluted | $ | .46 | $ | .44 |
F-16
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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.
Fiscal 2005 — Additional Acquisitions
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% shareholder (“Davis”), 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 — Additional 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 June 30, 2005, the limited liability company had not yet engaged in any revenue producing activities.
Fiscal 2003 — Acquisitions
On June 20, 2003, the Company acquired producing oil and gas interests and related undeveloped acreage in Kansas from JAED Production Company for total consideration of $8.7 million net of normal closing adjustments. On the date of acquisition, the Company estimated proved reserves to be approximately 9.9 Bcfe.
F-17
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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.
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% shareholder of Delta at March 31, 2004, for cash consideration of $8 million, which the Company believes is fair value, 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 nine months ended March 31, 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 nine months ended March 31, 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 4, 2005, the Company acquired a 49.5% ownership interest in DHS Drilling Company. The investment includes all of the net assets of the then 100% owned subsidiary, Big Dog, and certain drilling assets acquired by the Company. On March 31, 2005, the Company 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. DHS currently has seven drilling rigs in operation that have depth ratings of approximately 7,500 to 20,000 feet. Three additional rigs are in the process of being acquired or assembled by DHS and are currently expected to become operational during the summer and fall of 2005. The Company has the right to use all of the rigs on a priority basis, although approximately half will initially work for third party operators. At the outset, all of the rigs will operate in the Rocky Mountain basins.
F-18
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(5) Long Term Debt
7% Senior Notes, Due 2015, Unsecured
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 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 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 June 30, 2005. See “Guarantee of Financial Information” footnote below (Footnote 12). The fair value of the Company’s senior notes at June 30, 2005 was $141.0 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 June 30, 2005, the $200.0 million credit facility had an available borrowing base of approximately $75.0 million and $66.5 million outstanding. The reduction in available borrowing base was established until certain drilling results were attained. The Company anticipates 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 rate at June 30, 2005 approximated 7%. The loan was 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 of $7 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 June 30, 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 June 30, 2005.
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.
Maturities of long-term debt, in thousands of dollars based on contractual terms are as follows:
YEAR ENDING June 30, | ||||
2006 | $ | 3,477 | ||
2007 | 149 | |||
2008 | 72 | |||
2009 | 66,508 | |||
2010 | — | |||
Thereafter | 150,000 | |||
$ | 220,206 | |||
F-19
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(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 June 30, 2005, 2004 and 2003, no preferred stock was issued.
Common Stock
The Company raised additional capital through the sale of 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. The Company did not raise cash through the issuance of shares of its common stock during the years ended June 30, 2005 and 2003.
During the years ended June 30, 2005, 2004 and 2003, the Company acquired oil and gas properties for 1,571,000, 3,728,000, and 200,000 shares of the Company’s common stock, respectively. The shares were valued at $22.2 million, $30.5 million and $922,000, respectively.
During fiscal 2005, the Company acquired drilling equipment for 131,000 shares of the Company’s common stock valued at $1.9 million.
Non-Qualified Stock Options — Directors and Employees
On 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 supercedes the Company’s 1993 and 2001 Incentive Plans.
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 years ended June 30, 2005, 2004 and 2003 follows:
2005 | 2004 | 2003 | ||||||||||||||||||||||
Weighted-Average | Weighted-Average | Weighted-Average | ||||||||||||||||||||||
Exercise | Exercise | Exercise | ||||||||||||||||||||||
Options | Price | Options | Price | Options | Price | |||||||||||||||||||
Outstanding-beginning of year | 4,700,772 | $ | 4.10 | 3,410,987 | $ | 3.15 | 3,378,487 | $ | 3.07 | |||||||||||||||
Granted | 1,034,700 | 14.71 | 1,736,000 | 5.63 | 255,000 | 2.79 | ||||||||||||||||||
Exercised | (2,189,071 | ) | (3.33 | ) | (435,215 | ) | (2.51 | ) | (217,500 | ) | (1.59 | ) | ||||||||||||
Expired / Returned | (45,000 | ) | (14.37 | ) | (11,000 | ) | (6.39 | ) | (5,000 | ) | (3.20 | ) | ||||||||||||
Outstanding-end of year | 3,501,401 | $ | 7.59 | 4,700,772 | $ | 4.10 | 3,410,987 | $ | 3.15 | |||||||||||||||
Exercisable-end of year | 1,580,534 | $ | 5.01 | 4,300,772 | $ | 4.11 | 3,240,987 | $ | 3.15 | |||||||||||||||
F-20
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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 the years ended June 30, 2004 and 2003, respectively, for options issued below market prices.
Exercise prices for options outstanding under the Company’s various plans as of June 30, 2005 ranged from $1.13 to $15.46 per share. The weighted-average remaining contractual life of those unvested options is 5.95 years. At June 30, 2005 1,920,867 options were unvested. A summary of the outstanding and exercisable options at June 30, 2005, segregated by exercise price ranges, is as follows:
Weighted | ||||||||||||||||||||
Average | ||||||||||||||||||||
Weighted | Remaining | Weighted | ||||||||||||||||||
Exercise | Average | Contractual | Average | |||||||||||||||||
Price | Options | Exercise | Life | Exercisable | Exercise | |||||||||||||||
Range | Outstanding | Price | (in years) | Options | Price | |||||||||||||||
$1.13 — $ 3.25 | 590,951 | $ | 2.28 | 5.23 | 590,951 | $ | 2.28 | |||||||||||||
$3.26 — $15.46 | 2,910,450 | $ | 8.67 | 6.80 | 989,583 | $ | 6.65 |
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.
Non-Qualified Stock Options (Non-Employee)
The Company has 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 and none for the years ended June 30, 2005 and 2004.
