UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For
| x | ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
for the fiscal year ended June 30, 2002.
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For2004
| ¨ | TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934 |
for the transition period from.
Commission File No. 0-16203
DELTA PETROLEUM CORPORATION
(Exact
(Exact name of registrant as specified in its charter)
Colorado 84-1060803
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
475 17th Street, Suite 1400
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
Registrant's
| Colorado | 84-1060803 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
475 17th Street, Suite 1400 Denver, Colorado | 80202 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (303) 293-9133
Securities registered under Section 12(b) of the Exchange Act: None
Securities registered under to Section 12(g) of the Exchange Act:
Common Stock, $.01 par value
Check whether issuer (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. xYes [ X ]¨ No [ ]
Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of registrant'sregistrant’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. [X]
¨
Indicate by a check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act) ¨ Yes No x
The aggregate market value as of September 18, 20027, 2004 of voting stock held by non-affiliates of the registrant was $45,562,000.
approximately $407,611,000.
As of September 18, 2002, 22,659,00010, 2004, 39,314,949 shares of registrant'sregistrant’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'sCompany’s Definitive Proxy Statement for the Company's 2002Company’s 2004 Annual Meeting of Shareholders.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. DESCRIPTION OF BUSINESS ....................................
ITEM 2. DESCRIPTION OF PROPERTY ....................................
ITEM 3. LEGAL PROCEEDINGS ..........................................
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ........
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS ...........................
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ...
ITEM 6. SELECTED FINANCIAL DATA ....................................
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION ..
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..
ITEM 8. FINANCIAL STATEMENTS .......................................
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE .....................
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT ..........
ITEM 11. EXECUTIVE COMPENSATION .....................................
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT .............................................
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS .............
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS AND REPORTS ON FORM 8-K .....
| PAGE | ||
| PART I | ||
| 4 | ||
| 21 | ||
| 27 | ||
| 27 | ||
| 28 | ||
| PART II | ||
| 31 | ||
| 32 | ||
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 32 | |
| 42 | ||
| 43 | ||
| 43 | ||
| 43 | ||
| PART III | ||
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT | ||
EXECUTIVE COMPENSATION | ||
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT | ||
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS | ||
PRINCIPAL ACCOUNTING FEES AND SERVICES | ||
| PART IV | ||
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K | 46 | |
The terms "Delta," "Company," "we," "our,"“Delta,” “Company,” “we,” “our,” and "us"“us” refer to Delta Petroleum Corporation and its subsidiaries unless the context suggests otherwise.
1
CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS
GENERAL.
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"“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, and (4) capital spending.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"“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-
lookingforward-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-
lookingforward-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.
-
DESCRIPTION OF BUSINESS
(a) Business Development.
General
Delta Petroleum Corporation ("(“Delta," "we," "us"” “we” or “us”) is a Colorado corporation organized on December 21, 1984. We maintain our principal executive offices at Suite 1400, 475 Seventeenth Street, Suite 1400, Denver, Colorado 80202, and our telephone number is (303) 293-9133. Our common stock is listed on NASDAQ under the symbol DPTR.
We are primarily engaged in the acquisition, exploration, development and production of oil and gas properties. AsDuring fiscal 2004, we acquired a 50% interest in both a drilling and a trucking company, however these entities had limited activity. Our primary oil and gas areas of operations include the (1) Gulf Coast Region—South Texas and all Louisiana Basins, (2) Rocky Mountain Region - Denver Julesburg, Wind River, Williston and Piceance Basins, and (3) Offshore California near Santa Barbara.
The following table presents information regarding our primary oil and gas areas of operations as of June 30, 2002,2004:
Areas of Operations | Proved Reserves (Bcfe) (1) | % Natural | % Proved Developed | 2004 Production (MMcfe/d) (2) | ||||||
Gulf Coast Region | 93.6 | 46.8 | % | 33.9 | % | 5.6 | ||||
Rocky Mountain Region | 12.2 | 64.0 | % | 57.9 | % | 4.5 | ||||
Offshore California | 11.0 | — | % | 62.0 | % | 3.0 | ||||
Other | 50.9 | 71.8 | % | 63.0 | % | 6.7 | ||||
Total | 167.7 | 52.5 | % | 46.32 | % | 19.8 | ||||
| (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 fiscal 2005, we had varying
interestshave established an exploration and development capital budget of approximately $80 million.
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 approximately 466 gross (215 net) productive wells located in
fifteen (15) statesthe regular course of our business. We have no material patents, licenses, franchises or concessions that we consider significant to our oil and offshore California. Thesegas operations. The nature of our business is such that it is not seasonal, we do not include varying
small interestsengage in approximately 700 gross (4.6 net) wells locatedany 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.
The following acquisitions have provided a significant portion of our growth:
On June 29, 2004, we acquired substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc. (“Alpine”) for a total purchase price of $120.6 million, net of $1.9 million downward purchase price adjustment. Alpine was a privately held exploration and production company, active primarily in Southeast Texas which are owned byand Louisiana.
Subsequent to year-end on August 19, 2004, we completed the sale of our subsidiary Piper Petroleum Company. We also
had interests in five federal unitsfields in Louisiana and one lease offshore California near
Santa Barbara along with a financial interestSouth Texas previously acquired in a nearby producing offshore
federal unit (see Item 2 "Description of Property").the Alpine Acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $19.3 million. We operated
approximately 270 ofpaid $8.8 million toward our credit facility relating to the wells and the remaining wells were operated by
independent operators. We believe allsale of these wells are operated under
contracts that are standardproperties. No gain or loss was recorded on this transaction.
On September 19, 2003, we completed an acquisition of certain producing and drilling prospects in Colorado (the “South Tongue Prospect”) and Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, “Davis”). On the industry. At June 30, 2002,date of acquisition, we estimated
onshore proved reserves to be approximately 3,919,000 Bbls4.7 Bcfe and we also acquired 100,000 acres of prospect leases in the South Tongue Prospect in Washington County, Colorado and 20,000 acres of prospect leases in Wyoming for total consideration of $13.1 million net of normal closing adjustments. Subsequent to September 19, 2003, we increased our South Tongue acreage position to approximately 260,000 acres.
On April 22, 2004, we amended our agreement with Davis to, among other things, add certain oil and 43.95
Bcfgas leases located in Colorado known as the “North Tongue Prospect,” decrease the amount of gas,Davis’ reversionary working interest after payout in the properties acquired under the initial agreement from 50% to 42.5%, change the definition of which approximately 1,651,000 Bblspayout, change certain drilling obligations and modify our obligation to issue additional shares of stock to Davis upon the designation of Bonus Prospects. The initial consideration required to be paid to Davis upon execution of the Amended Agreement was 1,525,000 shares of our common stock, valued at $17.3 million. The entire amount was allocated to unproved undeveloped properties.
On June 20, 2003, we acquired producing oil and 25.1 Bcfgas interests and related undeveloped acreage in Kansas from JAED Production Company (“JAED”). On the date of gas
were proved developed reserves. At June 30, 2002,acquisition, we estimated offshore proved reserves to be approximately 902,000 Bbls9.9 Bcfe for total consideration of oil,$8.7 million net of which
approximately 849,000 Bbls were proved developed reserves. (See "Description
of Property, Item 2 herein.)
We have an 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 22,618,000 shares were issued and
outstanding as of June 30, 2002. We have outstanding warrants and options to
non-employees to purchase 1,854,000 shares of common stock at prices ranging
from $2.50 per share to $6.00 per share at September 10, 2002. Additionally,
as of June 30, 2002 we had outstanding options which were granted to our
officers, employees and directors under our incentive plans, to purchase up to
3,503,487 shares of common stock at prices ranging from $0.05 to $9.75 per
share at June 30, 2002.
At June 30, 2002, 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) whose activities include oil and gas exploration,
development, and production operations. Until July 1, 2001, Amber owned
interests in a portion of our producing oil and gas properties in Oklahoma.
At June 30, 2002, Amber still owned a portion of the interest referenced above
in our non-producing oil and gas properties offshore California near Santa
Barbara. The Company and Amber entered into an agreement effective October 1,
1998 which provides, in part, for the sharing of the management between the
two companies and allocation of expenses related thereto.
4
On May 31, 2002, Deltawe acquired all of the domestic oil and gas properties of Castle Energy Corporation ("Castle"Exploration Company (“Castle”). The properties acquired from Castle consistconsisted of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. Delta issued
9,566,000 sharesOn the date of Common Stockacquisition, we estimated proved reserves to Castle as part of the purchase price.
Although all of these shares have been registered for sale, none has yet been
sold. Delta is entitled to repurchase up to 3,188,667 of its shares from
Castle for $4.50 per share for a period of one year after closing. Delta's
agreement with Castle was effective as of October 1, 2001 and the net
operating revenues from the properties between the effective date and the May
31, 2002 closing date were recorded as an adjustment to the purchase price.
Also on May 31, 2002 Delta obtained a new $20 million credit
facility with the Bank of Oklahoma and Local Oklahoma Bank, partbe approximately 62 Bcfe, of which 32 Bcfe was usedconsidered to pay the remainder of the Castle purchase price. Approximately $19
million of the credit facility was utilized to close the Castle transaction
and to pay off our existing loan with US Bank. Ourbe proved developed producing reserves for total debt now approximates
$25 million. A substantial portion of oil and gas properties is pledged as
collateral for our new loan and the terms of the Credit Agreement limit our
flexibility to engage in many types of business activities without obtaining
the consent of our lenders in advance. As a part of the acquisition, upon
closing, Delta granted an option to acquire a 4% working interest in the
properties acquired for a cost of $878,000 to BWAB Limited Liability Company
("BWAB"), a less than 10% shareholder of Delta. The difference between the
$878,000 paid by BWAB which is less than fair value, and 4% of the cost of the
Castle properties was treated as an additional acquisition cost by Delta for
its consultation and assistance related to the transaction.
On March 1, 2002 we completed the sale of 21 producing wells and
acreage located primarily in the Eland and Stadium fields of Stark County,
North Dakota, to Sovereign Holdings, LLC, a privately-held Colorado limited
liability company, for cash consideration of $2,750,000 pursuant to a purchase
and sale agreement dated February 1, 2002 and effective January 1, 2002. As a
result$40.8 million net of the sale, we recorded a loss on sale of oil and gas properties of
$1,000. These properties accounted for approximately 9.45% of our total
assets as of June 30, 2001 and also accounted for approximately 22.6% of our
total revenues and approximately 11.9% of our total operating expenses during
our past fiscal year. Approximately $1,300,000 of the proceeds from the sale
were used to pay existing debt. On May 24, 2002 we completed the sale of our
undivided interests$5.8 million in an Authority to Prospect (ATP) covering lands in
Queensland, Australia, to Tipperary Corporation, in exchange for Tipperary's
producing properties in the West Buna Field (Hardin and Jasper counties,
Texas),$700,000 in cash, and 250,000 unregistered shares of Tipperary common
stock. Net daily production from the West Buna Field approximates 900,000
cubic feet of natural gas equivalent.
On March 1, 2002, we sold the properties acquired on November 15,
2001, to Whiting Petroleum Corporation for $648,000. As a result of the sale,
we recorded a loss on sale of oil and gas properties of $106,000. Proceeds
from the sale were used to pay existing debt.
closing adjustments.
On February 19, 2002, we completed the acquisition of Piper Petroleum Company ("Piper"(“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 5
$5,234,000$5.2 million based on the five-day average market closing price of Delta'sDelta’s common stock surrounding the announcement of the merger. In addition,
We have an 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 38,447,369 shares were issued and outstanding as of June 30, 2004. We have outstanding warrants and options to non-employees to purchase 57,500 shares of common stock at prices ranging from $3.25 per share to $5.00 per share at June 30, 2004. Additionally, as of June 30, 2004 we issued 51,000had outstanding options which were granted to our officers, employees and directors under our incentive plans, to purchase up to 4,700,772 shares of common stock at prices ranging from $0.05 to $13.43 per share.
On June 29, 2004, we increased our credit facility to $100 million with a current borrowing base of $70 million with Bank of Oklahoma, N.A., US Bank National Association and Hibernia National Bank (the “Banks”). The proceeds from the increase in our credit facility were used for the cancellationAlpine acquisition.
At June 30, 2004, we owned 4,277,977 shares of certain debtcommon stock of Piper. As a resultAmber Resources Company (“Amber”), representing 91.68% of the acquisition, we
acquired Piper'soutstanding common stock of Amber. Amber is a public company (registered under the Securities Exchange Act of 1934) which owns non-operated working and royalty interests in over 700 gross (4.6 net)
wells which are primarily located in Texas, Oklahoma and Louisiana along with
a 5% working interest in the Comet Ridge coal bed methane gas project in
Queensland, Australia. On May 24, 2002 we completed the sale of our undivided
interests in Australia, to Tipperary Corporation, in exchange for Tipperary's
producing properties in the West Buna Field (Hardin and Jasper counties,
Texas)which had a fair market value of approximately $4,100,000, $700,000 in
cash, and 250,000 unregistered shares of Tipperary common stock. No gain or
loss was recorded on this transaction. Net daily production from the West
Buna Field approximates 900,000 cubic feet equivalent. In addition, on May
28, 2002, we sold a commercial office building obtained in the merger with
Piper located in Fort Worth, Texas to a non-affiliate for its fair value of
$417,000. No gain or loss was recorded on this transaction. Piper was merged
into a subsidiary wholly owned by Delta and the subsidiary was then renamed
"Piper Petroleum Company".
On November 15, 2001, we acquired producing oil and gas interests in
Texas from three unrelated parties. The acquisition had a purchase price of
approximately $788,000 consisting of $413,000 in cash and 137,000 shares of
our restricted common stock with a fair value of $375,000 based on the market
closing price of Delta's common stock on the date of closing.undeveloped leases offshore California, near Santa Barbara. On July 1, 2001, we purchased all the producing properties of Amber
our 91.68% owned subsidiary, for $107,000. The purchase price was based on an evaluation performed by an unrelated engineering firm. The effects of this transaction are eliminated in the consolidated financial statements. (b) BusinessWe entered into an agreement with Amber effective October 1, 1998 which provides, in part, for the sharing of Issuer.
the management between the two companies and allocation of expenses related thereto.
Operations
During the year ended June 30, 2002,2004, we were 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 ownedwholly-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;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, Alabama,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 anya number of different manners whichthat 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.
6
(1) Principal Products or Services
During fiscal 2004 we also acquired a fifty percent interest in a small drilling company and Their Markets. a fifty percent interest in a small trucking company. Although we did not engage in any material drilling operations during fiscal 2004, our ownership interest in the drilling company will allow us to have priority access to at least two large drilling rigs. The initial purpose of our investment in the trucking company is to allow these drilling rigs to be moved to new drilling locations as necessary.
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.
(2)
Distribution Methods of the Products or Services.
Oil and natural gas produced from our wells are normally sold to various purchasers as referenced in (6)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 fee 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.
(3) Status of Any Publicly Announced New Product or Service.
Competition
We have not made a public announcement of, and no information has otherwise
become public about, a new product or industry segment requiring the
investment of a material amount of our total assets.
(4) Competitive Business Conditions. Oil and gas exploration and
acquisition of undeveloped properties is a highly competitive and speculative
business. We compete with a number of other companies, includingencounter strong competition from major oil companies and other independent operators which are more experiencedin acquiring properties and which
have greater financial resources. We do not hold a significantleases 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 gas and oil leases. The principal competitive positionfactors in the acquisition of undeveloped gas and oil 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 industry.
(5) Sources and Availabilitycrude oil are affected by a number of Raw Materials and Names of
Principal Suppliers. Oil and gas may be considered raw materials essential to
our business. The acquisition, exploration, development, production, and sale
of oil and gas are subject to many factors which are outsidebeyond our control, the effect of our control.
These factors include nationalwhich cannot be accurately predicted. See “Risk Factors.”
Raw Materials
The principal raw materials and international economic conditions,
availabilityresources necessary for the exploration and development of natural gas and crude oil and leasehold prospects under which gas and oil reserves may be discovered, drilling rigs casing, pipe, and otherrelated equipment to drill for and produce such reserves and knowledgeable personnel to conduct all phases of gas and oil operations. Although equipment and supplies proximityused 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 pipelines,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 recently acquired a fifty percent interest in a small drilling company and a fifty percent interest in a small trucking company. We believe that our ownership interest in the supplydrilling company will provide us with at least two large drilling rigs. The initial purpose of our investment in the trucking company is to allow these drilling rigs to be moved to new drilling locations as necessary. 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 of other fuels,increases in, drilling equipment and supplies, including drill pipe, in the regulation of prices, production, transportation,future. Any such shortages could delay and marketing by the
Department of Energy and other federal and state governmental authorities.
(6) Dependence on One or a Few adversely affect our ability to meet our drilling commitments.
Major Customers. Customers
During our fiscal year ended June 30, 2002,2004, we sold a significant portion of our oil and gas production to the following companies: Dynegy,Seminole, Texla, Cinergy, Gulfmark, BP and Plains Marketing. 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.
(7) Patents, Trademarks, Licenses, Franchises, Concessions, Royalty
Agreements or Labor Contracts. We do not own any patents, trademarks,
licenses, franchises, concessions, or royalty agreements except oil and gas
interests acquired from industry participants, private landowners and state
and federal governments. We are not a party to any labor contracts.
(8) Need for Any Governmental Approval of Principal Products or
Services. Except that we must obtain certain permits and other approvals from
various governmental agencies prior to drilling wells and producing oil and/or
7
natural gas, we do not need to obtain governmental approval of our principal
products or services.
(9)
Government Regulation of the Oil and Gas Industry.
General.
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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. Changes in any of these laws and regulations could have a material adverse effect on our business. In view 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.
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.
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Regulation
Together with other companies in the industries in which we operate, 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 duration and success of obtaining 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 obtained, 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
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.
Hazardous Substances and Waste Disposal.
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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"(“CERCLA”) and comparable state statutes impose strict, joint and several liabilityliabilities on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances"“hazardous substances” found at such sites. The Resource Conservation and Recovery Act ("RCRA"(“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,"“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 gas and oil industry in general.
Oil Spills.
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Spills
Under the Federal Oil Pollution Act of 1990, as amended ("OPA"(“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"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 million in the case of onshore facilities, $75 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.
9
In addition, with respect to certain offshore facilities, OPA requires evidence of financial responsibility in an amount of up to $150 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 Minerals Management Service of the United States Department of the Interior ("MMS"(“MMS”) to carry certain types of insurance and to post bonds in that regard. In addition, we also carry insurance as a non-operator in the amount of $5 million onshore and $10 million offshore. There is no assurance that our insurance coverage is adequate to protect us.
Offshore Production.
-------------------
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'slessee’s operations, and such 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.
(10) Research and Development. We do not engage in any research
and development activities. Since our inception, we have not had any customer
or government-sponsored material research activities relating to the
development of any new products, services or techniques, or the improvement of
existing products.
(11) Environmental Protection.
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 nor adversely affect our business. Capital expenditures relating to environmental control facilities have not been material to our operation since our inception. In addition, we do not anticipate that such expenditures will be material during the fiscal year ending June 30, 2003.
(12) Employees. 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, pro rata to our working interest. As of January 1, 2003 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 recorded an asset retirement obligation of approximately $2.6 million at June 30, 2004.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 twenty-twoapproximately 50 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.
10
ITEM
Certain Risks
Owners of common stock are subject to a variety of risks, including, without limitation, the following:
Risks Related to Our Stock
1. 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.
2. DESCRIPTION OF PROPERTY
(a) Office Facilities.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.
3. Our officesmanagement controls a significant percentage of our outstanding common stock and their interests may conflict with those of our shareholders.
As of June 30, 2004, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 29% of our outstanding common stock. In addition, one of our affiliates, Castle Energy Corporation, has agreed to vote in favor of all of management’s nominees for director and in favor of other matters recommended by our Board of Directors at annual shareholder meetings. This concentration of voting control gives our directors and executive officers and their respective affiliates substantial influence over any matters that require a shareholder vote, including, without limitation, the election of directors, even if their interests may conflict with those of other shareholders. It could also have the effect of delaying or preventing a change in control of or otherwise discouraging a potential acquirer from attempting to obtain control of us. This could have a material adverse effect on the market price of our common stock or prevent our shareholders from realizing a premium over the then prevailing market prices for their shares of common stock.
4. Sales of substantial amounts of our common stock may adversely affect our stock price and make future offerings to raise capital difficult.
Sales of a large number of shares of our common stock in the market or the perception that sales may occur could adversely affect the trading price of our common stock. As of June 30, 2004, 38,447,369 shares of our common stock were outstanding, almost all of which currently are located at 475 Seventeenth Street, Suite 1400,
Denver, Colorado 80202.freely tradable, subject to certain volume limitations and other requirements applicable to affiliates. We leaserecently issued 6,000,000 restricted shares to investors in a private placement of our shares and issued an additional 2,525,000 restricted shares to Edward Mike Davis and entities controlled by him. We have registered all 2,525,000 shares for resale. As of June 30, 2004, options to purchase up to a total of approximately 9,500 square feet4,758,272 shares of office
space for approximately $15,500 per month and the lease will expire in
September, 2008.
(b) Oil and Gas Properties.
our common stock were outstanding.
We own interests in producing oil and gas properties located
primarily in fifteen (15) states plus off-shore Santa Barbara California.
Most wells from which we receive revenues are owned only partially by us. For
information concerning our oil and gas production, average prices and costs,
estimated oil and gas reserves and estimated future cash flows, see the tables
set forth below in this section and "Notes to Financial Statements" included
in this report. We did not file oil and gas reserve estimates with any federal
authoritymay issue additional restricted securities or agency other thanregister additional shares of common stock under the Securities Act in the future for our use in connection with future acquisitions. Pursuant to Securities Act Rule 145, the volume limitations and Exchange Commission duringcertain other requirements of Rule 144 would apply to resales of these shares by affiliates of the past two years.
Principal Properties.
--------------------
businesses that we acquire for a period of one year from the date of their acquisition, but otherwise these shares would be freely tradable by persons not affiliated with us unless we contractually restrict their resale.
The following is a brief descriptionavailability for sale, or sale, of the shares of common stock eligible for future sale could adversely affect the market price of our principal properties:
Onshore:
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We own interestscommon stock.
5. Provisions in approximately 464 gross (215 net) producing
wellssome of our employment agreements with key employees could delay or prevent a change in fifteen (15) states, not including interestscontrol of our Company, even if that change would be beneficial to our shareholders.
Certain provisions in those wells owned byemployment agreements with certain of our subsidiary, Piper Petroleum Company ("Piper"). Piper owns varying very
small interests in approximately 700 gross (4.6 net) wells located primarily
in Texas. Piper's wells produce approximately 30 bbls per day and 200 mcf per
day net to Piper's interests.
Our principal onshore producing properties arekey employees provide that in the following
states:
Alabama
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We ownevent of a change of control of our Company we will immediately cause all of such employees’ then outstanding unexercised options to be exercised by us on behalf of such employees and operatethat we will pay all related federal, state and local taxes applicable to such exercise. Such provisions could delay, discourage, prevent or render more difficult an attempt to obtain control of our Company, whether through a 94.5% working interest in 50 coal bed
methane gas wells at depths of about 2,500 feet in Tuscaloosa County.tender offer, business combination, proxy contest or otherwise. These wells produce approximately 1650 mcf per day net to our interests.
We also own a .6455% working interest in the Hatter's Pond Unit
in Mobil County which is operated by Four Star Oil and Gas. This unit
produces approximately 18 barrels per day and 207 mcf per day net to our
interest.
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Texas
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We own interests in 149 gross (52.7 net) wells in Texas located
primarily in South Texas, East Texas and the Permian Basin with approximately
one third of the production coming from each area. We operate 42 of these
wells. These wells are scattered throughout 32 counties and are drilled to
various depths and reservoirs with varying working interests. In aggregate
these wells produce approximately 370 barrels of oil and 4,000 mcf of gas per
day.
This includes our interest in the West Buna field located in
Jasper and Hardin Counties which we recently acquired from Tipperary
Corporation. The West Buna field contains 20 wells producing approximately 53
barrels of oil and 418 mcf of gas per day. We own an average working interest
of approximately 8.5% plus additional royalty interests which give us an
average net revenue interest of approximately 12.4%.employment agreements terminate November 1, 2004.
6. We do not operateexpect to pay dividends on our common stock.
We do not expect to pay any of
the West Buna Field wells.
Pennsylvania
------------
We own 143 wellsdividends, in cash or otherwise, with an average working interest of
approximately 75% in six counties in Pennsylvania. We operate 104 of these
wells. The wells are drilled to an average depth of 3,500 feet and produce
approximately 1058 mcf per day netrespect to our interests.
Louisiana
---------common stock in the foreseeable future. We intend to retain any earnings for use in our business. In Louisiana we own interests in 15 wells with an average
working interest of 56.4% located in Acadia, Catahoula, Plaquemines and Pointe
Coupee parishes. We produce primarily fromaddition, the Wilcox formation at a depth of
10,000 to 11,000 feet. We operate 11 of these wells. Daily production is
approximately 225 barrels of oil per day netcredit agreement relating to our interests.
New Mexico
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We own interests in 32 wells in New Mexico, including our East
Carlsbad field in Eddy County where 10$100 million credit facility with the Bank of Oklahoma, U.S. Bank and Hibernia Bank prohibits us from paying any dividends until the wells are located. These wells
produce approximately 30 barrels of oil and 970 mcf of gas per day net to our
interests. We operate 9 of these wells.
Other States:
------------
We also own varying interests in producing wells in the following
states: California (Sacramento Basin), Colorado (D-J and Piceance Basins),
Oklahoma, Illinois, Mississippi, Michigan, Kansas, Montana, Wyoming and
Nebraska.
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Offshore:
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Offshore Federal Waters: Santa Barbara, California Area
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Unproved Undeveloped Properties:
-------------------------------
We own interests in five undeveloped federal units (plus one
additional lease) located in federal waters offshore California near Santa
Barbara.loan is retired.
7. The Santa Barbara Channel and the offshore Santa Maria Basin
are the seaward portions of geologically well-known onshore basins with over
90 years of production history. These offshore areas were first explored in
the Santa Barbara Channel along the near shore three mile strip controlled by
the state. New field discoveries in Pliocene and Miocene age reservoir sands
led to exploration into the federally controlled waters of the Pacific Outer
Continental Shelf ("POCS"). Although significant quantities of oil and gas
have been produced and sold from drilling conducted on POCS leases between
1966 and 1989, we do not own anycommon stock is an unsecured equity interest in any offshore California
production except for our smallCompany.
As an equity interest, in the Point Arguello Unit discussed
below, and there is no assurance thatcommon stock will not be secured by any of our undeveloped properties will
ever achieve production.
Mostassets. Therefore, in the event we are liquidated, the holders of the early offshore production was from Pliocene age
sandstone reservoirs. The more recent developments are from the highly
fractured zonescommon stock will receive a distribution only after all of the Miocene age Monterey Formation. The Monterey is
productive in both the Santa Barbara Channelour secured and the offshore Santa Maria
Basin. It is the principal producing horizon in the Point Arguello field, the
Point Pedernales field, and the Hondo and Pescado fields in the Santa Ynez
Unit. Because the Monterey is capable of relatively high productive rates,
the Hondo field, which has been on production since late 1981, has already
surpassed 224 million Bbls of oil production and 411 Bcf of gas production.
All told, offshore fields producing from the Monterey as of the end of
calendar 2000 have produced 526 million Bbls of oil and 544 Bcf of gas.
California's active tectonic history over the last few million
years has formed the large linear anticlinal features which trap the oil and
gas. Marine seismic surveysunsecured creditors have been used to locate and define these
structures offshore.
Recent seismic surveying utilizing modern 3-D seismic
technology, coupled with exploratory well data, has greatly improved knowledge
of the size of reservespaid in fields under development and in fields for which
development is planned. Currently, 11 fields are producing from 18 platforms
in the Santa Barbara Channel and offshore Santa Maria Basin. Implementation
of extended high-angle to horizontal drilling methods is reducing the number
of platforms and wells needed to develop reserves in the area. Use of these
new drilling methods and seismic technologies is expected to continue to
improve development economics.
Leasing, lease administration, development and production
within the Federal POCS all fall under the Code of Federal Regulations
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administered by the MMS. The EPA controls disposal of effluents, such as
drilling fluids and produced waters. Other Federal agencies, including the
Coast Guard and the Army Corps of Engineers, also have oversight of offshore
construction and operations.
The first three miles seaward of the coastline are administered
by each state and are known as "State Tidelands" in California. Within the
State Tidelands off Santa Barbara County, the State of California, through the
State Lands Commission, regulates oil and gas leases and the installation of
permanent and temporary producing facilities. Because the four units in which
we own interests are located in the POCS seaward of the three mile limit,
leasing, drilling, and development of these units are not directly regulated
by the State of California. However, to the extent that any production is
transported to an on-shore facility through the state waters, our pipelines
(or other transportation facilities) would be subject to California state
regulations. Construction and operation of any such pipelines would require
permits from the state. Additionally, all development plans must be
consistent with the Federal Coastal Zone Management Act ("CZMA"). In
California the decision of CZMA consistency is made by the California Coastal
Commission.
The Santa Barbara County Energy Division and the Board of
Supervisors will have a significant impact on the method and timing of any
offshore field development through its permitting and regulatory authority
over the construction and operation of on-shore facilities. In addition, the
Santa Barbara County Air Pollution Control District has authority in the
federal waters off Santa Barbara County through the Federal Clean Air Act as
amended in 1990.
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. The size of our working interest in the units, other than the Rocky
Point Unit, varies from 2.492% to 15.60%. We also own a working interest of
approximately 75% in the Rocky Point Unit. This interest is expected to be
reduced if the Rocky Point Unit is included in the Point Arguello Unit and
developed from existing Point Arguello platforms. We may be required to farm
out all or a portion of our interests in these properties to a third party if
we cannot fund our share of the development costs.full. There can be no assurance that we can farm outwill have sufficient assets after paying our interests on acceptable terms.
These units have been formally approvedsecured and are regulated byunsecured creditors to make any distribution to the MMS. While the Federal Government has recently attempted to expedite the
process of obtaining permits and authorizations necessary to develop the
properties, there can be no assurance that it will be successful in doing so.
We do not act as operator of any offshore California properties
and consequently will not generally control the timing of either the
developmentholders of the properties or the expenditures for development unless we
choose to unilaterally propose the drilling of wells under the relevant
operating agreements.
The MMS initiated the California Offshore Oil and Gas Energy
Resources (COOGER) Study at the request of the local regulatory agencies of
the three counties (Ventura, Santa Barbara and San Luis Obispo) affected by
offshore oil and gas development. A private consulting firm completed the
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study under a contract with the MMS. The COOGER Study presents a long-term
regional perspective of potential onshore constraints that should be
considered when developing existing undeveloped offshore leases. The COOGER
Study projects the economically recoverable oil and gas production from
offshore leases which have not yet been developed. These projections are
utilized to assist in identifying a potential range of scenarios for
developing these leases. These scenarios are compared to the projected
infrastructural, environmental and socioeconomic baselines between 1995 and
2015.
No specific decisions regarding levels of offshore oil and gas
development or individual projects will occur in connection with the COOGER
Study. Information presented in the study is intended to be utilized as a
reference document to provide the public, decision makers and industry with a
broad overview of cumulative industry activities and key issues associated
with a range of development scenarios. We have attempted to evaluate the
scenarios that were studied with respect to properties located in the eastern
and central subregions (which include the Sword Unit and the Gato Canyon Unit)
and the results of such evaluation are set forth below:
Scenario 1 - No new development of existing offshore leases. If
this scenario were ultimately to be adopted by governmental
decision makers as the proper course of action for development,
our offshore California properties would in all likelihood have
little or no value. In this scenario we would seek to cause the
Federal government to reimburse us for all money spent by us and
our predecessors for leasing and other costs and for the value of
the oil and gas reserves found on the leases through our
exploration activities and those of our predecessors.
Scenario 2 - Development of existing leases, using existing
onshore facilities as currently permitted, constructed and
operated (whichever is less) without additional capacity. This
scenario includes modifications to allow processing and
transportation of oil and natural gas with different qualities.
It is likely that the adoption of this scenario by the industry as
the proper course of action for development would result in lower
than anticipated costs, but would cause the subject properties to
be developed over a significantly extended period of time.
Scenario 3 - Development of existing leases, using existing
onshore facilities by constructing additional capacity at existing
sites to handle expanded production. This scenario is currently
anticipated by our management to be the most reasonable course of
action although there is no assurance that this scenario will be
adopted.