A summary of the stock option and warrant activity and related information for the years ended June 30, 2005, 2004 and 2003 is as follows:
2005 | 2004 | 2003 | ||||||||||||||||||||||
Weighted-Average | Weighted-Average | Weighted-Average | ||||||||||||||||||||||
Exercise | Exercise | Exercise | ||||||||||||||||||||||
Options | Price | Options | Price | Options | Price | |||||||||||||||||||
Outstanding-beginning of year | 57,500 | $ | 3.80 | 1,255,000 | $ | 3.38 | 1,954,000 | $ | 3.62 | |||||||||||||||
Granted | — | — | — | — | — | — | ||||||||||||||||||
Exercised | 57,500 | 3.80 | (1,197,500 | ) | (2.48 | ) | (250,761 | ) | (2.51 | ) | ||||||||||||||
Expired | — | — | — | — | (448,239 | ) | (4.76 | ) | ||||||||||||||||
Outstanding-end of year | — | $ | — | 57,500 | $ | 3.80 | 1,255,000 | $ | 3.38 | |||||||||||||||
Exercisable at end of year | — | $ | — | 57,500 | $ | 3.80 | 1,255,000 | $ | 3.38 | |||||||||||||||
F-21
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
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 will 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 of the employee’s compensation.
For the years ended June 30, 2005, 2004 and 2003 the Company contributed $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 which the Company adopted on January 1, 2001. 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 June 30, 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 activities.
F-22
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(8) Commodity Derivative Instruments and Hedging Activities, Continued
The following table summarizes our derivative contracts, which have been designated as hedges, at June 30, 2005:
Price Floor / | Fair Value | |||||||||||||||||||||||||||||||
Commodity | Volume | Price Ceiling | Term | Index | at June 30, 2005 | |||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Crude oil | 6,000 | Bbls / month | $ | 35.00 | / | $ | 49.75 | Apr’05 — Dec’05 | NYMEX-WTI | $ | 335 | |||||||||||||||||||||
Crude oil | 40,000 | Bbls / month | $ | 40.00 | / | $ | 50.34 | July’05 — June’06 | NYMEX-WTI | 4,629 | ||||||||||||||||||||||
Crude oil | 10,000 | Bbls / month | $ | 45.00 | / | $ | 56.90 | July’05 — June‘06 | NYMEX-WTI | 599 | ||||||||||||||||||||||
Crude oil | 25,000 | Bbls / month | $ | 35.00 | / | $ | 61.80 | July’06 — June‘07 | NYMEX-WTI | 1,681 | ||||||||||||||||||||||
Natural gas | 3,000 | MMBtu / day | $ | 5.00 | / | $ | 7.85 | Apr’05 — Oct‘05 | NYMEX-H HUB | 40 | ||||||||||||||||||||||
Natural gas | 10,000 | MMBtu / day | $ | 5.00 | / | $ | 9.60 | July’05 — June‘06 | NYMEX-H HUB | 995 | ||||||||||||||||||||||
Natural gas | 3,000 | MMBtu / day | $ | 6.00 | / | $ | 9.35 | July’05 — June ‘06 | NYMEX-H HUB | 255 | ||||||||||||||||||||||
Natural gas | 13,000 | MMBtu / day | $ | 5.00 | / | $ | 10.20 | July’06 — June ‘07 | NYMEX-H HUB | 1,466 | ||||||||||||||||||||||
$ | 10,000 | |||||||||||||||||||||||||||||||
The fair value of the Company’s net derivative instruments obligation was a liability of approximately $10.0 million at June 30, 2005 and $23.3 million on September 12, 2005.
The net losses from hedging activities recognized in the Company’s statements of operations were $960,000, $859,000 and $1.9 million for the years ended June 30, 2005, 2004 and 2003, respectively. These losses are recorded as a decrease in revenues. During the year ended June 30, 2005, $330,000 of losses realized from ineffectiveness on hedging activities were reclassified from other comprehensive income into realized loss on derivative instruments in the statement of operations. Based on the estimated fair value of the derivative contracts at June 30, 2005, the Company expects to reclassify net losses of $7.2 million into earnings related to derivative contracts during the next twelve months; however, actual gains and loses recognized may differ materially.
(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 years ended June 30, 2005, 2004 and 2003.
Years Ended June 30, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
(In thousands) | ||||||||||||
CURRENT: | ||||||||||||
U.S. — Federal | $ | — | $ | — | $ | — | ||||||
U.S. — State | — | — | — | |||||||||
Foreign | — | — | — | |||||||||
DEFERRED: | ||||||||||||
U.S. — Federal | (3,027 | ) | — | — | ||||||||
U.S. — State | (298 | ) | — | — | ||||||||
Foreign | — | — | — | |||||||||
$ | (3,325 | ) | $ | — | $ | — | ||||||
Income from continuing operations before taxes consists of the following for the years ended June 30, 2005, 2004 and 2003. | ||||||||||||
Income from continuing operations before taxes | $ | 11,276 | $ | 5,056 | $ | 1,257 | ||||||
F-23
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(9) Income Taxes, Continued
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:
Years Ended June 30, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Federal statutory rate | 35.00 | % | 35.00 | % | 35.00 | % | ||||||
State income taxes, net of federal benefit | 3.44 | % | 3.10 | % | 2.50 | % | ||||||
Investment in DHS | 3.53 | % | 0.25 | % | 0.25 | % | ||||||
Change in valuation allowance | (69.63 | )% | (38.35 | )% | (37.75 | )% | ||||||
Other | (1.83 | )% | — | — | ||||||||
Actual income tax rate | (29.49 | )% | 0.00 | % | 0.00 | % | ||||||
Deferred tax assets (liabilities) are comprised of the following at June 30, 2005 and 2004:
Years Ended June 30, | ||||||||
2005 | 2004 | |||||||
(In thousands) | ||||||||
Current deferred tax assets | ||||||||
Derivative instruments | $ | 2,638 | $ | — | ||||
Allowance for doubtful accounts | 38 | 19 | ||||||
Total current deferred tax assets | 2,676 | 19 | ||||||
Less valuation allowance | — | (19 | ) | |||||
Net current deferred tax asset | $ | 2,676 | $ | — | ||||
Long-term deferred tax assets (liability): | ||||||||
Deferred tax assets: | ||||||||
Net operating loss | $ | 14,544 | $ | 13,278 | ||||
Asset retirement obligation | 1,419 | 1,009 | ||||||
Derivative instruments | 1,211 | — | ||||||
Percentage depletion | 541 | — | ||||||
Drilling equipment | 403 | — | ||||||
Other | 66 | — | ||||||
Total long-term deferred tax assets | 18,184 | 14,287 | ||||||
Valuation allowance | (1,139 | ) | (8,971 | ) | ||||
Net deferred tax asset | 17,045 | 5,316 | ||||||
Deferred tax liabilities: | ||||||||
Oil and gas properties | (11,256 | ) | (5,316 | ) | ||||
Investment in DHS | (399 | ) | — | |||||
Investments — available for sale | (503 | ) | — | |||||
Total long-term deferred tax liabilities | (12,158 | ) | (5,316 | ) | ||||
Net long-term deferred tax asset (liability) | $ | 4,887 | $ | — | ||||
F-24
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(9) Income Taxes, Continued
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future 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 June 30, 2005. The valuation allowance at June 30, 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 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.