Scenario 4 - Development of existing leases after
decommissioning and removal of some or all existing onshore
facilities. This scenario includes new facilities, and perhaps
new sites, to handle anticipated future production. Under this
scenario we would incur increased costs but revenues would be
received more quickly.
15
We have also evaluated our position with regard to the scenarios
with respect to properties located in the northern sub-region (which includes
the Lion Rock Unit and the Point Sal Unit), the results of which are as
follows:
Scenario 1 - No new development of existing offshore leases.
If this scenario were ultimately to be adopted by governmental
decision makers as the proper course of action for development,
our offshore California properties would in all likelihood have
little or no value. In this scenario we would seek to cause the
Federal government to reimburse us for all money spent by us and
our predecessors for leasing and other costs and for the value of
the oil and gas reserves found on the leases through our
exploration activities and those of our predecessors.
Scenario 2 - Development of existing leases, using existing
onshore facilities as currently permitted, constructed and
operated (whichever is less) without additional capacity. This
scenario includes modifications to allow processing and
transportation of oil and natural gas with different qualities.
It is likely that the adoption of this scenario by the industry
as the proper course of action for development would result in
lower than anticipated costs, but would cause the subject
properties to be developed over a significantly extended period
of time.
Scenario 3 - Development of existing leases, using existing
onshore facilities by constructing additional capacity at existing
sites to handle expanded production. This scenario is currently
anticipated by our management to be the most reasonable course of
action although there is no assurance that this scenario will be
adopted.
Scenario 4 - Development of existing offshore leases, using
existing onshore facilities with additional capacity or adding new
facilities to handle a relatively low rate of expanded
development. This scenario is similar to #3 above, but would
entail increased costs for any new facilities.
Scenario 5 - Development of existing offshore leases, using
existing onshore facilities with additional capacity or adding new
facilities to handle a relatively higher rate of expanded
development. Under this scenario we would incur increased costs
but revenues would be received more quickly.
The development plans for the various units (which have been
submitted to the MMS for review) currently provide for 22 wells from one
platform set in a water depth of approximately 300 feet for the Gato Canyon
Unit; 63 wells from one platform set in a water depth of approximately 1,100
feet for the Sword Unit; 60 wells from one platform set in a water depth of
approximately 336 feet for the Point Sal Unit; and 183 wells from two
platforms for the Lion Rock Unit.
On the Lion Rock Unit, Platform A would be set in a water depth of
approximately 507 feet, and Platform B would be set in a water depth of
approximately 484 feet. The reach of the deviated wells from each platform
16
required to drain each unit falls within the reach limits now considered to be
"state-of-the-art." The development plans for the Rocky Point Unit provide
for the inclusion of the Rocky Point leases in the Point Arguello Unit upon
which the Rocky Point leases would be drilled from existing Point Arguello
platforms with extended reach drilling technology. The approximate distances
required to drain the Rocky Point leases range from 2,276 feet to 13,999 feet
at proposed total vertical depths ranging from 6,620 feet to 7,360 feet.
Current Status. On October 15, 1992 the MMS directed a Suspension
of Operations (SOO), effective January 1, 1993, for the POCS undeveloped
leases and units. The SOO was directed for the purpose of preparing what
became known as the COOGER Study. Two-thirds of the cost of the Study was
funded by the participating companies in lieu of the payment of rentals on the
leases. Additionally, all operations were suspended on the leases during this
period. On November 12, 1999, as the COOGER Study drew to a conclusion, the
MMS approved requests made by the operating companies for a Suspension of
Production (SOP) status for the POCS leases and units. During the period of
an SOP, the lease rentals resume and each operator is generally required to
perform exploration and development activities in order to meet certain
milestones set out by the MMS. The milestones that were established by the
MMS for the properties in which we own an interest were established through
negotiations by the MMS on behalf of the United States government and the
operators on behalf of the working interest owners. We did not directly
participate in these negotiations. Until recently, progress toward the
milestones was monitored by the operator in quarterly reports submitted to the
MMS. In February 2000 all operators completed and timely submitted to the MMS
a preliminary "Description of the Proposed Project". This was the first
milestone required under the SOP. Quarterly reports were also prepared and
submitted for all subsequent quarters.
On June 22, 2001, however, a Federal Court in the case of California
v. Norton, et al. (discussed below - see "Management's Discussion and Analysis
or Plan of Operation-Offshore Undeveloped Properties") ordered the MMS to set
aside its approval of the suspensions of our offshore leases and to direct
suspensions, including all milestone activities, for a time sufficient for the
MMS to provide the State of California with a consistency determination under
federal law. As a result of this order, on July 2, 2001 the MMS directed
suspensions of operations for all of our offshore California leases for an
indefinite period of time and suspended all of the related milestones. The
ultimate outcome and effects of this litigation are not certain at the present
time. In order to continue to carry out the requirements of the MMS, all
operators of the units in which we own non-operating interests are prepared to
meet the next milestone leading to development of the leases, but the status
of the milestones is presently uncertain in light of the Norton ruling. The
United States government has filed a notice of its intent to appeal the
court's order in the Norton case.
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
17
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 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 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. 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 Coastal Zone
Management Act and we decide not to appeal such ruling to the Secretary of
Commerce, or the Secretary of Commerce either refuses to hear our appeal of
any such ruling or ultimately makes a determination adverse to us, it is
likely that some or all of these leases would become impaired and written off
at that time.
In addition, it should be noted that our pending litigation against
the United States is predicated on the ruling of the lower court in California
v. Norton. The United States has appealed the decision of the lower court to
the 9th Circuit Court of Appeals. In the event that the United States is not
successful in its appeal(s) of the lower court's decision in the Norton case
and the pending litigation with us is not settled, it would be necessary for
us to reevaluate whether the leases should be considered impaired at that
time.
As the ruling in the Norton case currently stands, the United States
has been ordered to make a consistency determination under the Coastal Zone
Management Act, but the leases are still valid. If through the appellate
process the leases are found not to be valid for some reason, or if the United
States is finally ordered to make a consistency determination and either does
not do so or finds that development is inconsistent with the Coastal Zone
Management Act, it would appear that the leases would become impaired even
though we would undoubtedly proceed with our litigation. It is also possible
that other events could occur during the appellate process that would cause
the leases to become impaired, and we will continuously evaluate those factors
as they occur.
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. our claim
for lease bonuses and rentals paid by us and our predecessors is in excess of
$152,000,000. In addition, our claim for exploration costs and related
expenses will also be substantial.
On May 18, 2001 (prior to the Norton decision), a revised
Development and Production Plan for the Point Arguello Unit was submitted to
the MMS and the California Coastal Commission ("CCC") for approval. If
approved by the CCC, this plan would enable development of the Rocky Point
Unit from the Point Arguello platforms that are already in existence.
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Under law, the CCC is typically required to make a determination as
to whether or not the Plan is "consistent" with California's Coastal Plan
within three months of submission, with a maximum of three months' extension
(a total of six months). By correspondence dated August 7, 2001, however, the
Unit operator requested that the CCC suspend the consistency review for the
revised Development and Production Plan since the MMS had temporarily stopped
work on the processing of the plan as the result of the Norton decision.
Although it currently appears likely that the CCC may require some
additional supplemental information to be provided with respect to some
aspects of air and water quality when its review continues, we believe that
the Rocky Point Development and Production Plan that was submitted meets the
requirements established by applicable federal regulations. In accordance
with these regulations, the Plan includes very specific information regarding
the planned activities, including a description of and schedule for the
development and production activities to be performed, including plan
commencement date, date of first production, total time to complete all
development and production activities, and dates and sequences for drilling
wells and installing facilities and equipment, and a description of the
drilling vessels, platforms, pipelines and other facilities and operations
located offshore which are proposed or known by the lessee (whether or not
owned or operated by the lessee) to be directly related to the proposed
development, including the location, size, design, and important safety,
pollution prevention, and environmental monitoring features of the facilities
and operations. The current Development and Production Plan calls for
drilling activities to be conducted from the existing Point Arguello platforms
using extended reach drilling techniques with oil and gas production to be
transported through existing pipelines to existing onshore production
facilities. The plan does not require the construction of new platforms,
pipelines or production facilities.
In accordance with applicable federal regulations, the following
supporting information accompanies the Development and Production Plan: (1)
geological and geophysical data and information, including: (i) a plat showing
the surface location of any proposed fixed structure or well; (ii) a plat
showing the surface and bottomhole locations and giving the measured and true
vertical depths for each proposed well; (iii) current interpretations of
relevant geological and geophysical data; (iv) current structure maps showing
the surface and bottomhole location of each proposed well and the depths of
expected productive formations; (v) interpreted structure sections showing the
depths of expected productive formations; (vi) a bathymetric map showing
surface locations of fixed structures and wells or a table of water depths at
each proposed site; and (vii) a discussion of seafloor conditions including a
shallow hazards analysis for proposed drilling and platform sites and pipeline
routes.
As required by federal regulations, the information contained in the
Plan contains proposed precautionary measures, including a classification of
the lease area, a contingency plan, a description of the environmental
safeguards to be implemented, including an updated oil-spill response plan;
and a discussion of the steps that have been or will be taken to satisfy the
conditions of lease stipulations, a description of technology and reservoir
19
engineering practices intended to increase the ultimate recovery of oil and
gas, i.e., secondary, tertiary, or other enhanced recovery practices; a
description of technology and recovery practices and procedures intended to
assure optimum recovery of oil and gas; a discussion of the proposed drilling
and completion programs; a detailed description of new or unusual technology
to be employed; and a brief description of the location, description, and size
of any offshore and land-based operations to be conducted or contracted for as
a result of the proposed activity; including the acreage required in
California for facilities, rights-of-way, and easements, the means proposed
for transportation of oil and gas to shore; the routes to be followed by each
mode of transportation; and the estimated quantities of oil and gas to be
moved along such routes; an estimate of the frequency of boat and aircraft
departures and arrivals, the onshore location of terminals, and the normal
routes for each mode of transportation.
As required, the Plan also provides a list of the proposed drilling
fluids, including components and their chemical compositions, information on
the projected amounts and rates of drilling fluid and cuttings discharges, and
methods of disposal, and specifies the quantities, types, and plans for
disposal of other solid and liquid wastes and pollutants likely to be
generated by offshore, onshore, and transport operations and, regarding any
wastes which may require onshore disposal, the means of transportation to be
used to bring the wastes to shore, disposal methods to be utilized, and the
location of onshore waste disposal or treatment facilities.
In order to comply with federal regulations, the Plan also addresses
the approximate number of people and families to be added to the population of
local nearshore areas as a result of the planned development, provides an
estimate of significant quantities of energy and resources to be used or
consumed including electricity, water, oil and gas, diesel fuel, aggregate, or
other supplies which may be purchased within California, and specifies the
types of contractors or vendors which will be needed, although not
specifically identified, and which may place a demand on local goods and
services.
The Plan also identifies the source, composition, frequency, and
duration of emissions of air pollutants and provides a narrative description
of the existing environment with an emphasis placed on those environmental
values that may be affected by the proposed action. This section of the Plan
contains a description of the physical environment of the area covered by the
Plan and includes data and information obtained or developed by the lessee
together with other pertinent information and data available to the lessee
from other sources. The environmental information and data includes a
description of the aquatic biota, including fishery and marine mammal use of
the lease, the significance of the lease and identifies the threatened and
endangered species and their critical habitat.
The Plan also addresses environmentally sensitive areas (e.g.,
refuges, preserves, sanctuaries, rookeries, calving grounds, coastal habitats,
beaches, and areas of particular environmental concern) which may be affected
by the proposed activities, the predevelopment, ambient water-column quality
and temperature data for incremental depths for the areas encompassed by the
plan, the physical oceanography, including ocean currents described as to
prevailing direction, seasonal variations, and variations at different water
depths in the lease, and describes historic weather patterns and other
20
meteorological conditions, including storm frequency and magnitude, wave
height and direction, wind direction and velocity, air temperature,
visibility, freezing and icing conditions, and ambient air quality listing,
where possible, the means and extremes of each.
The Plan further identifies other uses of the area, including
military use for national security or defense, subsistence hunting and
fishing, commercial fishing, recreation, shipping, and other mineral
exploration or development and describes the existing and planned monitoring
systems that are measuring or will measure impacts of activities on the
environment in the planning area. As required, the Plan provides an
assessment of the effects on the environment expected to occur as a result of
implementation of the Plan, and identifies specific and cumulative impacts
that may occur both onshore and offshore, and describes the measures proposed
to mitigate these impacts. These impacts are quantified to the fullest extent
possible including magnitude and duration and are accumulated for all
activities for each of the major elements of the environment (e.g., water and
biota). The Plan also provides a discussion of alternatives to the activities
proposed that were considered during the development of the Plan, including a
comparison of the environmental effects.
As required, the Plan provides certain supporting information with
respect to the projected emissions from each proposed or modified facility for
each year of operation and the bases for all calculations, including, for each
source, the amount of the emission by air pollutant expressed in tons per year
and frequency and duration of emissions; for each proposed facility, the total
amount of emissions by air pollutant expressed in tons per year, the frequency
distribution of total emissions by air pollutant expressed in pounds per day
and, in addition for a modified facility only, the incremental amount of total
emissions by air pollutant resulting from the new or modified source(s); and a
detailed description of all processes, processing equipment and storage units,
including information on fuels to be burned; and a schematic drawing which
identifies the location and elevation of each source.
In order to continue to carry out the requirements of the MMS when
they resume, all operators of the units in which we own non-operating
interests are prepared to complete any studies and project planning necessary
to commence development of the leases. Where additional drilling is needed,
the operators will bring a mobile drilling unit to the POCS to further
delineate the undeveloped oil and gas fields.
Cost to Develop Offshore California Properties. The cost to develop
four of the five undeveloped units (plus one lease) located offshore
California, 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 by the partners to be in
excess of $3 billion.common stock.
8. Our share based on our current working interest of such
costs over the life of the properties is estimated to be over $200 million.
There will be additional costs of a currently undetermined amount to develop
the Rocky Point Unit which is the fifth undeveloped unit in which we own an
interest.
To the extent that weshareholders do not have sufficient cash available to pay
our share of expenses when they become payable under the respective operating
21
agreements, it will be necessary for us to seek funding from outside sources.
Likely potential sources for such funding are currently anticipated to include
(a) public and private salescumulative voting rights.
Holders of our common stock (which may result in
substantial ownership dilutionare not entitled to existing shareholders), (b) bank debt from
oneaccumulate their votes for the election of directors or otherwise. Accordingly, the holders of more commercial oil and gas lenders, (c) the sale of debt instruments
to investors, (d) entering into farm-out arrangements with respect to one or
morethan 50% of our interests in the properties whereby the recipient of the farm-out
would pay the full amount of our share of expenses and we would retain a
carried ownership interest (which would result in a substantial diminution of
our ownership interest in the farmed-out properties), (e) entering into one or
more joint venture relationships with industry partners, (f) entering into
financing relationships with one or more industry partners, and (g) the sale
of some oroutstanding common stock will be able to elect all of our interests indirectors. As of June 30, 2004, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 29% of our outstanding common stock.
9. Our Articles of Incorporation 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 properties.
It is unlikely that any one potential source of funding would be
utilized exclusively. Rather, it is more likely that we will pursue a
combination of different funding sources when the need arises. Regardlessprovisions of the type of financing techniques that are ultimately utilized, however, it
currently appears likely that because of our small size in relation to the
magnitude of the capital requirements that will be associated with the
development of the subject properties, we will be forced in the future to
issue significant amounts of additional shares, pay significant amounts of
interest on debt that presumably would be collateralized by all of our assets
(including our offshore California properties), reduce our ownership interest
in the properties through sales of interests in the properties or as the
result of farmouts, industry financing arrangementsColorado Business Corporation Act may discourage persons from considering unsolicited tender offers or other partnership or
joint venture relationships, orunilateral takeover proposals. Such persons might choose to enter into various transactions which will
result in some combination of the foregoing. In the event that we are not
able to pay our share of expenses as a working interest owner as required by
the respective operating agreements, it is possible that we might lose some
portion of our ownership interest in the properties under some circumstances,
or that we might be subject to penalties which would result in the forfeiture
of substantial revenues from the properties.