The Company’s net operating losses are scheduled to expire as follows (in thousands):
2006 | $ | 318 | ||
2007 | 322 | |||
2008 | 346 | |||
2009 | 1,827 | |||
2010 | 720 | |||
2011 and thereafter | 33,757 | |||
$ | 37,290 | |||
(10) Related Party Transactions
Transactions with Officers
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 us on our 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 during 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 officer earned approximately $100,000, $66,000 and $108,000 for their respective 1% ORRI during fiscal 2005, 2004 and 2003, respectively.
The Company’s officers have employment agreements which, among other things, include termination and change of control clauses.
Accounts Receivable Related Parties
At June 30, 2005, the Company had $32,000 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.
F-25
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(11) Earnings Per Share
The following table sets forth the computation of basic and diluted earnings per share:
Years Ended June 30, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Numerator: | ||||||||||||
Numerator for basic and diluted earnings per share – income available to common stockholders | $ | 15,050 | $ | 5,056 | $ | 1,257 | ||||||
Denominator: | ||||||||||||
Denominator for basic earnings per share-weighted average shares outstanding | 40,327 | 27,041 | 22,865 | |||||||||
Effect of dilutive securities, stock options and warrants | 1,693 | 2,591 | 954 | |||||||||
Denominator for diluted earnings per common share | 42,020 | 29,632 | 23,819 | |||||||||
Basic earnings per common share | $ | .37 | $ | .19 | $ | .05 | ||||||
Diluted earnings per common share | $ | .36 | $ | .17 | $ | .05 | ||||||
(12) Guarantee of 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 June 30, 2005 and 2004, the condensed consolidating statements of operations for the years ended June 30, 2005, 2004 and 2003 and the condensed consolidating statements of cash flows for years ended June 30, 2005, 2004 and 2003 (in thousands).
F-26
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(12) Guarantee of Financial Information, Continued
Condensed Consolidated Balance Sheet
June 30, 2005
June 30, 2005
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Current assets | $ | 23,602 | $ | 2,235 | $ | 1,197 | $ | — | $ | 27,034 | ||||||||||
Property and equipment: | ||||||||||||||||||||
Oil and gas | 455,678 | 6,556 | 5,007 | 467,241 | ||||||||||||||||
Drilling rigs and trucks | — | — | 40,031 | — | 40,031 | |||||||||||||||
Other | 10,347 | — | 65 | — | 10,412 | |||||||||||||||
Total property and equipment | 466,025 | 6,556 | 45,103 | — | 517,684 | |||||||||||||||
Accumulated DD&A | (42,003 | ) | (1,032 | ) | (1,099 | ) | — | (44,134 | ) | |||||||||||
Net property and equipment | 424,022 | 5,524 | 44,004 | — | 473,550 | |||||||||||||||
Investment in subsidiaries | 26,322 | — | — | (26,322 | ) | — | ||||||||||||||
Other long-term assets | 12,359 | — | 40 | — | 12,399 | |||||||||||||||
Total assets | $ | 486,305 | $ | 7,759 | $ | 45,241 | $ | (26,322 | ) | $ | 512,983 | |||||||||
Current liabilities | $ | 42,294 | $ | 215 | $ | 11,641 | $ | — | $ | 54,150 | ||||||||||
Long-term liabilities | ||||||||||||||||||||
Long-term debt | 219,437 | — | 184 | — | 219,621 | |||||||||||||||
Asset retirement obligation | 2,951 | 24 | — | — | 2,975 | |||||||||||||||
Total long-term liabilities | 222,388 | 24 | 184 | — | 222,596 | |||||||||||||||
Minority interest | 14,614 | — | — | — | 14,614 | |||||||||||||||
Shareholders’ equity | 207,009 | 7,520 | 33,416 | (26,322 | ) | 221,623 | ||||||||||||||
Total liabilities and shareholders’ equity | $ | 486,305 | $ | 7,759 | $ | 45,241 | $ | (26,322 | ) | $ | 512,983 | |||||||||
F-27
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(12) Guarantee of Financial Information, Continued
Condensed Consolidated Statement of Operations
Year Ended June 30, 2005
Year Ended June 30, 2005
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Total revenue | $ | 88,254 | $ | 1,657 | $ | 7,319 | $ | (2,523 | ) | $ | 94,707 | |||||||||
Operating expenses: | ||||||||||||||||||||
Lease operating expense | 21,780 | 489 | — | — | 22,269 | |||||||||||||||
Depreciation and depletion | 21,534 | 148 | 1,525 | — | 23,207 | |||||||||||||||
Exploration expense | 6,155 | — | — | — | 6,155 | |||||||||||||||
Drilling and trucking operations | — | — | 6,799 | (2,133 | ) | 4,666 | ||||||||||||||
Dry hole, abandonment and impaired | 2,771 | — | — | — | 2,771 | |||||||||||||||
General and administrative | 15,788 | 9 | 1,133 | — | 16,930 | |||||||||||||||
Total expenses | 68,028 | 646 | 9,457 | (2,133 | ) | 75,998 | ||||||||||||||
Income (loss) from continuing operations | 20,226 | 1,011 | (2,138 | ) | (390 | ) | 18,709 | |||||||||||||
Other income and expenses | (7,462 | ) | 31 | (2 | ) | — | (7,433 | ) | ||||||||||||
Income tax benefit | 3,325 | — | — | — | 3,325 | |||||||||||||||
Discontinued operations | 449 | — | — | — | 449 | |||||||||||||||
Net income (loss) | $ | 16,538 | $ | 1,042 | $ | (2,140 | ) | $ | (390 | ) | $ | 15,050 | ||||||||
Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2005
Year Ended June 30, 2005
Guarantor | Non-Guarantor | |||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
Operating activities | $ | 37,057 | $ | 707 | $ | 7,098 | $ | 44,862 | ||||||||
Investing activities | (158,273 | ) | (551 | ) | (25,058 | ) | (183,882 | ) | ||||||||
Financing activities | 121,262 | — | 17,921 | 139,183 | ||||||||||||
Net increase (decrease) in cash and cash equivalents | 46 | 156 | (39 | ) | 163 | |||||||||||
Cash at beginning of the period | 1,992 | 40 | 46 | 2,078 | ||||||||||||
Cash at the end of the period | $ | 2,038 | $ | 196 | $ | 7 | $ | 2,241 | ||||||||
F-28
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(12) Guarantee of Financial Information, Continued
Condensed Consolidated Balance Sheet
Year Ended June 30, 2004
Year Ended June 30, 2004
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Current assets | $ | 13,781 | $ | 1,115 | $ | 57 | $ | — | $ | 14,953 | ||||||||||
Property and equipment: | ||||||||||||||||||||
Oil and gas | 261,879 | 6,007 | 5,006 | — | 272,892 | |||||||||||||||
Drilling rigs and trucks | — | — | 3,965 | — | 3,965 | |||||||||||||||
Other | 1,136 | — | 11 | — | 1,147 | |||||||||||||||
Total property and equipment | 263,015 | 6,007 | 8,982 | — | 278,004 | |||||||||||||||
Accumulated DD&A | (20,765 | ) | (886 | ) | (14 | ) | — | (21,665 | ) | |||||||||||
Net property and equipment | 242,250 | 5,121 | 8,968 | — | 256,339 | |||||||||||||||
Investment in subsidiaries | 14,724 | — | — | (14,724 | ) | — | ||||||||||||||
Other long-term assets | 1,412 | — | — | — | 1,412 | |||||||||||||||
Total assets | $ | 272,167 | $ | 6,236 | $ | 9,025 | $ | (14,724 | ) | $ | 272,704 | |||||||||
Current liabilities | $ | 14,018 | $ | 36 | $ | 236 | $ | — | $ | 14,290 | ||||||||||
Long-term liabilities | ||||||||||||||||||||
Long-term debt | 69,387 | — | 243 | — | 69,630 | |||||||||||||||
Asset retirement obligation | 2,520 | 22 | — | — | 2,542 | |||||||||||||||
Total long-term liabilities | 71,907 | 22 | 243 | — | 72,172 | |||||||||||||||
Minority interest | 245 | — | — | — | 245 | |||||||||||||||
Shareholders’ equity | 185,997 | 6,178 | 8,546 | (14,724 | ) | 185,997 | ||||||||||||||
Total liabilities and shareholders’ equity | $ | 272,167 | $ | 6,236 | $ | 9,025 | $ | (14,724 | ) | $ | 272,704 | |||||||||
Condensed Consolidated Statement of Operations
Year Ended June 30, 2004
Year Ended June 30, 2004
Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Total revenue | $ | 34,947 | $ | 1,429 | $ | 33 | $ | (33 | ) | $ | 36,376 | |||||||||
Operating expenses: | ||||||||||||||||||||
Lease operating expense | 9,377 | 399 | — | — | 9,776 | |||||||||||||||
Depreciation and depletion | 9,637 | 263 | 14 | — | 9,914 | |||||||||||||||
Exploration expense | 2,405 | — | 1 | — | 2,406 | |||||||||||||||
Drilling and trucking operations | — | — | 265 | (33 | ) | 232 | ||||||||||||||
Dry hole, abandonment and impaired | 2,132 | — | — | — | 2,132 | |||||||||||||||
General and administrative | 7,906 | 19 | 124 | — | 8,049 | |||||||||||||||
Total expenses | 31,457 | 681 | 404 | (33 | ) | 32,509 | ||||||||||||||
Income (loss) from continuing operations | 3,490 | 748 | (371 | ) | — | 3,867 | ||||||||||||||
Other income and expenses | (1,643 | ) | 4 | (1 | ) | 70 | (1,570 | ) | ||||||||||||
Discontinued operations | 2,759 | — | — | — | 2,759 | |||||||||||||||
Net income (loss) | $ | 4,606 | $ | 752 | $ | (372 | ) | $ | 70 | $ | 5,056 | |||||||||
F-29
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(12) Guarantee of Financial Information, Continued
Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2004
Year Ended June 30, 2004
Guarantor | Non-Guarantor | |||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
Operating activities | $ | 9,263 | $ | 518 | $ | (158 | ) | $ | 9,623 | |||||||
Investing activities | (144,232 | ) | (370 | ) | (3,836 | ) | (148,438 | ) | ||||||||
Financing activities | 134,795 | (218 | ) | 4,045 | 138,622 | |||||||||||
Net increase (decrease) in cash and cash equivalents | (174 | ) | (70 | ) | 51 | (193 | ) | |||||||||
Cash at beginning of the period | 2,160 | 110 | 1 | 2,271 | ||||||||||||
Cash at the end of the period | $ | 1,986 | $ | 40 | $ | 52 | $ | 2,078 | ||||||||
Condensed Consolidated Statement of Operations
Year Ended June 30, 2003
Year Ended June 30, 2003
Guarantor | Non-Guarantor | |||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
Total revenue | $ | 19,119 | $ | 1,599 | $ | — | $ | 20,718 | ||||||||
Operating expenses: | ||||||||||||||||
Lease operating expense | 7,957 | 453 | — | 8,410 | ||||||||||||
Depreciation and depletion | 4,475 | 524 | 4,999 | |||||||||||||
Exploration expense | 140 | — | — | 140 | ||||||||||||
Drilling and trucking operations | — | — | — | — | ||||||||||||
Dry hole, abandonment and impaired | 530 | 7 | — | 537 | ||||||||||||
General and administrative | 4,987 | 21 | 129 | 5,137 | ||||||||||||
Total expenses | 18,089 | 1,005 | 129 | 19,223 | ||||||||||||
Income (loss) from continuing operations | 1,030 | 594 | (129 | ) | 1,495 | |||||||||||
Other income and expenses | (1,770 | ) | 14 | — | (1,756 | ) | ||||||||||
Discontinued operations | 1,322 | 196 | — | 1,518 | ||||||||||||
Net income (loss) | $ | 582 | $ | 804 | $ | (129 | ) | $ | 1,257 | |||||||
F-30
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(12) Guarantee of Financial Information, Continued
Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2003
Year Ended June 30, 2003
Guarantor | Non-Guarantor | |||||||||||||||
Issuer | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
Operating activities | $ | 7,042 | $ | 1,083 | $ | (126 | ) | $ | 7,999 | |||||||
Investing activities | (14,837 | ) | 82 | 107 | (14,648 | ) | ||||||||||
Financing activities | 8,992 | (1,101 | ) | 5 | 7,896 | |||||||||||
Net increase (decrease) in cash and cash equivalents | 1,197 | 64 | (14 | ) | 1,247 | |||||||||||
Cash at beginning of the period | 978 | 46 | — | 1,024 | ||||||||||||
Cash at the end of the period | $ | 2,175 | $ | 110 | $ | (14 | ) | $ | 2,271 | |||||||
(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 years ended June 30, 2005, 2004 and 2003 was approximately $491,000, $311,000 and $210,000, respectively. The following table summarizes the future minimum payments under all non-cancelable operating lease obligations:
(In thousands) | ||||
2006 | $ | 1,998 | ||
2007 | 818 | |||
2008 | 825 | |||
2009 | 777 | |||
2010 | 765 | |||
2011 and thereafter | 3,564 | |||
$ | 8,747 | |||
The Company has entered into agreements with three 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.