While the costs to develop the offshore California properties in
which we own an interest are anticipated to be substantial in relation to our
small size, management believes that the opportunities for us to increase our
asset base and ultimately improve our cash flow are also substantial in
relation to our size. Although there are several factors to be considered in
connectionnegotiate with our plans to obtain funding from outside sources as necessary
to pay our proportionate shareBoard of the costs associated with developing our
offshore properties (not the least of which is the possibility that prices for
petroleum products could decline in the future to a point at which development
of the properties is no longer economically feasible), we believe that the
timing and rate of development in the future will in large part be motivated
by the prices paid for petroleum products.
To the extent that prices for petroleum products were to decline
below their recent levels, it is likely that development efforts will proceed
at a slower pace such that costs will be incurred over a more extended period
of time. If petroleum prices remain at current levels, however, we believe
that development efforts will intensify. Our ability to successfully
negotiate financing to pay our share of development costs on favorable terms
will be inextricably linked to the prices that are paid for petroleum products
22
during the time period in which development is actually occurring on each of
the subject properties.
Gato Canyon Unit. We hold a 15.60% working interest in the Gato
Canyon Unit. This 10,100 acre unit is operated by Samedan Oil Corporation.
Seven test wells have been drilled on the Gato Canyon structure. Five of
these were drilled within the boundaries of the Unit and two were drilled
outside the Unit boundaries in the adjacent State Tidelands. The test wells
were drilled as follows: within the boundaries of the Unit, three wells were
drilled by Exxon, two in 1968 and one in 1969; one well was drilled by Arco
in 1985 and one well was drilled by Samedan in 1989. Outside the boundaries
of the Unit, in the State Tidelands but still on the Gato Canyon Structure,
one well was drilled by Mobil in 1966 and one well was drilled by Union Oil in
1967. In April 1989, Samedan tested the P-0460 #2 which yielded a combined
test flow rate of 5,160 Bbls of oil per day from six intervals in the Monterey
Formation between 5,880 and 6,700 feet of drilled depth. The Monterey
Formation is a highly fractured shale formation. The Monterey (which ranges
from 500 feet to 2,900 feet in thickness) is the main productive and target
zone in many offshore California oil fields (including our federal leases
and/or units).
The Gato Canyon field is located in the Santa Barbara Channel
approximately three to five miles offshore (see Map). Water depths range from
280 feet to 600 feet in the area of the field. Oil and gas produced from the
field is anticipated to be processed onshore at the existing Las Flores Canyon
facility (see Map). Las Flores Canyon has been designated a "consolidated
site" by Santa Barbara County and is available for use by offshore operators.
Any processed oil is expected to be transported out of Santa Barbara County in
the All American Pipeline (see Map). Offshore pipeline distance to access the
Las Flores site is approximately six miles. Our share of the estimated
capital costs to develop the Gato Canyon field is approximately $45 million.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 Norton case,rights, preferences and other designations, including voting rights of those shares, as the Gato Canyon Unit leases are held
under directed suspensions of operations with no specified end date. An
updated Exploration Plan is expected toBoard may determine. Additional provisions include plans to drill an additional
delineation well when activities are resumed. This well will be used to
determine the final location of the development platform. Following the
platform decision, a Development Plan will be prepared for submittal to the
MMSrestrictions on business combinations and the other involved agencies. Two to three years will likely be
required to process the Development Plan and receive the necessary approvals.
Point Sal Unit. We hold a 6.83% working interest in the Point Sal
Unit. This 22,772 acre unit is operated by Aera Energy LLC, a limited
liability company jointly owned by Shell Oil Company and ExxonMobil Company.
Four test wells were drilled within this unit.availability of authorized but unissued common stock. These test wells were drilled
as follows: two wells were drilled by Sun Oil (now Oryx Energy), one in 1984
and one in 1985; and the other two wells were drilled by Reading & Bates, both
in 1984. All four wells drilled on this unit have indicated the presenceprovisions may discourage transactions involving actual or potential changes of oil and gas in the Monterey Formation. The largest of these, the Sun P-0422
#1, yielded a combined test flow rate of 3,750 Bbls of oil per day from the
Monterey. The oil in the upper block has an average estimated gravity of 10E
API and the oil in the subthrust block has an average estimated gravity of 15E
API.
23
The Point Sal field is located in the Offshore Santa Maria Basin
approximately six miles seaward of the coastline. Water depths range from 300
feet to 500 feet in the area of the field. It is anticipatedcontrol, including transactions that oil and gas
produced from the field will be processed in a new facility at an onshore site
or in the existing Lompoc facility. Any processed oil would then be
transported out of Santa Barbara County in either the All American Pipeline or
the Tosco-Unocal Pipeline. Offshore pipeline distance is approximately six to
eight miles depending on the final choice of the point of landfall. Our share
of the estimated capital costs to develop the Point Sal Unit is approximately
$38 million.
As a result of the Norton case, the Point Sal Unit leases are held
under directed suspensions of operations with no specified end date. An
updated Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed prior to preparing the
Development Plan.
Lion Rock Unit and Federal OCS Lease P-0409. We hold a 1% net
profits interest in the Lion Rock Unit and a 24.21692% working interest in
5,693 acres in Federal OCS Lease P-0409 which is immediately adjacent to the
Lion Rock Unit and contains a portion of the San Miguel Field reservoir. The
Lion Rock Unit is operated by Aera Energy LLC. An aggregate of 13 test wells
have been drilled on the Lion Rock Unit and OCS Lease P-0409. Nine of these
wells were completed and tested and indicated the presence of oil and gas in
the Monterey Formation. The test wells were drilled as follows: one well was
drilled by Socal (now Chevron) in 1965; six wells were drilled by Phillips
Petroleum, one in 1982, two in 1983, two in 1984 and one in 1985; and six
wells were drilled by Occidental Petroleum in Lease P-0409, three in 1983 and
three in 1984. The oil has an average estimated gravity of 10.7E API.
The Lion Rock Unit and Lease P-0409 are located in the Offshore
Santa Maria Basin eight to ten miles from the coastline. Water depths range
from 300 feet to 600 feet in the area of the field. It is anticipated that any
oil and gas produced at Lion Rock and P-0409 would be processed at a new
facility in the onshore Santa Maria Basin or at the existing Lompoc facility,
and would be transported out of Santa Barbara County in the All American
Pipeline or the Tosco-Unocal Pipeline. Offshore pipeline distance will be
eight to ten miles, depending on the point of landfall. Our share of the
estimated capital costs to develop the Lion Rock/San Miguel field is
approximately $113 million.
As a result of the Norton case, the Lion Rock Unit and Lease P-0409
are held under directed suspensions of operations with no specified end date.
It is anticipated that upon the resumption of activities there will be an
interpretation of the 3D seismic survey and the preparation of an updated Plan
of Development leading to production. Additional delineation wells may or may
not be drilled depending on the outcome of the interpretation of the 3D
survey.
Sword Unit. We hold a 2.492% working interest in the Sword Unit.
This 12,240 acre unit is operated by Conoco, Inc. In aggregate, three wells
have been drilled on this unit, of which two wells were completed and tested
in the Monterey formation with calculated flow rates of from 4,000 to 5,000
Bbls per day with an estimated average gravity of 10.6E API. The two
24
completed test wells were drilled by Conoco, one in 1982 and the second in
1985.
The Sword field is located in the western Santa Barbara Channel ten
miles west of Point Conception and five miles south of Point Arguello's field
Platform Hermosa. Water depths range from 1000 feet to 1800 feet in the area
of the field. It is anticipated that the oil and gas produced from the Sword
Field will likely be processed at the existing Gaviota consolidated facility
and the oil would then be transported out of Santa Barbara County in the All
American Pipeline. Access to the Gaviota plant is through Platform Hermosa
and the existing Point Arguello Pipeline system. A pipeline proposed to be
laid from a platform located in the northern area of the Sword field to
Platform Hermosa would be approximately five miles in length. Our share of
the estimated capital costs to develop the Sword field is approximately $19
million.
As a result of the Norton case, the Sword Unit leases are held under
directed suspensions of operations with no specified end date. An updated
Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed.
Rocky Point Unit. Delta, owns an 11.11% interest in OCS Block 451
(E/2) and 100% interest in OCS Block 452 and 453, which leases comprise the
undeveloped Rocky Point Unit. On November 2, 2000 we entered into an
agreement with all of the interest owners of Point Arguello for the
development of Rocky Point and agreed, among other things, that Arguello,
Inc. would become the operator of Rocky Point. Six test wells have been
drilled on these leases from mobile drilling units. Five were successful and
one was a dry hole. OCS-P 0451 #1, drilled in 1982, was the discovery well
for the Rocky Point Field. Five delineation wells were drilled on the Unit
between 1982 and 1984. Rates up to 1,500 Bbls of oil per day were tested from
the Monterey formation. Rates up to 3,500 Bbls of oil per day were tested
from the lower Sisquoc formation which overlies the Monterey. Oil gravities
at Rocky Point range from 24 degrees to 31 degrees API.
Development of the Rocky Point Unit will be accomplished through
extended-reach drilling from the platforms located within the adjacent Point
Arguello Unit (see below). In 1987 an extended-reach well was successfully
drilled to the southwestern edge of the Rocky Point field from Platform
Hermosa located in the Point Arguello Unit. Since that time the technology of
extended-reach drilling has dramatically advanced. The entire Rocky Point
field is now within drilling distance from the Point Arguello Unit platforms.
As a result of the Norton case, the Rocky Point Unit leases are held
under directed suspensions of operations with no specified end date. The Unit
operator has prepared and timely submitted a Project Description for the
development program to the MMS as the first milestone in the Schedule of
Activities for the Unit. The operator, under the auspices of the MMS, has
also made a presentation of the Project to the affected Federal, state and
local agencies. On May 18, 2001 a revised Development and Production Plan and
supporting information was submitted to the MMS and distributed to the CCC and
the Office of the California Governor. The revised Development and Production
Plan calls for development of the Rocky Point Unit using extended reach
drilling from the existing Point Arguello platforms, and is deemed to be in
final form as the MMS has acknowledged that all regulatory requirements
25
necessary for such a Plan have been addressed. Under law, the CCC is
typically required to make a determination as to whether or not the Plan is
"consistent" with California's Coastal Plan within three months of submission,
with a maximum of three months' extension (a total of six months). By
correspondence dated August 7, 2001, however, the Unit operator requested that
the CCC suspend the consistency review for the revised Development and
Production Plan since the MMS had temporarily stopped work on the processing
of the plan as the result of the court decision in the Norton. See
"Management's Discussion and Analysis or Plan of Operation-Offshore
Undeveloped Properties".
On January 9, 2002, we filed a lawsuit against the U.S. government
along with several other companies alleging that the government breached the
terms of some of our undeveloped, offshore California properties. See "Legal
Proceedings."
Offshore Producing Properties:
-----------------------------
Point Arugello Unit. Whiting holds, as our nominee, the equivalentotherwise could involve payment 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.
In layman's terms, the term "net operating interest" is defined in our
agreement with Whiting as being the positive or negative cash flow resultingpremium over prevailing market prices 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 attributableshareholders for their common stock.
Risks Related to the
interest. Within this unit are three producing platforms (Hidalgo, Harvest
and Hermosa) which are operated by Arguello, Inc., a subsidiary of Plains
Petroleum. In an agreement between Whiting and us (see Form 8-K dated June 9,
1999) Whiting agreed to retain all of the abandonment costs associated with
our interest in the Point Arguello Unit and the related facilities.
We anticipate that we will drill one to four developmental wells on
the Point Arguello Unit during fiscal 2003. Each well will cost
approximately $2.8 million ($170,000 to our interest). We anticipate the
costs to be paid through current operations or additional financing.
26
- ---------------
map page
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27
(c) Production.
During the years ended June 30, 2002 and 2001 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
-------------------------------
Unproved Undeveloped Offshore California Properties
---------------------------------------------------
We acquired many of our offshore properties (including our
interest in Amber) in a series of transactions from 1992 to the present.
These properties are carried at our cost bases and have been subject to an
impairment review on an annual basis.
These properties will be expensive to develop and produce and
have been subject to significant regulatory restrictions and delays.
Substantial quantities of hydrocarbons are believed to exist based on
estimates reported to us by the operator of the properties and the U.S.
government's Mineral Management Services. The classification of these
properties depends on many assumptions relating to commodity prices,
development costs and timetables. We annually consider impairment of
properties assuming that properties will be developed. Based on the range of
possible development and production scenarios using current prices and costs,
we have concluded that the cost bases of our offshore properties are not
impaired at this time. There are no assurances, however, that when and if
development occurs, we will recover the value of our investment in such
properties.
Other Undeveloped Properties
----------------------------
Other undeveloped properties are carried at historical cost and
consist of the several onshore properties. These properties are carried at
our cost bases and have been subject to an impairment review on an annual
basis. There are no proven reserves associated with these properties. Based
on our continued interest in these properties and the possibility for future
development, we have concluded that the cost bases of these other undeveloped
properties are not impaired at this time. There are no assurances, however,
that when and if development occurs, we will recover the value of our
investments in such properties.
Onshore Producing Properties
----------------------------
We annually compare our historical cost basis of each
developed 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
28
impairment exists and is measured by the excess of the carrying value over
the estimated fair value of the asset.
We had an impairment provision attributed to producing
properties during the year ended June 30, 2002, of $878,000 and during the
year ended June 30, 2001 of $174,000.
Any impairment provisions recognized for developed and
undeveloped properties are permanent and may not be restored in the future.
The following table sets forth our average sales prices and
average production costs during the periods indicated:
Year Ended Year Ended Year Ended
June 30, June 30, June 30,
2002 2001 2000
---- ---- ----
Onshore Offshore Onshore Offshore Onshore Offshore
------- -------- ------- -------- ------- --------
Average sales price:
Net of forward contract sales
Oil (per barrel) $22.22 $14.36 $27.10 $18.49 $25.95 $11.54
Natural Gas (per Mcf) $ 2.75 $ - $ 6.27 - $ 2.62 -
Gross of forward contract sales
Oil (per barrel) $22.32 $14.45 $27.30 $22.53 $25.95 $21.14
Natural Gas (per Mcf) $ 2.75 $ - $ 6.27 - $ 2.62 -
Production costs
(per Bbl equivalent) $ 5.68 $11.64 $ 3.88 $12.65 $ 4.94 $11.02
(d) Productive Wells and Acreage.
The table below shows, as of June 30, 2002, 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 by Amber. 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
Gross (2) Net (3) Gross (2) Net (3) Gross (2) Net (3)
--------- ------- --------- ------- --------- -------
North Dakota 0 0 0 0 5,120 1,344
New Mexico 8 1.2 24 7.2 6,000 2,115
Texas 37 21.48 113 31.4 880 656
Colorado 6 4.2 5 4.00 4,480 1,600
Oklahoma 3 .93 4 1.57
California:
Onshore 10 .558 8 .664 720 49
Offshore 38 2.30 0 0 11,042 669
Wyoming 0 0 2 .634 1,280 811
29
Nebraska 2 .0625 0 0 160 10
Michigan 1 .0096 0 0 80 1
Mississippi 5 .413 5 1.01 400 57
Illinois 12 1.8 0 0 480 72
Alabama 0 0 51 49.2 4,080 3,916
Pennsylvania 0 0 143 89.29 5,720 3,577
Louisiana 12 7.14 3 1.32 600 388
Montana 12 3.7 0 0 480 148
Kansas 1 .048 0 0 40 2
--- ----- --- ------ ------ ------
108 27.26 358 186.27 41,562 15,360
______________
(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
700 gross wells (4.6 net) located primarily in Texas which are owned
by our subsidiary, Piper Petroleum Company.
(e) Undeveloped Acreage.
At June 30, 2002, we held undeveloped acreage by state as set forth
below:
Undeveloped Acres (1) (2)
-------------------------
Location Gross Net
- -------- ----- ---
South Dakota 58,400 29,200
California, offshore(3) 64,905 15,837
California, onshore 640 96
Colorado 6,060 4,554
Wyoming 960 768
Alabama 420 406
Texas 8,923 3,265
------- ------
Total 140,308 54,126
_______________
(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.
30
(2) Includes acreage owned by Amber.
(3) Consists of Federal leases offshore California near Santa Barbara.
(f) Drilling Activity.