F-31
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(14) Selected Quarterly Financial Data (Unaudited)
Fiscal 2005 | 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | ||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Total revenue | $ | 19,338 | $ | 20,529 | $ | 26,566 | $ | 28,274 | ||||||||
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect | 3,215 | 4,809 | 4,940 | (1,688 | ) | |||||||||||
Net income | 3,944 | 4,809 | 4,940 | 1,357 | ||||||||||||
Net income per common share: (1) | ||||||||||||||||
Basic | $ | .10 | $ | .12 | $ | .12 | $ | .04 | ||||||||
Diluted | $ | .09 | $ | .11 | $ | .12 | $ | .04 |
Fiscal 2004 | 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | ||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Total revenue | $ | 6,755 | $ | 7,646 | $ | 10,308 | $ | 11,658 | ||||||||
Income from continuing operations before income taxes, discontinued operations and cumulative effect | 1,045 | 425 | 374 | 453 | ||||||||||||
Net income | 1,364 | 652 | 2,454 | 586 | ||||||||||||
Net income per common share: (1) | ||||||||||||||||
Basic | $ | .06 | $ | .03 | $ | .09 | $ | .02 | ||||||||
Diluted | $ | .05 | $ | .03 | $ | .08 | $ | .02 |
(1) | The sum of individual quarterly net income per share may not agree with year-to-date net income per share as each period’s computation is based on the weighted average number of common shares outstanding during the period. |
F-32
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(15) Disclosures About Capitalized Costs, Cost Incurred and Major Customers
Capitalized costs related to oil and gas activities are as follows:
Years Ended June 30, | ||||||||
2005 | 2004 | |||||||
(In thousands) | ||||||||
Unproved offshore California properties | $ | 10,925 | $ | 10,844 | ||||
Unproved onshore domestic properties | 91,010 | 38,903 | ||||||
Proved offshore California properties | 12,207 | 9,103 | ||||||
Proved onshore domestic properties | 353,099 | 214,042 | ||||||
467,241 | 272,892 | |||||||
Accumulated depreciation and depletion | (43,034 | ) | (21,317 | ) | ||||
$ | 424,207 | $ | 251,575 | |||||
Costs incurred(1) in oil and gas activities are as follows:
Years Ended June 30, | ||||||||||||||||||||||||
2005 | 2004 | 2003 | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||||||||
Unproved property acquisition costs | $ | 25,383 | $ | 81 | $ | 37,223 | $ | 680 | $ | 694 | $ | 442 | ||||||||||||
Proved property acquisition costs | 81,190 | — | 128,587 | — | 10,784 | — | ||||||||||||||||||
Developed cost incurred on undeveloped reserves | 72,413 | 3,104 | 3,789 | 1,070 | 815 | 986 | ||||||||||||||||||
Development costs – other | 34,369 | — | 20,986 | — | 4,335 | — | ||||||||||||||||||
Exploration costs | 6,155 | — | 2,406 | — | 140 | — | ||||||||||||||||||
$ | 219,510 | $ | 3,185 | $ | 192,991 | $ | 1,750 | $ | 16,768 | $ | 1,428 | |||||||||||||
(1) | Included in costs incurred are asset retirement obligation costs incurred for all periods presented. |
F-33
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(15) 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:
Years Ended June 30, | ||||||||||||||||||||||||
2005 | 2004 | 2003 | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||||||||
Revenue | ||||||||||||||||||||||||
Oil and gas revenues | $ | 85,680 | $ | 5,191 | $ | 33,251 | $ | 3,975 | $ | 17,987 | $ | 4,589 | ||||||||||||
Expenses: | ||||||||||||||||||||||||
Production costs | 18,344 | 3,925 | 6,510 | 3,257 | 5,140 | 3,270 | ||||||||||||||||||
Depletion | 20,171 | 720 | 8,978 | 705 | 3,860 | 1,075 | ||||||||||||||||||
Exploration | 6,155 | — | 2,406 | — | 140 | — | ||||||||||||||||||
Abandonment and impaired Properties | — | — | — | — | — | — | ||||||||||||||||||
Dry hole costs | 2,771 | — | 2,132 | — | 537 | — | ||||||||||||||||||
Results of operations of oil and gas producing activities | $ | 38,239 | $ | 546 | $ | 13,225 | $ | 13 | $ | 8,310 | $ | 244 | ||||||||||||
Income (loss) from operations of properties sold, net | 449 | — | 872 | — | 1,241 | — | ||||||||||||||||||
Gain (loss) on sale of properties | — | — | 1,887 | — | 277 | — | ||||||||||||||||||
Cumulative effect on change in accounting principle | — | — | — | — | (20) | — | ||||||||||||||||||
Results of discontinued operations of oil and gas producing activities | $ | 449 | $ | — | $ | 2,759 | $ | — | $ | 1,498 | $ | — | ||||||||||||
Statement of Financial Accounting Standards 131 “Disclosures about segments of an enterprise and Related Information” (SFAS 131) establishes standards for reporting information about operating segments in annual and interim financial statements. SFAS 131 also establishes standards for related disclosures about products and services, geographic areas and major customers. The Company’s business segment includes its onshore and offshore properties described above and its drilling and trucking companies. The drilling and trucking companies had minimal activity. As such, segment information relating to the drilling and trucking companies has not been presented.
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 years ended June 30, 2005, 2004 and 2003 were:
2005 | 2004 | 2003 | ||||||||||
Customer A | 10 | % | 17 | % | — | % | ||||||
Customer B | 7 | % | 17 | % | 13 | % | ||||||
Customer C | 6 | % | 10 | % | 18 | % | ||||||
Customer D | 3 | % | 14 | % | 17 | % |
F-34
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(16) Information Regarding Proved Oil and Gas Reserves (Unaudited)
Proved Oil and Gas Reserves.Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. For the purposes of this disclosure, the Company has included reserves it is committed to and anticipates drilling.
(i) Reservoirs are considered proved if economic producability is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves;” (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other un-drilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
F-35
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(16) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
Estimates of our oil and natural gas reserves and present values for our fiscal years ended 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.
A summary of changes in estimated quantities of proved reserves for the years ended June 30, 2005, 2004 and 2003 is as follows:
Onshore | Offshore | |||||||||||
GAS | OIL | OIL | ||||||||||
(MMcf) | (MBbl) | (MBbl) | ||||||||||
(In thousands) | ||||||||||||
Balance at June 30, 2002 | 43,953 | 3,919 | 902 | |||||||||
Revisions of quantity estimate | 13,719 | (927 | ) | 244 | ||||||||
Extensions and discoveries | 687 | — | 1,132 | |||||||||
Purchase of properties | 236 | 1,024 | — | |||||||||
Sale of properties | (457 | ) | (66 | ) | — | |||||||
Production | (2,938 | ) | (252 | ) | (227 | ) | ||||||
Balance at June 30, 2003 | 55,200 | 3,698 | 2,051 | |||||||||
Revisions of quantity estimate | (3,136 | ) | 469 | (44 | ) | |||||||
Extensions and discoveries | 6,560 | 69 | — | |||||||||
Purchase of properties | 39,782 | 8,306 | — | |||||||||
Sale of properties | (6,817 | ) | (596 | ) | — | |||||||
Production | (3,110 | ) | (568 | ) | (180 | ) | ||||||
Balance at June 30, 2004 | 88,479 | 11,378 | 1,827 | |||||||||
Revisions of quantity estimate | (3,850 | ) | (512 | ) | (173 | ) | ||||||
Extensions and discoveries | 39,459 | 1,162 | — | |||||||||
Purchase of properties | 32,282 | 1,397 | — | |||||||||
Sale of properties | (7,654 | ) | (153 | ) | — | |||||||
Production | (7,675 | ) | (899 | ) | (156 | ) | ||||||
Balance at June 30, 2005 | 141,041 | 12,373 | 1,493 | |||||||||
Proved developed reserves: | ||||||||||||
June 30, 2002 | 25,100 | 1,651 | 849 | |||||||||
June 30, 2003 | 28,611 | 2,608 | 919 | |||||||||
June 30, 2004 | 55,786 | 6,240 | 695 | |||||||||
June 30, 2005 | 70,568 | 6,947 | 585 |
F-36
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(16) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
Future net cash flows presented below are computed using year end prices and costs and are net of all overriding royalty revenue interests.
Future corporate overhead expenses and interest expense have not been included.
Onshore | Offshore | Combined | ||||||||||
(In thousands) | ||||||||||||
June 30, 2005 | ||||||||||||
Future net cash flows | $ | 1,724,986 | $ | 64,516 | $ | 1,789,502 | ||||||
Future costs: | ||||||||||||
Production | 366,453 | 19,286 | 385,739 | |||||||||
Development and abandonment | 183,416 | 8,934 | 192,350 | |||||||||
Income taxes | 294,754 | — | 294,754 | |||||||||
Future net cash flows | 880,363 | 36,296 | 916,659 | |||||||||
10% discount factor | (387,874 | ) | (11,415 | ) | (399,289 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 492,489 | $ | 24,881 | $ | 517,370 | ||||||
Standardized measure of discounted future net cash flows before tax | $ | 658,848 | $ | 24,881 | $ | 683,729 | ||||||
Estimated future development cost anticipated for fiscal 2006 and 2007 on existing properties | $ | 152,652 | $ | 6,004 | $ | 158,656 | ||||||
June 30, 2004 | ||||||||||||
Future net cash flows | $ | 953,532 | $ | 51,625 | $ | 1,005,157 | ||||||
Future costs: | ||||||||||||
Production | 225,046 | 23,558 | 248,604 | |||||||||
Development and abandonment | 55,845 | 11,054 | 66,899 | |||||||||
Income taxes | 165,492 | — | 165,492 | |||||||||
Future net cash flows | 507,149 | 17,013 | 524,162 | |||||||||
10% discount factor | 230,540 | 5,585 | 236,125 | |||||||||
Standardized measure of discounted future net cash flows | $ | 276,609 | $ | 11,428 | $ | 288,037 | ||||||
Standardized measure of discounted future net cash flows before tax | $ | 367,679 | $ | 11,428 | $ | 379,107 | ||||||
June 30, 2003 | ||||||||||||
Future cash flows | $ | 377,458 | $ | 46,898 | $ | 424,356 | ||||||
Future costs: | ||||||||||||
Production | 99,243 | 24,787 | 124,030 | |||||||||
Development and abandonment | 20,104 | 13,137 | 33,241 | |||||||||
Income taxes | 62,390 | — | 62,390 | |||||||||
Future net cash flows | 195,721 | 8,974 | 204,695 | |||||||||
10% discount factor | 93,734 | 3,750 | 97,484 | |||||||||
Standardized measure of discounted future net cash flows | $ | 101,987 | $ | 5,224 | $ | 107,211 | ||||||
Standardized measure of discounted future net cash flows before tax | $ | 134,667 | $ | 5,224 | $ | 139,891 | ||||||
F-37
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
(16) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
The principal sources of changes in the standardized measure of discounted net cash flows during the years ended June 30, 2005, 2004 and 2003 are as follows:
2005 | 2004 | 2003 | ||||||||||
(In thousands) | ||||||||||||
Beginning of the year | $ | 288,037 | $ | 107,211 | $ | 62,384 | ||||||
Sales of oil and gas production during the period, net of production costs | (68,602 | ) | (27,459 | ) | (16,082 | ) | ||||||
Purchase of reserves in place | 201,693 | 248,478 | 14,335 | |||||||||
Net change in prices and production costs | 90,938 | 26,088 | 37,957 | |||||||||
Changes in estimated future development costs | 19,345 | 8,592 | (8,251 | ) | ||||||||
Extensions, discoveries and improved recovery | 93,624 | 11,599 | 3,032 | |||||||||
Revisions of previous quantity estimates, estimated timing of development and other | (91,002 | ) | (25,807 | ) | 25,675 | |||||||
Previously estimated development and abandonment costs incurred during the period | 72,413 | 4,859 | 1,801 | |||||||||
Sales of reserves in place | (42,508 | ) | (17,934 | ) | (1,122 | ) | ||||||
Change in future income tax | (75,371 | ) | (58,311 | ) | (18,756 | ) | ||||||
Accretion of discount | 28,803 | 10,721 | 6,238 | |||||||||
End of year | $ | 517,370 | $ | 288,037 | $ | 107,211 | ||||||
(17) Subsequent Events
On September 9, 2005, the Company completed the sale of its interest in the Deerlick Field located in Tuscaloosa, Alabama, for cash consideration of $30.0 million and an effective date of July 1, 2005. The Company expects to record a tax deferred gain on the sale of oil and gas properties of approximately $18.0 million. Revenues from these oil and gas properties were approximately $4.9 million, $3.3 million and $3.0 million for the years ended June 30, 2005, 2004 and 2003, respectively.