During the years indicated, we drilled or participated in the
drilling of the following productive and nonproductive exploratory and
development wells:
Year Ended Year Ended Year Ended
June 30,2002 June 30, 2001 June 30, 2000
Gross Net Gross Net Gross Net
------------ ------------- -------------
Exploratory Wells(1):
Productive:
Oil 0 .00 0 .00 0 .00
Gas 0 .00 0 .00 0 .00
Nonproductive 5 2.70 6 2.24 0 .00
- ---- - ---- - ---
Total 5 2.70 6 2.24 0 .00
Development Wells(1):
Productive:
Oil 4 .242 3 .18 3 .18
Gas 6 .491 7 .37 2 .25
Nonproductive 0 .00 0 .00 0 .00
-- ---- -- ---- - ---
Total 10 .733 10 .55 5 .43
Total Wells(1):
Productive:
Oil 4 .242 3 .18 3 .18
Gas 6 2.700 7 .37 2 .25
Nonproductive 5 .491 6 2.24 0 .00
-- ----- -- ---- - ---
Total Wells 15 3.433 16 2.79 5 .43
________________
(1) Does not include wells in which theOur Company had only a royalty
interest.
(g) Present Drilling Activity.
We plan to participate in the drilling of approximately 20 new wells
before the end of fiscal 2003.
Certain Risks
Prospective investors should consider carefully, in addition to the
other information in this Annual Report, the following:
31
1. We have substantial debt obligations, and shortages of funding could hurt our future operations.
As the result of debt obligations that we have incurred in connection with purchases of oil and gas properties, we are at times obligated to make substantial monthly payments to our lenders on loans whichthat encumber our oil and gas properties and our production revenue. At the present timeAs of June 30, 2004, we are almost
totally dependent upon the revenuesowed Bank of Oklahoma, U.S. Bank and Hibernia Bank, collectively, $69.4 million, which was all that we receive fromwere permitted to borrow under our oil and gas
properties to service the debt.existing credit facility. In the event that oil and gas prices and/or production rates drop to a level such that we are unable to pay the minimum principal and interest payments that are required by our debt agreements, it
is likely that we would losebe in default under our interest in some or all of our properties.credit facility. In addition, our level of oil and gas activities, including exploration and development of existing properties, and additional property acquisitions, will be significantly dependent on our ability to successfully concludecomplete funding transactions.
2. A default under our credit agreement could cause us to lose our properties.
In connection with our acquisition of Castle's properties on May 31,
2002, we entered into a
Our credit facility with Bank of Oklahoma, U.S. Bank and Local
OklahomaHibernia Bank which allows us to borrow, repay and reborrow amounts.re-borrow amounts, up to a maximum amount of $100 million. In order to obtain this facility, we granted 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. Under the terms of our credit agreement, the oil and gas properties mortgaged must represent not less than 80% of the engineered value of our oil and gas properties as determined by the Bank of Oklahoma using its own pricing parameters, exclusive of the
properties that are mortgaged to Kaiser-Francis under a separate lending
arrangement. parameters.
Our borrowing base, which determines the amounts that we are allowed to borrow or have outstanding under our credit facility, was initially
determined to be $20$69.4 million at the time we entered into our credit agreement.as of June 30, 2004. Subsequent determinations of our borrowing base will be made by the lending banks at least semi-annually on October 1 and April 1 of each year beginning
October 1, 2002 or as unscheduled redeterminations. In connection with each determination of our borrowing base, the banks will also redetermine the amount of our monthly commitment reduction. TheWe do not currently have any monthly commitment reduction was $260,000.00 beginningobligation as a result of July 1, 2002our most recent redetermination, and we will continue at that amount
until the amount of thenot have any monthly commitment reduction obligation until it is redetermined.redetermined by our banks. Our borrowing base and the revolving commitment of the banks to lend money under the credit agreement must be reduced as of the first day of each month by an amount determined by the banks under our credit agreement. The amount of the borrowing base must also be reduced from time to time by the amount of any prepayment that results from our sale of oil and gas properties. If, as a result of any such monthly commitment reduction or reduction in the amount of our borrowing base, the total amount of our outstanding debt ever
exceedswere to exceed the amount of the revolving commitment then in effect, then, within 30 days after we are notified by the Bank of Oklahoma, we mustwould be required to make a mandatory prepayment of principal that is sufficient to causereduce our total outstanding indebtedness toso that it would not exceed our borrowing base.
32
30 requisite day30-day period, we would be in default of our obligations under our credit agreement.
For so long as the revolving commitment is in existence or any amount is owed under any of the loan documents, we will also be required to comply with
a substantial number of 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. Upon occurrence ofIf an event of default occurs and continues after the expiration of any cure period that is provided for in our credit agreement, the entire principal amount due under the notes,loan documents, all accrued interest and any other liabilities that we might have to the lending banks under the loan documents will all become immediately due and payable, all without notice and without
presentment, demand, protest, notice of protest or dishonor or any other
notice of default of any kind, and we will not be permitted to service our
obligations under our loan agreement with Kaiser-Francis Oil Company from
proceeds of the collateral securing the loan under our credit agreement
including, but not limited to, oil and gas properties or any related operating
fees.kind. The foregoing information is provided to alert investorsreaders 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. Complete
copies of our credit agreement and other loan documents are filed as an
exhibit to our Report on Form 8-K dated May 24, 2002.
3. We have a history of losses and we may not achieve profitability.
We have incurred substantial losses from our operations over the past
several years except fiscal 2001, and at June 30, 2002 we had an accumulated
deficit of $28,853,000. During the fiscal year ended June 30, 2002, we had
total revenue of $8,210,000, operating expenses of $13,251,000 and a net loss
for the year of $6,253,000. During fiscal 2001 we had total revenue of
$12,877,000, operating expenses of $11,199,000 and had net income of $345,000.
During the year ended June 30, 2000, we had total revenue of $3,576,000,
operating expenses of $5,655,000 and a net loss for fiscal 2000 of $3,367,000.
4. The substantial cost to develop certain of our offshore California properties could result in a reduction inof our interest in these properties or penalize us.
cause us to incur penalties.
Certain of our offshore California undeveloped properties, in which we have ownership interests ranging from 2.49% to 75%, 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 $10.8 million. The cost to develop these properties will be very 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 billion. Our share of such
33
5. The development of the offshore units could be delayed or halted.
The California offshore federal units have been formally approved and are
regulated by the Minerals Management Service of the federal government
("MMS"). The MMS initiated the California Offshore Oil and Gas Energy
Resources(COOGER) study at the request of the local regulatory agencies of the
affected Tri-Counties. The COOGER study was completedestimates discussed above may differ significantly from actual results.
4. If we fail to drill in January of 2000 and
is intended to present a long-term regional perspective of potential onshore
constraints that should be considered when developing existing undeveloped
offshore leases. The "worst" case scenario under the COOGER study is that no
new development of existing offshore leases would occur. If this scenario
were ultimately to be adopted by governmental decision makers and the industry
as the proper course of action for development, our offshore California
properties would in all likelihood have little or no value. Under those
circumstances we would seek to cause the Federal government to reimburse us
for all money spent by us and our predecessors for leasing and other costs
and/or for the value of the oil and gas reserves found on the leases through
our exploration activities and those of our predecessors. On June 22, 2001,
in litigation relating to the development of these properties brought by the
State of California, a Federal Court ordered the MMS to set aside its approval
of the suspensions of our offshore leases that were granted while the COOGER
Study was being completed, and to direct suspensions, including all milestone
activities, for a time sufficient for the MMS to provide the State of
Californiaaccordance with a consistency determination under federal law. On July 2,
2001 these milestones were suspended by the MMS.
In a separate action, 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 materially breached the terms of our existing agreements, we could lose some of our properties in Washington County, Colorado.
We have entered into agreements, which require us to fulfill certain drilling obligations. In particular, we have entered into an agreement with Edward Mike Davis and entities controlled by him (“Davis”) which requires us to drill wells on not less than ten prospects during every twelve month period in our area of mutual interest in Washington County, Colorado, and as to each successful prospect well, to continuously drill additional wells to fully develop each prospect as a result of such drilling with the leasesgoal of establishing ten-acre spacing for each such oil discovery. Our agreement with Davis provides that if at any time we fail, but for reasons of acts of God or lack of availability of a drilling rig, to honor the drilling program, we are to reassign to Davis all lease acreage in our area of mutual interest not held by production, but we are to have no other liability to Davis or any other party for our offshore California properties. Our suit seeks compensation
for the lease bonuses and rentals paidfailure to drill. We have agreed to drill all wells to the Federal Government, exploration
costs, and related expenses. The ultimate outcome and effectsbase of the litigation pertainingJ-Sand Formation or the top of the Skull Creek Formation. Our past J-Sand results have initially caused us to believe that the eastern half of our Offshore California properties are not certain atacreage position in our area of mutual interest will be productive in the present time.
34
6. We will have to incur substantial costs in order to develop our
reserves and weshallow Niobrara formation, but may not be ableproductive in the deeper J-Sand. Although we currently intend to secure funding.
Relativecontinue to drill to the J-Sand in that area because in many locations the formation may be economically viable and continued drilling to that depth will provide us with additional information which may prove to be beneficial to us in the future, if we ultimately determine that it is not worthwhile to drill to the depth of the J-Sand or otherwise fail to drill to that depth in accordance with the terms of our financial resources,agreement, we may be required to assign acreage to Davis. Davis has notified us that he does not believe that we are fulfilling all of our obligations under this and other agreements with him, but he has not declared us to be in default. We intend to fully comply with all of our obligations under these agreements.
5. 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 recently acquired a fifty percent interest in a small drilling company and a fifty percent interest in a small trucking company that are both currently managed by Edward Mike Davis. Although Mr. Davis and his affiliated entities are not currently deemed to be affiliates of Delta, we have significant undevelopedrecently acquired several properties in additionfrom Mr. Davis and entities that are controlled by him. We also currently have areas of mutual interest and joint ventures with Mr. Davis and his related entities, and we have substantial drilling commitments that are related to those in offshore California discussed aboveventures. We believe that will require substantial costs to develop. During the year ended June 30,
2001, we participatedour ownership interest in the drilling and completion or recompletioncompany will allow us to have priority access to at least two large drilling rigs. The initial purpose of seven
gas wells and six non-productive wells. During the year ended June 30, 2002,
we participatedour investment in the trucking company is to allow these drilling rigs to be moved to new drilling locations as necessary. We are also attempting to establish arrangements with others to assure adequate availability of four offshore wells at a cost to us of
approximately $680,000,certain other necessary drilling equipment and 11 (6 successful and 5 unsuccessful) onshore wells
at a cost to us of approximately $1,140,000. The cost of these wells either
has been orsupplies on satisfactory terms, but there can be no assurance that we will be paid outable to do so. Accordingly, there can be no assurance that we will not experience shortages of, our cash flow.
We drilled 6 successfulor material price increases in, drilling equipment and 5 unsuccessful wells onshoresupplies, including drill pipe, in the future. Any such shortages could delay and drilled 4
successful offshore wells in fiscal 2002. Our level of future oil and gas
activity, including exploration and development and property acquisitions,
will be to a significant extent dependent uponadversely affect our ability to successfully
conclude funding transactions.
We expect to continue incurring costs to acquire, explore and develop oil
and gas properties, and management predicts that these costs (together with
general and administrative expenses) will be in excess of funds available from
revenues from properties owned by us and existing cash on hand. It is
anticipated that the source of funds to carry out such exploration and
development will come from a combination ofmeet our sale of working interests in
oil and gas leases, production revenues, sales of our securities, and funds
from any funding transactions in which we might engage.
7. Current and future governmental regulations will affect our operations.
Our activities are subject to extensive federal, state, and local laws
and regulations controlling not only the exploration for and sale of oil, but
also the possible effects of such activities on the environment. Present as
well as future legislation and regulations could cause additional
expenditures, restrictions and delays in our business, the extent of which
cannot be predicted, and may require us to cease operations in some
circumstances. In addition, the production and sale of oil and gas are
subject to various governmental controls. Because federal energy policies are
still uncertain and are subject to constant revisions, no prediction can be
made as to the ultimate effect on us of such governmental policies and
controls.
8. We hold only a minority interest in certain properties and, therefore,
generally will not control the timing of development.
We currently do not operate approximately 42% of the wells in which we
own an interest and we are dependent upon the operators of the wells that we
do not operate to make most decisions concerning such things as whether or not
to drill additional wells, how much production to take from such wells, or
whether or not to cease operation of certain wells. Further, we do not act as
operator of and, with the exception of Rocky Point, we do not own a
controlling interest in any of our offshore California properties. While we,
as a working interest owner, may have some voice in the decisions concerning
the wells, we are not the primary decision maker concerning them. As a
result, we will generally not control the timing of either the development of
35
most of these non-operated properties or the expenditures for their
development. Because we are not in control of the non-operated wells, we may
not be able to cause wells to be drilled even though we may have the funds
with which to pay our proportionate share of the expenses of such drilling or, alternatively, we may incur development expenses at a time when funds are
not available to us. We hold only a minority interest in and do not operate
many of our properties and, therefore, generally will not control the timing
of development on these properties.
9. We are subject to the general risks inherent in oil and gas exploration
and operations.
Our business is subject to risks inherent in the exploration, development
and operation of oil and gas properties, including but not limited to
environmental damage, personal injury, and other occurrences that could result
in our incurring substantial losses and liabilities to third parties. In our
own activities, we purchase insurance against risks customarily insured
against by others conducting similar activities. Nevertheless, we are not
insured against all losses or liabilities which may arise from all hazards
because such insurance is not available at economic rates, because the
operator has not purchased such insurance, or because of other factors. Any
uninsured loss could have a material adverse effect on us.
10.commitments.
6. 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 for which we act as a producer. We are therefore dependent upon our ability to sell oil and gas at the prevailing well headwellhead market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable.
11.
7. Our business is not diversified.
Since all of our resources are devoted to one industry, purchasersowners of our common stock will beare risking essentially their entire investment in a company that is focused only on oil and gas activities.
12. 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 present
shareholders will be able to elect all of our directors, and holders of the
common stock offered by this prospectus will not be able to elect a
representative to our Board of Directors. See "DESCRIPTION OF COMMON STOCK."
13. We do not expect to pay dividends.
There can be no assurance that our proposed operations will result in
sufficient revenues to enable us to operate at profitable levels or to
generate a positive cash flow, and our current loan documents prevent us from
paying dividends. For the foreseeable future, it is anticipated that any
earnings which may be generated from our operations will be used to finance
our growth and that dividends will not be paid to holders of common stock.
See "DESCRIPTION OF COMMON STOCK."
36
14.
8. We depend on key personnel.
We currently have only threefour employees that serve in management roles, and the loss of any one of them could severely harm our business. In particular, Roger A. Parker isand John R. Wallace are responsible for the operation of our oil and gas business, Aleron H. Larson, Jr. is responsible for other business and corporate matters, and Kevin K. Nanke is our chief financial officer. We do not have key man insurance on the lives of any of these individuals.
15.
Risks Related to Our Business
1. 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; the foreign supply of oil and natural gas; the price of oil and gas imports; and overall U.S. and foreign economic conditions.
We alloware not able to predict future natural gas or oil 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 key personneloil and gas properties. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to purchase working interestscontracts based on spot market prices, not long-term fixed price contracts.
In an attempt to reduce price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. Such transactions may not reduce the same
terms as us.
Inrisk or minimize the pasteffect of any decline in natural gas or oil prices. 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.
2. If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, we have occasionally allowed our key employeesmay be required to purchase
working interests intake write downs.
There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. A write down 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 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 oil and gas 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 capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future net revenues, we must write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but it will reduce our earnings and stockholders’ equity.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas 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 developmental in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires 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.
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 write down 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 book values associated with our oil and gas properties.
3. The marketability of our production depends mostly upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities.
The marketability of our production depends upon the availability, operation and capacity of gas gathering systems, pipelines and processing facilities. 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. United States federal, state and foreign regulation of oil and gas production and transportation, 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.
4. We may not receive payment for a portion of our future production.
Our revenues are derived principally from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. We generally 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.
5. 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, particularly with respect to our offshore California properties. We continue to examine the following alternative sources of capital:
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.
6. 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 ranges from $60 to $80 million for fiscal 2005. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program. In addition, if our borrowing base under our credit facility is re-determined to a lower amount, this could adversely affect our ability to fund our planned capital expenditures. 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 expenditures requirements.
7. We may not be able to replace production with new reserves.
Our reserves will decline 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 and developing existing proved reserves, which we may not be successful in doing.
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. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, the review will not permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not be able to acquire properties at acceptable prices because the competition for producing oil and gas properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us.
8. 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. Currently, 42% of our proved reserves are undeveloped and have a book value of $86.7 million. The cost to develop these reserves is estimated to be approximately $67 million. In addition, we have $49 million of capitalized costs on properties with no proved reserves. 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.
9. You should not place undue reliance on reserve information because it is only an estimate.
Certain of our Exchange Act reports filed with the Commission contain estimates of oil and gas reserves, and the future net cash flows attributable to those reserves, prepared by Ralph E. Davis Associates, Inc. and Mannon & Associates (together, the “Engineers”), our independent petroleum and geological engineers. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the Engineers’ 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 and oil and gas prices. 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 the assumptions and estimates in our Exchange Act reports filed with the Commission, certain of which are incorporated by reference into this report. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same termsavailable data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in certain of the Exchange Act reports were prepared by the Engineers in accordance with the rules of the Commission, and are not intended to represent the fair market value of such reserves.
10. Our operations are subject to numerous risks of oil and gas drilling and production activities.
Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be found. Oil and gas drilling and production activities may be shortened, delayed or canceled as usa result of a variety of factors, many of which are beyond our control. These factors include:
The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services.
New wells that we drill may not be productive and we may not recover all or any portion of our investment. The cost of drilling and completing wells is often uncertain. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs to providerecoup drilling costs.
11. Our industry experiences numerous operating risks.
The exploration, development and operation of oil and gas properties also involve a meaningful incentivevariety of operating risks including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. If any of these industry-operating risks occur, we could have substantial losses. Substantial losses may be caused by 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.
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 the changes in the insurance markets attributable to those attacks may make some types of insurance more difficult to obtain. We may be unable to secure the level and types of insurance we would otherwise have secured prior to the employeesterrorist attacks. We may not be able to maintain insurance in the future at rates we consider reasonable. The occurrence of a significant event, not fully insured or indemnified against, could materially and adversely affect our financial condition and operations.
12. 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 align their
ownincreased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our business.
13. We may suffer losses or incur liability for events that we or the operator of a property has chosen not to obtain insurance.
Our operations are subject to hazards and risks inherent in producing and transporting oil and natural gas, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal financial interests with ours in making decisions affecting theinjury claims and other damage to our properties and others. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, we believe any operators of properties in which we have or may acquire an interest will maintain similar insurance coverage. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operation.
14. Hedging transactions may limit our potential gains.
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, such as commodity swap agreements, forward sale contracts, commodity futures, options and similar agreements, with respect to a portion of our expected production. 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:
15. We may incur substantial costs to comply with the various U.S. federal, state and local environmental 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. 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:
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.
16. We are exposed to additional risks through our drilling business.
We own a fifty percent interest in a drilling business. Our operations through that entity will subject us 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. Although we believe that our drilling business is adequately insured for public liability and property damage to others and injury or death to persons in accordance with industry standards with respect to its operations, no assurance can be given that such insurance 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 our 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 our 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.
Oil and Gas Primary Areas
The following discussion describes our primary oil and gas areas. We believe these areas will have a significant contribution to our daily production and future reserve growth.
Gulf Coast Region – South Texas and South Louisiana Basins
The Gulf Coast Region comprises approximately 55.8% of our estimated proved reserves at June 30, 2004. We did not drill and complete a significant number of wells in this region because a majority of the drilling prospect inventory was acquired through the Alpine Resources acquisition, which did not close until June 29, 2004.
In South Texas, our primary activities will be an interest.
Specifically,extensive drilling program to continue the development of two large value fields (Newton Field in Newton County and South Angleton Field in Brazoria County), which were previously owned by Alpine Resources. We will also have additional development in other areas of South Texas which includes activity on February 12, 2001,properties we own in Polk County, Liberty County, Arkansas County and McMullen County. Working interest ownership is between 50% and 100% and operated by us.
In Louisiana, we plan additional development on properties in Point Coupee and Iberville Parishes. The majority of these properties are operated and owned 100% by us.
Rocky Mountain Region – Denver Julesburg, Wind River and Piceance Basins
The Denver Julesburg and Piceance Basins of Colorado and the Wind River Basin of Wyoming account for a major portion our Boardcurrent and projected exploration and development activities. Approximately 7.3% of Directors permitted
Aleron H. Larson, Jr., our Chairman, Roger A. Parker,estimated proved reserves are located in these areas at June 30, 2004. We own and operate interests in 40 producing wells in these basins and the net daily production was approximately 6,000 Mcfge (thousand cubic feet of gas equivalent) as of June 30, 2004. We have approximately 280,000 net acres of developed and undeveloped acres in these basins.
In the Denver Julesburg Basin, we have already identified 135 locations to be drilled and we are also continuing our President, and
Kevin K. Nanke,3D seismic program, with the intent of collecting seismic on all 260,000 acres we own. Due to a high degree of success in predicting wells resulting from 3D seismic surveys, we plan to concentrate a majority of our CFO, to purchase2005 capital expense drilling in this area. We own 100% of the working interests of 5% each for Messrs.
Larson and Parker and 2-1/2% for Mr. Nankeinterest in our Cedar Stateacreage in the Denver Julesburg Basin.
The Piceance Basin was not a focal point of development in 2004, but should see extensive drilling in 2005 as a result of increased well productivity, lower completion costs and higher natural gas prices. We own and operate a majority of our interests in the Piceance Basin. Our total acreage position is approximately 10,600 net acres that may ultimately allow for the drilling of up to 700 wells.
In the Wind River Basin, we drilled 18 wells and as of June 30, 2004 nine have been completed and the other nine are in various stages of being completed. The majority of the drilling was in the Fuller Reservoir Field. The Fuller Reservoir Field will be a focus of development in 2005. We operate the wells and own a significant portion of the working interest (75% on average). In addition, we will begin drilling activity on our Howard Ranch properties.
Offshore Federal Waters: Santa Barbara, California Area
Unproved Undeveloped Offshore California Properties
We have ownership interests ranging from 2.49% to 75% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $10.8 million and $10.2 million at June 30, 2004 and 2003, respectively. These non-operated property interests are located in Eddy County, New Mexicoproximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of our investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.
Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, we believe the fair values of our Ponderosa Prospect consistingproperty interests are in excess of approximately 52,000 gross acrestheir carrying values at June 30, 2004 and that no impairment in Harding and Butte Counties, South Dakota
held for exploration. These officers were authorizedthe carrying values has occurred. Pursuant to purchase these
interests on or before March 1, 2001 at a purchase price equivalentruling in California v. Norton, later affirmed by the 9th Circuit Court of Appeals, the U.S. Government is required to make a consistency determination relating to the amounts paid by us for each property as reflected upon1999 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 books by delivering
to us shares of Delta common stock at the February 12, 2001 closing price of
$5.125 per share. Messrs. Larson and Parker each delivered 31,310 shares and
Mr. Nanke delivered 15,655 shares in exchange for their 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, Delta 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 the Company’s Offshore California properties. AlsoSee “Legal Proceedings.”
Rocky Point Unit
We own an 11.11% interest in the east half of OCS Block 451 and a 100% interest in OCS Blocks 452 and 453, which leases comprise the undeveloped 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. Six test wells have been drilled on February 12, 2001,these leases from mobile drilling units. Five were successful and one was a dry hole. OCS-P 0451 #1, drilled in 1982, was the discovery well for the Rocky Point Field. Five delineation wells were drilled on the Unit between 1982 and 1984. Rates up to 1,500 Bbls of oil per day were tested from the Monterey formation. Rates up to 3,500 Bbls of oil per day were tested from the lower Sisquoc formation which overlies the Monterey. Oil gravities at Rocky Point range from 24 degrees to 31 degrees API.
Development of the Rocky Point Unit will be accomplished through extended-reach drilling from the platforms located within the adjacent Point Arguello Unit (see below). In 1987 an extended-reach well was successfully drilled to the southwestern edge of the Rocky Point field from Platform Hermosa located in the Point Arguello Unit. Since that time the technology of extended-reach drilling has dramatically advanced. The entire Rocky Point field is now within drilling distance from the Point Arguello Unit platforms.
We are currently drilling our first development well on the Rocky Point Unit. The well is being drilled to a total measured depth of 18,000 feet and we grantedshould have results sometime in September. By virtue of various agreements between owners of the Point Arguello Unit platforms and the Rocky Point Unit leasehold, Delta will have approximately a 6.25% working interest in the development of the east half of OCS Block 451.
Offshore Producing Properties
Point Arguello Unit. Whiting Petroleum Corporation holds, as our nominee, the equivalent of a 6.07% working interest in form of a financial arrangement termed a “net operating interest” in the Point Arguello Unit and related facilities. In layman’s terms, the term “net operating interest” is defined in our agreement with Whiting as being the positive or negative cash flow resulting to Messrs. Larsonthe interest from a seven step calculation which in summary subtracts royalties, operating expenses, severance taxes, production taxes and Parkerad valorem taxes, capital expenditures, unit fees and Mr. Nankecertain other expenses from the rightoil and gas sales and certain other revenues that are attributable to participatethe interest. Within this unit are three producing platforms (Hidalgo, Harvest and Hermosa) which are operated by Arguello, Inc., a subsidiary of Plains Resources Corporation. In an agreement between Whiting and us (see Form 8-K dated June 9, 1999), Whiting agreed to retain all of the abandonment costs associated with our interest in the Point Arguello Unit and the related facilities.
Office Facilities
Our offices are located at 475 Seventeenth Street, Suite 1400, Denver, Colorado 80202. We lease approximately 19,000 square feet of office space for approximately $25,000 per month and the lease will expire in September, 2008.
Production
During the years ended June 30, 2004, 2003 and 2002 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
Unproved Undeveloped Offshore California Properties
We acquired many of our offshore properties (including our interest in Amber) in a series of transactions from 1992 to the present. These properties are carried at our cost basis, $10.8 million, and have been subject to an impairment review on an annual basis.
These properties will be expensive to develop and produce and have been subject to significant regulatory restrictions and delays. Substantial quantities of hydrocarbons are believed to exist based on estimates reported to us by the operator of the properties and the U.S. government’s Mineral Management Services. The classification of these properties depends on many assumptions relating to commodity prices, development costs and timetables. We annually consider impairment of properties assuming that properties will be developed. Based on the range of possible development and production scenarios using current prices and costs, we have concluded that the cost bases of our offshore properties are not impaired at this time. There are no assurances, however, that when and if development occurs, we will recover the value of our investment in such properties.
Unproved Onshore Properties
Unproved onshore properties are carried at our cost basis, $38.9 million, and have been subject to an impairment review on an annual basis. There are no proven reserves associated with these properties. Based on our continued interest in these properties and the possibility for future development, we have concluded that the cost basis of these other undeveloped properties are not impaired at this time. There are no assurances, however, that when and if development occurs, we will recover the value of our investments in such properties.
Onshore Producing and Undeveloped Properties
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 an impairment provision attributed to producing properties during the year ended June 30, 2002 of $878,000 and none during the years ended June 30, 2004 and 2003.
Any impairment provisions recognized for developed and undeveloped properties are permanent and may not be restored in the future periods.
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, 2004, 2003 and 2002.
Year Ended June 30, 2004 | Year Ended June 30, 2003 (1) | Year Ended June 30, 2002 (1) | ||||||||||||||||||
| Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||||
Production volume - continuing operations: | ||||||||||||||||||||
Oil (MBbls) | 552 | 180 | 217 | 227 | 86 | 262 | ||||||||||||||
Natural Gas (Mmcf) | 2,842 | — | 2,492 | — | 870 | — | ||||||||||||||
Net average daily production-continuing operations: | ||||||||||||||||||||
Oil (Bbl) | 1,512 | 493 | 595 | 621 | 236 | 718 | ||||||||||||||
Natural Gas (Mcf) | 7,786 | — | 6,827 | — | 2,384 | — | ||||||||||||||
Average sales price: | ||||||||||||||||||||
Oil (per barrel) | $ | 33.09 | $ | 22.11 | $ | 28.82 | $ | 20.21 | $ | 22.22 | $ | 14.36 | ||||||||
Natural Gas (per Mcf) | $ | 5.27 | $ | — | $ | 4.71 | $ | — | $ | 2.75 | $ | — | ||||||||
Hedge effect (per Mcf equivalent) | $ | (.14 | ) | $ | — | $ | (.49 | ) | $ | — | $ | .03 | $ | — | ||||||
Production costs | ||||||||||||||||||||
(per Mcf equivalent) | $ | 1.06 | $ | 3.02 | $ | 1.35 | $ | 2.40 | $ | .90 | $ | 1.94 | ||||||||
| (1) | 2003 and 2002 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, 2004, 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 by Amber. 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 | 0 | 0 | 74 | 55.1 | 3,526 | 3,526 | ||||||
California: | ||||||||||||
Offshore | 38 | 2.3 | 0 | 0 | 1,200 | 134 | ||||||
Onshore | 10 | .67 | 10 | 3.84 | 1,160 | 586 | ||||||
Colorado | 21 | 17.81 | 9 | 7.54 | 3,550 | 3,508 | ||||||
Kansas | 29 | 26.44 | 1 | .625 | 840 | 808 | ||||||
Louisiana | 25 | 13.8 | 5 | 1.45 | 5,968 | 3,737 | ||||||
Michigan | 1 | .0096 | 0 | 0 | 40 | 0 | ||||||
Mississippi | 7 | .32 | 4 | 1.0 | 1,440 | 332 | ||||||
Montana | 11 | 3.64 | 1 | .48 | 964 | 241 | ||||||
Nebraska | 1 | .0625 | 0 | 0 | 40 | 3 | ||||||
New Mexico | 12 | 1.21 | 21 | 5.38 | 9,280 | 2,574 | ||||||
North Dakota | 18 | 1.25 | 0 | 0 | 9,910 | 2,302 | ||||||
Oklahoma | 5 | 5.76 | 3 | .07 | 2,385 | 28 | ||||||
Texas (4) | 93 | 49.66 | 138 | 42.47 | 26,562 | 12,552 | ||||||
Wyoming | 1 | 1 | 16 | 5.91 | 7,200 | 720 | ||||||
| 272 | 123.93 | 282 | 123.87 | 74,065 | 31,051 | |||||||
| (1) | All of the wells classified as “oil” wells also produce various amounts of natural gas. |
| (2) | A “gross well” or “gross acre” is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned. |
| (3) | A “net well” or “net acre” is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof. |
| (4) | This does not include varying very small interests in approximately 666 gross wells (5.2 net) located primarily in Texas which are owned by our subsidiary, Piper Petroleum Company. |
Undeveloped Acreage
At June 30, 2004, we held undeveloped acreage by state as set forth below:
Undeveloped Acres (1) (2) | ||||
Location | Gross | Net | ||
California, offshore(3) | 64,905 | 15,837 | ||
Colorado | 396,988 | 300,297 | ||
Montana | 26,841 | 22,466 | ||
North Dakota | 880 | 528 | ||
Texas | 1,493 | 1,119 | ||
Washington | 239,205 | 106,629 | ||
Wyoming | 25,567 | 17,961 | ||
Total | 755,879 | 464,837 | ||
| (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. |
| (3) | Consists of Federal leases offshore California near Santa Barbara. |
Drilling Activity
During the years indicated, we drilled or participated in the drilling of the Austin State #1 well
in Eddy County, New Mexico by having them commit to us on February 12, 2001
(prior to any bore hole knowledge or information relating to the objective
zone or zones)to pay 5% each by Messrs. Larsonfollowing productive and Parkernonproductive exploratory and 2-1/2% by Mr.
Nanke ofdevelopment wells:
| Year Ended June 30, 2004 | Year Ended June 30, 2003 | Year Ended June 30, 2002 | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
Exploratory Wells (1): | ||||||||||||
Productive: | ||||||||||||
Oil | 3 | 1.40 | 0 | 0.00 | 0 | 0.00 | ||||||
Gas | 1 | .25 | 0 | 0.00 | 0 | 0.00 | ||||||
Nonproductive | 5 | 3.25 | 3 | 1.55 | 5 | 2.70 | ||||||
Total | 9 | 4.90 | 3 | 1.55 | 5 | 2.70 | ||||||
Development Wells (1): | ||||||||||||
Productive: | ||||||||||||
Oil | 3 | 2.81 | 0 | 0.00 | 4 | .24 | ||||||
Gas | 22 | 9.46 | 6 | 5.15 | 6 | 0.49 | ||||||
Nonproductive | 3 | 3.00 | 0 | 0.00 | 0 | 0.00 | ||||||
Total | 28 | 15.27 | 6 | 5.15 | 10 | .73 | ||||||
Total Wells (1): | ||||||||||||
Productive: | ||||||||||||
Oil | 6 | 4.21 | 0 | 0.00 | 4 | .242 | ||||||
Gas | 23 | 9.71 | 6 | 5.15 | 6 | 2.70 | ||||||
Nonproductive | 8 | 6.25 | 3 | 1.55 | 5 | 0.49 | ||||||
Total Wells | 37 | 20.17 | 9 | 6.70 | 15 | 3.43 | ||||||
| (1) | Does not include wells in which we had only a royalty interest. |
Present Drilling Activity
The following represents our working interest costs of drillingplanned exploration and completion or abandonment
costs, which costs may be paid in either cash or in Delta common stock at
$5.125 per share. All of these officers committed to participate in the well
under the condition that they would be assigned their respective working
interests in the well and associated spacing unit after they had been billed
and had paiddevelopment activities for the interests as required.