On September 7, 2005 the Company entered into an agreement to purchase an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington, and to purchase an interest in undeveloped acreage in the Piceance Basin in Colorado from Savant Resources, LLC (“Savant”) for an aggregate purchase price of $85 million, on or before September 30, 2005. 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 consolidates the Company’s current leasehold position, whereby subsequent to the acquisition Delta will own a 100% working interest in approximately 310,000 net acres. This acquisition also includes a small portion of acreage that is subject to an agreement with EnCana Oil & Gas (USA) Inc., whereby the Company will have the right to convert an overriding royalty interest to a working interest at project payout. In the Piceance Basin, the Company is acquiring Savant’s interest in an entity that owns a 25% interest in approximately 6,314 gross acres that is currently being developed.
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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.
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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.
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SIGNATURES
Pursuant to the requirements of the 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 12th day of September, 2005.
DELTA PETROLEUM CORPORATION | ||||||
By: | /s/ Roger A. Parker | |||||
Roger A. Parker, Chairman, President and | ||||||
Chief Executive Officer | ||||||
By: | /s/ Kevin K. Nanke | |||||
Kevin K. Nanke, Treasurer and | ||||||
Chief Financial Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this Form 10-K has been signed below by the following persons on our behalf and in the capacities and on the dates indicated.
Signature and Title | Date | |||||
/s/ Roger A. Parker | September 12, 2005 | |||||
Roger A. Parker, Director | ||||||
/s/ Kevin R. Collins | September 12, 2005 | |||||
Kevin R. Collins, Director | ||||||
/s/ Jerrie F. Eckelberger | September 12, 2005 | |||||
Jerrie F. Eckelberger, Director | ||||||
/s/ Aleron H. Larson, Jr. | September 12, 2005 | |||||
Aleron H. Larson, Jr., Director | ||||||
/s/ Russell L. Lewis | September 12, 2005 | |||||
Russell S. Lewis, Director | ||||||
/s/ Jordan R. Smith | September 12, 2005 | |||||
Jordan R. Smith, Director | ||||||
/s/ Neal A. Stanley | September 12, 2005 | |||||
Neal A. Stanley, Director | ||||||
/s/ James B. Wallace | September 12, 2005 | |||||
James B. Wallace, Director | ||||||
/s/ James P. Van Blarcom | September 12, 2005 | |||||
James P. Van Blarcom, Director |
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INDEX TO EXHIBITS
2. | Plans of Acquisition, Reorganization, Arrangement, Liquidation, or Succession. Not applicable. | |
3. | Articles of Incorporation and By-laws. | |
3.1 | Articles of Incorporation and Articles of Amendment to Articles of Incorporation. Incorporated by reference from Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended June 30, 2004. | |
3.2 | By-laws. Incorporated by reference from Exhibit 3.3 to the Company’s Form 10 Registration Statement under the Securities Exchange Act of 1934, filed September 9, 1987. | |
4. | Instruments Defining the Rights of Security Holders. | |
4.1 | Purchase Agreement dated March 9, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.1 to the Company’s Form 8-K dated March 15, 2005. | |
4.2 | Registration Rights Agreement dated March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.2 to the Company’s Form 8-K dated March 15, 2005. | |
4.3 | Indenture dated as of March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and US Bank National Association, as Trustee. Incorporated by reference from Exhibit 4.3 to the Company’s Form 8-K dated March 15, 2005. | |
4.4 | Form of 7% Series A Senior Notes due 2015 with attached notation of Guarantees. Incorporated by reference from Exhibit 4.4 to the Company’s Form 8-K dated March 15, 2005. | |
9. | Voting Trust Agreement. Not applicable. | |
10. | Material Contracts. | |
10.1 | Burdette A. Ogle “Assignment, Conveyance and Bill of Sale of Federal Oil and Gas Leases Reserving a Production Payment,” “Lease Interests Purchase Option Agreement” and “Purchase and Sale Agreement.” Incorporated by reference from Exhibit 28.1 to the Company’s Form 8-K dated January 3, 1995. | |
10.2 | Delta Petroleum Corporation 1993 Incentive Plan, as amended. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1996. * | |
10.3 | Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement dated June 1, 1999. * | |
10.4 | Agreement between Burdette A. Ogle and Delta Petroleum Corporation effective December 17, 1998. Incorporated by reference from Exhibit 99.2 to the Company’s Form 10-QSB for the quarterly period ended December 31, 1998. | |
10.5 | Agreement between Whiting Petroleum Corporation and Delta Petroleum Corporation (including amendment) dated June 8, 1999. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated June 9, 1999. | |
10.6 | Purchase and Sale Agreement dated October 13, 1999 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1999. |
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10.7 | Agreement between Delta Petroleum Corporation, Roger A. Parker and Aleron H. Larson, Jr. dated November 1, 1999. Incorporated by reference from Exhibit 99.3 to the Company’s Form 8-K dated November 1, 1999.* | |
10.8 | Conveyance and Assignment from Whiting Petroleum Corporation dated December 1, 1999. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated December 1, 1999. | |
10.9 | Agreement dated December 30, 1999 between Burdette A. Ogle and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.4 to the Company’s Form 8-K dated January 4, 2000. | |
10.10 | Purchase and Sale Agreement dated June 1, 2000 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated July 10, 2000. | |
10.11 | Delta Petroleum Corporation 2001 Incentive Plan. Incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement dated July 26, 2001 for fiscal year 2000 ended June 30, 2000.* | |
10.12 | Employment Agreements with Aleron H. Larson, Jr., Roger A. Parker and Kevin K. Nanke, from Exhibit 10.4 a, b, and c to the Company’s Form 8-K dated October 25, 2001. * | |