To the extent that key employees are permitted to purchase working
interests in wells that are successful, they will receive benefits of
ownership that might otherwise have been available to us. Conversely, to the
extent that key employees purchase working interests in wells that are
ultimately not successful, such purchases may result in personal financial
losses for our key employees that could potentially divert their attention
from our business.
37
16. The exercise of our Put Rights may dilute the interests of other
security holders.
We have entered into an arrangement with Swartz Private Equity, LLC under
which we may sell shares of our common stock to Swartz at a discount from the
then prevailing market price. The exercise of these rights may substantially
dilute the interests of other security holders.
Under the terms of our relationship with Swartz, we will issue shares to
Swartz upon exercise of our Put Rights at a price equal to the lesser of: the
market price for each share of our common stock minus $.25; or 91% of the
market price for each share of our common stock.
17. The sale of material amounts of our common stock could reduce the price
of our common stock and encourage short sales.
If and when we exercise our Put Rights and sell shares of our common
stock to Swartz, if and to the extent that Swartz sells the common stock, our
common stock price may decrease due to the additional shares in the market. If
the price of our common stock decreases, and if we decide to exercise our
right to put shares to Swartz, we must issue more shares of our common stock
for any given dollar amount invested by Swartz, subject to a designated
minimum Put price that we specify. This may encourage short sales, which could
place further downward pressure on the price of our common stock. Under the
terms of the Investment Agreement with Swartz, however, we are not obligated
to sell any of our shares to Swartz nor do we intend to sell shares to Swartz
unless it is beneficial to us.
ITEM 3. fiscal 2005.
Areas of Operations | Drilling Locations | Budget | ||
| (In millions) | ||||
Gulf Coast Region | 18 - 23 | $ 22 - $ 29 | ||
Rocky Mountain Region | 130 - 162 | $ 36 - $ 45 | ||
Offshore California | 3 - 5 | $ 2 - $ 4 | ||
Other | 0 - 5 | $ 0 - $ 2 | ||
Total | 153 - 200 | $ 60 - $ 80 | ||
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 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 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. 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 Coastal Zone
Management Act and we decide not to appeal such ruling to the Secretary of
38
Commerce, or the Secretary of Commerce either refuses to hear our appeal of
any such ruling or ultimately makes a determination adverse to us, it is
likely that some or all of these leases would become impaired and written off
at that time.
In addition, it should be noted that our pending litigation against the
United States is predicated on the ruling of the lower court in California v.
Norton. The United States has appealed the decision of the lower court to the
9th Circuit Court of Appeals. In the event that the United States is not
successful in its appeal(s) of the lower court's decision in the Norton case
and the pending litigation with us is not settled, it would be necessary for
us to reevaluate whether the leases should be considered impaired at that
time.
As the ruling in the Norton case currently stands, the United States has
been ordered to make a consistency determination under the Coastal Zone
Management Act, but the leases are still valid. If through the appellate
process the leases are found not to be valid for some reason, or if the United
States is finally ordered to make a consistency determination and either does
not do so or finds that development is inconsistent with the Coastal Zone
Management Act, it would appear that the leases would become impaired even
though we would undoubtedly proceed with our litigation. It is also possible
that other events could occur during the appellate process that would cause
the leases to become impaired, and we will continuously evaluate those factors
as they occur.
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. Our claim for lease bonuses and rentals paid by us and our predecessors is in excess of $152,000,000.$152 million. In addition, our claim for exploration costs and related expenses will also be substantial. ITEM 4. 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, and to pay expenses of litigation 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 liability aspects related to their claims. Neither motion has yet been heard by the court.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The 2001 Annual Meeting
No matter was submitted to a vote of security holders during the fourth quarter of our shareholders was held on May 30, 2002.
At the Annual Meeting the following persons, constituting the entire board
of directors, were elected as directors of the Company to serve until the next
annual meeting:
DIRECTORS AND EXECUTIVE OFFICERS.
OFFICERS
The following information with respect to DirectorsExecutive Officers and Executive
OfficersDirectors is furnished pursuant to Item 401(a) of Regulation S-K.
Name Age Positions Period of Service
- --------------------- --- ------------------------ -------------------
Aleron H. Larson, Jr. 57 Chairman of the Board, May 1987 to Present
Secretary, and a Director
Roger A. Parker 40 President, Chief May 1987 to Present
Executive Officer and
a Director
Jerrie F. Eckelberger 58 Director September 1996
to Present
James B. Wallace 73 Director November 2001 to
Present
Joseph L. Castle II 70 Director June 2002 to Present
Russell S. Lewis 47 Director June 2002 to Present
John P. Keller 63 Director June 2002 to Present
40
Kevin K. Nanke 37 Treasurer and Chief December 1999
Financial Officer to Present
Name | Age | Positions | Period of Service | |||
Roger A. Parker | 42 | President, Chief Executive Officer and a Director | May 1987 to Present | |||
Aleron H. Larson, Jr. | 59 | Chairman of the Board, Secretary and a Director | May 1987 to Present | |||
Kevin K. Nanke | 39 | Treasurer and Chief Financial Officer | December 1999 to Present | |||
John R. Wallace | 43 | Executive V.P., Exploration and Chief Operating Officer | October 2003 to Present | |||
Jerrie F. Eckelberger | 59 | Director | September 1996 to Present | |||
James B. Wallace | 74 | Director | November 2001 to Present | |||
Joseph L. Castle II | 71 | Director | June 2002 to Present | |||
Russell S. Lewis | 48 | Director | June 2002 to Present | |||
John P. Keller | 64 | Director | June 2002 to Present | |||
The following is biographical information as to the business experience of each of our current officers and directors.
Roger A. Parker has operated as an independent in the oil and gas industry individually and through public and private ventures since 1982. He was at various times, from 1982 to 1989, a Director, Executive Vice President, President and shareholder of Ampet, Inc. He has also served as the President, a Director and Chief Operating Officer of Chippewa Resources Corporation from July of 1990 through March 1993 when he resigned after a change of control. Mr. Parker also serves as President, Chief Executive Officer and Director of Amber. 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.
Aleron H. Larson, Jr., age 57, has operated as an independent in the oil and gas industry individually and through public and private ventures since 1978. Mr. Larson served as the Chairman, Secretary, CEO and a Director of Chippewa Resources Corporation, a public company then listed on the American Stock Exchange from July 1990 through March 1993 when he resigned after a change of control. Mr. Larson serves as Chairman of the Board, Secretary and Director of Amber Resources Company ("Amber"(“Amber”), a public oil and gas company which is our majority-owned subsidiary. 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.
Roger A. Parker, age 40, served as the President, a Director
Kevin K. Nanke, Treasurer and Chief OperatingFinancial Officer, of Chippewa Resources Corporation from July of 1990 through
March 1993 whenjoined Delta in April 1995. Since 1989, he resigned after a change of control. Mr. Parker also serves
as President, Chief Executive Officerhas been involved in public and Director of Amber. He also serves
as a Director and Executive Vice President of P & G Exploration, Inc., a
private oil and gas company (formerly Texco Exploration, Inc.). Mr. Parker
has also been the President, a Director and sole shareholder of Apex Operating
Company, Inc. since its inception in 1987. He has operated as an independent
inaccounting with the oil and gas industry individually and through public and private
ventures since 1982. He was at various times, from 1982 to 1989, a Director,
Executive Vice President, President and shareholder of Ampet, Inc. Heindustry. Mr. Nanke received a Bachelor of ScienceArts in Mineral Land ManagementAccounting from the University of ColoradoNorthern Iowa in 1983.1989. 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. 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 Oilregion, and Gas
Associationhas 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 Independent Producers Associationson of John B. Wallace, a Director of the Mountain States
(IPAMS).
Company.
Jerrie F. Eckelberger age 58, 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 eighteenthEighteenth Judicial District Attorney'sAttorney’s Office in Colorado. From 1975 to present, Mr. Eckelberger has practicedbeen engaged in the private practice of law in Colorado 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 acted as
President and Chief Executive Officer of 1998, Ltd., a Colorado corporation
actively engaged in the investment and development of Colorado real estate through several private companies in Colorado. Hewhich he is the
Managing Member of The Francis Companies, L.L.C., a Colorado limited liability
company, which actively invests in real estate and has been since June, 1996.
Additionally, since November, 1997, Mr. Eckelberger has served as the Managing
41
Member of the Woods at Pole Creek, a Colorado limited liability company,
specializing in real estate development.
principal.
James B. Wallace age 73, 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.
Joseph L. Castle II age 70 has been a Director of Castle Energy Corporation ("Castle"(“Castle”) since 1985. Mr. Castle is the Chairman of the Board of Directors and Chief Executive Officer of Castle, having served as Chairman from December 1985 through May 1992 and since December 20, 1993. Mr. Castle also served as President of Castle from December 1985 through December 20, 1993, when he reassumed his position as Chairman of the Board. Previously, Mr. Castle was Vice President of Philadelphia National Bank, a corporate finance partner at Butcher and Sherrerd, an investment banking firm, and a Trustee of The Reading Company. Mr. Castle has worked in the energy industry in various capacities since 1971. Mr. Castle is also a director of Comcast Corporation and Charming Shoppes, Inc. Since May of 2000, Mr. Castle has served as the Chairman of the Board of Trustees of the Diet Drug Products Liability ("Phen-Fen"(“Phen-Fen”) Settlement Trust.
Russell S. Lewis (age 47) has been a director of Castle since April 2000. From 1994 to 1999, Mr. Lewis was the Chief Executive Officer of TransCore, Inc., a company which sells and installs electronic toll collection systems. Since 1999, Mr. Lewis has been the owner and President of Lewis Capital Group, a company investing in and providing consulting services to growth-oriented companies. Since March 2000, Mr. Lewis has also been Senior Vice President of Corporate Development at VeriSign, Inc. In February of 2002, Mr. Lewis joined VeriSign full-time as Executive Vice President and General Manager of VeriSign'sVeriSign’s Global Registry Services Group, which maintains the authoritative database for all ".com", ".net"“.com,” “.net” and ".org"“.org” domain names in the Internet.
John P. Keller (age 63) has been a director of Castle since April 1997. Since 1972, Mr. Keller has served as the President of Keller Group, Inc., a privately-held corporation with subsidiaries in Ohio, Pennsylvania and Virginia. In 1993 and 1994, Mr. Keller also served as the Chairman of American Appraisal Associates, an appraisal company. Mr. Keller is also a director of A.M. Castle & Co.
Kevin K. Nanke, (age 37) Treasurer and Chief Financial Officer, joined
Delta in April 1995. 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. Mr. Nanke
is not a nominee for election as a director.
There is no family relationship among or between any of our Officers
and/or Directors.
42
Messrs. Castle, Lewis and Keller were proposed for appointment to the board by Castle Energy Corporation pursuant to the Purchase and Sale Agreement between Delta and Castle Energy Corporation which had an effective date of October 1, 2001. Messrs Castle, Lewis and Keller are also directors of Castle Energy Corporation.
As of September 7, 2004, Messrs. Castle, James B. Wallace and Eckelberger serveserved as the Incentive Plan Committee and as the Compensation CommitteeCommittee. Messrs. Lewis, Keller, Eckelberger and James B. Wallace serveserved as the Audit CommitteeCommittee; and Messrs Lewis, Castle and James B. Wallace served as the Nominating 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'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.
MARKET FOR REGISTRANT’S COMMON EQUITY, AND RELATED STOCKHOLDER MATTERS (a) AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information.
Delta'sInformation
Delta’s common stock currently trades under the symbol "DPTR"“DPTR” on NASDAQ.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, 1999 3.50 2.63
December 31, 1999 2.94 1.78
March 31, 2000 3.88 2.19
June 30, 2000 4.06 3.00
September 30, 2000 6.25 3.75
December 31, 2000 5.13 3.13
March 31, 2001 5.22 3.31
June 30, 2001 5.75 4.19
September 30, 2001 4.50 2.54
December 31, 2001 3.90 2.38
March 31, 2002 4.53 3.35
June 30, 2002 4.73 3.52
Quarter Ended | High | Low | ||||
September 30, 2002 | $ | 3.94 | $ | 1.25 | ||
December 31, 2002 | 4.10 | 3.01 | ||||
March 31, 2003 | 4.05 | 3.15 | ||||
June 30, 2003 | 5.00 | 3.25 | ||||
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 | ||||
On September 18, 20027, 2004 the closing price of the Common Stock was $3.70.
(b) $11.37.
Approximate Number of Holders of Common Stock.
Stock
The number of holders of record of our Common Stock at September 18,
20027, 2004 was approximately 1,000 which does not include an estimated 2,600 additional holders whose stock is held in "street name".
43
(c) Dividends.
“street name.”
Dividends
We have not paid dividends on our stock and we do not expect to do so in the foreseeable future.
(d)
Recent Sales of Unregistered Securities.
ThisSecurities
On April 23, 2004, we issued a total of 1,525,000 shares of our common stock in connection with the execution of an amendment to an existing Purchase and Sale Agreement with Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, “Davis”) that was initially dated August 1, 2003. In connection with this transaction was exempt from registration underwe relied on the exemption provided by Section 4(2) of the Securities Act of 1933. We had a prior relationship with the purchaser,
both through business operations and personal contacts with our officers and
directors. We reasonably believe that both of the purchaser of these shares was an
"Accredited Investor"investors are “Accredited Investors” as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act of 1933 at the time the transactiontransactions occurred. On May 31, 2002,The investors acquired the shares for investment purposes. Restrictive legends were placed on the certificates issued to the investors, and stop transfer orders were given to our transfer agent.
In June 2004, we acquired allissued a total of the domestic oil and gas
properties of Castle Energy Corporation. The properties acquired from Castle
consist of interests in approximately 525 producing wells located in fourteen
(14) states, plus associated undeveloped acreage. We issued 9,566,0006,000,000 shares of Common Stockour common stock to Castle Energy Corporation as part of the purchase price.
We are entitled to repurchase up to 3,188,667 of our51 Accredited Investors in a private placement. The shares from Castlewere sold for $4.50$12 per share for an aggregate of $72 million. In connection with the private placement we paid Sterne, Agee & Leach, Inc., the placement agent, a periodcommission of one year after closing. This transaction was
exempt from registration under$3.6 million. In connection with this offering we relied on the exemptions provided by Section 4(2) of the Securities Act of 1933 and Rule 506 of Regulation D promulgated under the Securities Act of 1933. Options
-------
We receivedreasonably believe that all of the proceeds frominvestors are “Accredited Investors” as such term is defined in Rule 501 of Regulation D at the exercisetime the offering occurred. The investors acquired the shares for investment purposes. Restrictive legends were placed on the certificates issued to the investors, and stop transfer orders were given to our transfer agent. A Form D reporting the offering was filed with the Securities and Exchange Commission.
Issuer Purchases of options to purchaseEquity Securities
We did not repurchase any of our shares of our common stock of $407,000, $1,480,000 and $1,378,000 during the yearsquarter ended June 30, 2002, 2001 and 2000, respectively.
ITEM 6. 2004.