10.13 | Delta Petroleum Corporation 2002 Incentive Plan incorporated by reference from Exhibit A to the Company’s definitive proxy statement filed May 1, 2002. * | |
10.14 | Agreement between Delta Petroleum Corporation and Amber Resources Company dated July 1, 2001, incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated October 25, 2001. | |
10.15 | Letter agreement dated December 3, 2001 between Delta Petroleum Corporation and Ogle Properties LLC, incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K dated October 25, 2001. | |
10.16 | Purchase and Sale Agreement between Castle Energy Company and Delta Petroleum Corporation dated December 31, 2001 incorporated by reference from Exhibit 2.1 to the Company’s Form 8-K dated January 15, 2002. | |
10.17 | Purchase and Sale Agreement between Delta Petroleum Corporation and Tipperary Oil & Gas Corporation dated May 8, 2002 incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated April 30, 2002. | |
10.18 | Credit Agreement dated May 31, 2002 by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated May 24, 2002. | |
10.19 | First Amendment to Credit Agreement dated June 20, 2003 by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated June 20, 2003. | |
10.20 | Agreement with Arguello, Inc. Incorporated by reference from Exhibit 10.22 to the Company’s Form 10-K for the fiscal year ended June 30, 2003. | |
10.21 | Purchase and Sale Agreement dated as of June 5, 2003 between JAED Production Company, Inc. and Delta Petroleum Corporation. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 20, 2003. |
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10.22 | Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated September 19, 2003. | |
10.23 | First Amendment to Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated September 19, 2003. | |
10.24 | Amended and Restated Credit Agreement dated December 30, 2003, by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.1 to the Company’s Form 10-Q dated December 31, 2003. | |
10.25 | Second Amendment to Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K dated April 23, 2004. | |
10.26 | Purchase and Sale Agreement dated June 10, 2004 with various sellers related to Alpine Resources, Inc. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 29, 2004. | |
10.27 | Second Amendment of Amended and Restated Credit Agreement dated June 29, 2004 with Bank of Oklahoma, N.A., US Bank National Association and Hibernia National Bank. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated June 29, 2004. | |
10.28 | Amendment No. 1 to Purchase and Sale Agreement dated July 7, 2004 with Edward Mike Davis and entities controlled by him. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated June 29, 2004. | |
10.29 | Third Amendment to Credit Agreement between Delta Petroleum Corporation and the banks named therein, dated June 30, 2005. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 29, 2005. | |
10.30 | Delta Petroleum Corporation 2005 New-Hire Equity Incentive Plan. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 17, 2005.* | |
10.31 | Amendment No. 1 to Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated June 17, 2005.* | |
10.32 | Employment Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated May 5, 2005.* | |
10.33 | Employment Agreement with Kevin K. Nanke dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.34 | Employment Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.35 | Change in Control Executive Severance Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.36 | Change in Control Executive Severance Agreement with Kevin K. Nanke dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.37 | Change in Control Executive Severance Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.* | |
10.38 | Asset Purchase Agreement dated December 15th, 2004, with Manti Resources, Inc., a Texas corporation, Manti Operating Company, a Texas corporation, Manti Caballos Creek, LTD., a Texas |
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limited partnership, Manti Opossum Hollow, LTD., a Texas limited partnership, J&P Oil and Gas, Inc., a Texas corporation, Lara Energy, Inc., a Texas corporation, and SofRoc Fuel Co., a Texas corporation. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated January 21, 2005. | ||
10.39 | First Amendment to Credit Agreement dated as of January 21, 2005 with JP Morgan Chase Bank, N.A., U.S. Bank N.A., Bank of Oklahoma and Hibernia Bank. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated January 21, 2005. | |
10.40 | Credit Agreement dated November 5, 2004, by and among Delta Petroleum Corporation, Bank One, NA, Bank of Oklahoma, N.A., and U.S. Bank National Association. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated November 5, 2004. | |
10.41 | Fourth Amendment to Purchase and Sale Agreement with Edward Mike Davis, et al. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated November 4, 2004. | |
11. | Statement Regarding Computation of Per Share Earnings. Not applicable. | |
12. | Statement Regarding Computation of Ratios. Not applicable. | |
13. | Code of Ethics. The Company’s Code of Business Conduct and Ethics is posted on the Company’s website at www.deltapetro.com. | |
16. | Letter re: change in certifying accountant. Not applicable. | |
18. | Letter re: change in accounting principles. Not applicable. | |
21. | Subsidiaries of the Registrant. Filed herewith electronically. | |
22. | Published report regarding matters submitted to vote of security holders. Not applicable. | |
23. | Consents of experts and counsel. | |
23.1 | Consent of KPMG LLP. Filed herewith electronically. | |
23.2 | Consent of Ralph E. Davis Associates, Inc. Filed herewith electronically. | |
23.3 | Consent of Mannon Associates. Filed herewith electronically. | |
24. | Power of attorney. Not applicable. | |
31. | Rule 13a-14(a)/ 15d-14(a) Certifications. | |
31.1 | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically. | |
31.2 | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically. | |
32. | Section 1350 Certifications. | |
32.1 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically. | |
32.2 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically. |
* | Management contracts and compensatory plans. |