The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.
| Fiscal Years Ended June 30, | |||||||||||||||||
| 2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||
| (In thousands, except per share amounts) | |||||||||||||||||
Total Revenues | $ | 36,376 | $ | 20,718 | $ | 8,052 | $ | 12,712 | $ | 3,576 | |||||||
Income/(Loss) from Continuing Operations | $ | 3,867 | $ | 1,495 | $ | (4,944 | ) | $ | 1,619 | $ | (2,079 | ) | |||||
Net Income (Loss) | $ | 5,056 | $ | 1,257 | $ | (6,253 | ) | $ | 345 | $ | (3,367 | ) | |||||
Income/(Loss) Per Common Share | |||||||||||||||||
Basic | $ | .19 | $ | .05 | $ | (.49 | ) | $ | .03 | $ | (.46 | ) | |||||
Diluted | $ | .17 | $ | .05 | $ | (.49 | ) | $ | .03 | $ | (.46 | ) | |||||
Total Assets | $ | 272,704 | $ | 86,847 | $ | 74,077 | $ | 29,832 | $ | 21,057 | |||||||
Total Liabilities | $ | 86,462 | $ | 38,944 | $ | 29,161 | $ | 11,551 | $ | 10,094 | |||||||
Minority Interest | $ | 245 | $ | — | $ | — | $ | — | $ | — | |||||||
Stockholders’ Equity | $ | 185,997 | $ | 47,903 | $ | 44,916 | $ | 18,281 | $ | 10,963 | |||||||
Total Long Term Liabilities | $ | 72,386 | $ | 33,082 | $ | 24,939 | $ | 9,434 | $ | 8,245 | |||||||
MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Liquidity and Capital Resources
-------------------------------
Liquidity is a measure of a company'scompany’s ability to access cash. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities when market conditions permit, and most recently through the use of a new bank credit facility and cash provided by operating activities.activities and sale of oil and gas properties. During fiscal 2004, we increased our credit facility to $100 million with an available borrowing base of $69.4 million and raised approximately $98 million in additional capital through the sale of our common stock. The prices we receive for future oil and natural gas production and the level of production have significant impacts 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.
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.
Working Capital
---------------
At June 30, 2002, we had a working capital deficit
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 $271,000 comparedour business. However, future cash flows are subject to a workingnumber of variables including the level of production and oil and natural gas prices. We cannot assure you that operations and other capital deficitresources will provide cash in sufficient amounts to maintain planned levels of $1,560,000capital 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 2004, we completed the following transactions.
On June 29, 2004, we acquired substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc (“Alpine”) for a total purchase price of $120.6 million, net of a $1.9 million downward purchase price adjustment. Alpine was a privately held exploration and production company, active primarily in South East Texas and Louisiana.
On April 21, 2004, we acquired a fifty percent interest in approximately 1,300 leasehold acres in the Midway Loop Project located in Polk County, Texas from Wilsource Enterprises, LLC for $340,000 and 31,250 shares of the Company’s common stock valued at June 30, 2001. Our current$289,000.
Also on April 21, 2004, we acquired a seventy five percent interest in approximately 9,800 leasehold acres in the Divide Creek Extension Project located in Mesa County, Colorado from Wilsource Enterprises, LLC for $90,000 in cash and 187,500 shares of the Company’s common stock valued at $1.7 million.
In March 2004, we acquired a 50% interest in Big Dog Drilling Company, LLC (“BDDC”) for an initial investment of approximately $3 million. Also in March 2004, we purchased a 50% interest in Shark Trucking Company, LLC (“STC”) for an initial investment of approximately $276,000. The remaining 50% interest in both BDDC and STC is owned by Mike Davis. STC’s primary assets include an increase in trade accounts receivable from June 30, 2001the ownership of trucking equipment used for the mobilization of drilling rigs and equipment.
The drilling rigs owned by BDDC and trucking company will be used primarily for drilling activities on Delta’s properties. Increasing drilling rig rates, periodic lack of availability of drilling rigs and increased drilling by us were contributing factors to this venture.
On February 26, 2004, we acquired approximately $2,768,000. This increase is primarily due to the accrued
revenue from the Castle and Piper acquisitions completed during the year. Our
current liabilities include the current portion of long-term debt of
$3,498,000 at June 30, 2002. The increase135,000 leasehold acres in the current portionColumbia River Basin project in eastern Washington from an unrelated entity for $1.4 million in cash. We will become the operator once drilling begins on this acreage.
On February 24, 2004, we acquired certain properties in Texas from Labyrinth Enterprises, LLC, an unrelated entity, for $1.5 million in cash and 185,000 shares of long-term
debt from June 30, 2001 isour common stock valued at $1.6 million.
On December 10, 2003, we completed an acquisition of certain production and acreage located primarily attributed to the borrowing related to
the Castle acquisition offset by a reduction in debt from the proceeds on the
sale of the Eland and Stadium fields in Stark County, North Dakota, from Sovereign Holdings, LLC, a privately - held Colorado limited liability company (“Sovereign”), pursuant to the terms of a Purchase and Sale Agreement effective as of December 1, 2003. The total consideration paid for these properties was 773,500 shares of our common stock valued at $4.2 million, net of normal closing adjustments.
On September 19, 2003, we completed an acquisition of certain producing and drilling prospects in Colorado (the “South Tongue Prospect”) and Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, “Davis”). On the date of acquisition, we estimated proved reserves to be approximately 4.7 Bcfe. The acquisition included approximately 100,000 acres of prospect leases in the South Tongue and 20,000 acres of prospect leases in Wyoming. The total consideration was $13.1 million net of normal closing adjustments. Subsequent to September 19, 2003, we increased our South Tongue acreage position to approximately 260,000.
On April 22, 2004, we amended our agreement with Davis to, among other things, add certain oil and gas leases located in Colorado known as the “North Tongue Prospect,” decrease the amount of Davis’s reversionary working interest after payout in the properties acquired under the initial agreement from 50% to 42.5%, change the definition of payout, change certain drilling obligations and modify our obligation to issue additional shares of stock to Davis upon the designation of Bonus Prospects. The initial consideration required to be paid to Davis upon execution of the Amended Agreement was 1,525,000 shares of our common stock, valued at $17.3 million. The entire amount was allocated to unproved undeveloped properties.
During the current fiscal year, we agreed to invest an aggregate of $1 million for a 6.25% interest as a member of 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 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 quarter fiscal 2002.
Cash Provided by (Used in) Operating Activities
-----------------------------------------------
Duringparty customers located in California. As of the date of this Report, the limited liability company had not yet engaged in any revenue producing activities. We have accounted for our investment at cost.
| Cashflow | Provided by Operations |
Our cashflow from operating activities increased 20% to $9.6 million for the year ended June 30, 2002, we had cash used in operating
activities of $1,870,0002004 compared to cash provided by operating activities of
$2,779,000 during$8 million for the same period a year earlier, primarily as a result of an increase in net income.
Capital and Exploration Expenditures and Financing
Our capital and exploration expenditures and sources of financing for the years ended June 30, 2001. This decrease2004, 2003 and 2002 are as follows:
| 2004 | 2003 | 2002 | |||||||||
| (In thousands) | |||||||||||
CAPITAL AND EXPLORATION EXPENDITURES: | |||||||||||
Acquisitions: | |||||||||||
Alpine Resources | $ | 120,655 | $ | — | $ | — | |||||
Washington, County South and North Tongue | 30,406 | — | — | ||||||||
Padget | — | 9,631 | — | ||||||||
Castle | — | — | 40,767 | ||||||||
Piper | — | — | 4,803 | ||||||||
Other and development costs | 37,969 | 8,468 | 4,582 | ||||||||
Drilling and trucking companies | 3,965 | — | — | ||||||||
Exploration costs | 2,406 | 140 | 155 | ||||||||
| $ | 195,401 | $ | 18,239 | $ | 50,307 | ||||||
FINANCING SOURCES: | |||||||||||
Cash flow provided by (used in) operating activities | $ | 9,623 | $ | 7,999 | $ | (1,870 | ) | ||||
Stock issued for cash upon exercised options | 3,563 | 975 | 407 | ||||||||
Issuance of common stock for cash | 97,902 | — | 225 | ||||||||
Net long term borrowings | 37,157 | 6,921 | 14,856 | ||||||||
Proceeds from sale of oil and gas properties | 10,787 | 850 | 4,313 | ||||||||
Other | (721 | ) | 139 | 534 | |||||||
| $ | 158,311 | $ | 16,884 | $ | 18,465 | ||||||
We anticipate our capital and exploration expenditures to range between $60 and $80 million for fiscal 2005. The timing of most of our capital expenditures is discretionary. We have one drilling commitment in operating activitiesWashington County, Colorado as is discussed below.
Sale of Oil and Gas Properties - Discontinued Operations
On March 31, 2004, we completed the sale of all of our Pennsylvania properties to Castle Energy Corporation, a result20% shareholder of us at June 30, 2004, for cash consideration of $8 million, which we believe is fair value, with an effective date of January 1, 2004 and resulted in a substantial decrease ingain on sale of oil and gas prices that adversely affected net income, our decrease in production through
the saleproperties of certain properties which enabled us$1.9 million.
Subsequent to reduce debt prior to
acquiring Castle and Piper and an increase in trade receivables primarily
relating to June production for Castle and Piper not collected at June 30,
2002.
Offshore Undeveloped Properties
-------------------------------
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.
45
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. Our claim
(including the claim of our subsidiary Amber Resources Company) for lease
bonuses and rentals paid by us and our predecessors is in excess of
$152,000,000. In addition, our claim for exploration costs and related
expenses will also be substantial. The Complaint is basedyear-end 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 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 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. None of these leases are currently impaired, but in the event that
there is some future adverse ruling by the California Coastal Commission under
the Coastal Zone Management Act and we decide not to appeal such ruling to the
Secretary of Commerce, or the Secretary of Commerce either refuses to hear our
appeal of any such ruling or ultimately makes a determination adverse to us,
it is likely that some or all of these leases would become impaired and
written off at that time. In addition, it should be noted that our pending
litigation against the United States is predicated on the ruling of the lower
court in California v. Norton. The United States has appealed the decision of
the lower court to the 9th Circuit Court of Appeals. In the event that the
United States is not successful in its appeal(s) of the lower court's decision
in the Norton case and the pending litigation with us is not settled, it would
be necessary for us to reevaluate whether the leases should be considered
impaired at that time. As the ruling in the Norton case currently stands, the
United States has been ordered to make a consistency determination under the
Coastal Zone Management Act, but the leases are still valid. If through the
appellate process the leases are found not to be valid for some reason, or if
the United States is finally ordered to make a consistency determination and
either does not do so or finds that development is inconsistent with the
Coastal Zone Management Act, it would appear that the leases would become
impaired even though Delta would undoubtedly proceed with its litigation. It
is also possible that other events could occur during the appellate process
that would cause the leases to become impaired, and we will continuously
evaluate those factors as they occur.
Offshore Producing Properties
-----------------------------
Point Arguello Unit. Pursuant to a financial arrangement between Whiting
and us, we hold what is essentially the economic equivalent of a 6.07% working
interest, which we call a "net operating interest", in the Point Arguello Unit
46
and related facilities. In layman's terms, the term "net operating interest"
is defined in our agreement with Whiting 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 are three producing platforms
(Hidalgo, Harvest and Hermosa) which are operated by Arguello, Inc., a
subsidiary of Plains Resources, Inc. In an agreement between Whiting and
Delta, Whiting agreed to retain all of the abandonment costs associated with
our interest in the Point Arguello Unit and the related facilities.
We have already participated in the drilling of three wells and
anticipate that we will participate in the drilling of four wells in fiscal
2002. Each well will cost approximately $2.8 million ($170,000 to our
interest). We anticipate the drilling costs to be paid through current
operations or additional financing.
Onshore Producing Properties and Material Equity Transactions
-------------------------------------------------------------
During Fiscal 2002
------------------
On February 1, 2002, we sold interests in 20 producing wells, 5 injection
wells and acreage located in the Eland and Stadium fields in Stark County,
North Dakota for $2,750,000 to Sovereign Holdings, LLC, an unrelated entity.
As a result of the sale, the Company recognized at December 31, 2001 an
impairment of $102,000.
On FebruaryAugust 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 $5,234,000 based on
the five-day average market closing price of Delta's common stock surrounding
the announcement of the merger. In addition, we issued 51,000 shares for the
cancellation of certain debt of Piper. As a result of the acquisition, we
acquired Piper's working and royalty interests in over 700 gross (4.6 net)
wells which are primarily located in Texas, Oklahoma and Louisiana along with
a 5% working interest in the Comet Ridge coal bed methane gas project in
Queensland, Australia. On May 24, 20022004, we completed the sale of our undivided
interests in Australia, to Tipperary Corporation,five fields in exchange for Tipperary's
producing propertiesLouisiana and South Texas previously acquired in the West Buna Field (Hardin and Jasper counties,
Texas)Alpine acquisition, which had a fair market valueclosed on June 29, 2004, to Whiting Petroleum Corporation for $19.3 million. We paid $8.8 million of approximately $4,100,000, $700,000 in
cash, and 250,000 unregistered sharesour credit facility balance from the sale of Tipperary common stock.these properties. No gain or loss was recorded on this transaction. Net daily production from the West
Buna Field approximates 900,000 cubic feet equivalent. In addition, on May
28, 2002, we sold a commercial office building obtained in the merger with
Piper located in Fort Worth, Texas to a non-affiliate for its fair value of
$417,000. No gain or loss was recorded on this transaction. Piper was merged
into a subsidiary wholly owned by Deltarecognized.
Contractual and the subsidiary was then renamed
"Piper Petroleum Company". (See detailed disclosure of the Piper acquisition
in note 2 to the financial statements).
47
On May 31, 2002, we issued 9,566,000 shares of Common Stock to Castle
Energy Corporation as part of the purchase price for our purchase of all of
Castle's domestic oil and gas properties. We are entitled to repurchase up to
3,188,667 of our shares from Castle for $4.50 per share for a period of one
year after closing. (See detailed disclosure of te Castle acquisition in note
2 to the financial statements).
We estimate our capital expenditures for onshore properties to be
approximately $6,000,000 for the year ending June 30, 2003. However, we are
not obligated to participate in future drilling programs and will not enter
into future commitments to do so unless management believes we have the
ability to fund such projects.
Agreement with Swartz
---------------------
On July 21, 2000, we entered into an investment agreement with Swartz
Private Equity, LLC ("Swartz") and issued Swartz a warrant to purchase 500,000
shares of common stock exercisable at $3.00 per share until May 31, 2005. A
warrant to purchase 150,000 shares of the Company's common stock at $3.00 per
share for five years was also issued to another unrelated company as
consideration for its efforts in this transaction and has been recorded as an
adjustment to equity. In the aggregate, we issued options to Swartz and the
other unrelated company valued at $1,436,000 as consideration for the firm
underwriting commitment of Swartz and related services to be rendered and
recorded in additional paid in capital. The options were valued at market
based on the quoted market price at the time of issuance.
The investment agreement entitles us to issue and sell ("Put") up to $20
million of our common stock to Swartz, subject to a formula based on our stock
price and trading volume over a three year period following the effective date
of a registration statement covering the resale of the shares to the public.
Pursuant to the terms of this investment agreement the Company is not
obligated to sell to Swartz all of the common stock referenced in the
agreement nor does the Company intend to sell shares to the entity unless it
is beneficial to the Company.
To exercise a Put, we must have an effective registration statement on
file with the Securities and Exchange Commission covering the resale to the
public by Swartz of any shares that it acquires under the investment
agreement. The Company has filed a registration statement covering the Swartz
transaction with the SEC. Swartz will pay us the lesser of the market price
for each share minus $0.25, or 91% of the market price for each share of
common stock under the Put. The market price of the shares of common stock
during the 20 business days immediately following the date we exercise a Put
is used to determine the purchase price Swartz will pay and the number of
shares we will issue in return.
If we do not Put at least $2,000,000 worth of common stock to Swartz
during each one year period following the effective date of the Investment
Agreement, we must pay Swartz an annual non-usage fee. This fee equals the
difference between $200,000 and 10% of the value of the shares of common stock
we Put to Swartz during the one year period. The fee is due and payable on the
last business day of each one year period. Each annual non-usage fee is
payable to Swartz, in cash, within five (5) business days of the date it
48
accrued. We are not required to pay the annual non-usage fee to Swartz in
years we have met the Put requirements. We are also not required to deliver
the non-usage fee payment until Swartz has paid us for all Puts that are due.
If the investment agreement is terminated, we must pay Swartz the greater of
(i) the non-usage fee described above, or (ii) the difference between $200,000
and 10% of the value of the shares of common stock Put to Swartz during all
Puts to date. We may terminate our right to initiate further Puts or
terminate the investment agreement at any time by providing Swartz with
written notice of our intention to terminate. However, any termination will
not affect any other rights or obligations we have concerning the investment
agreement or any related agreement.
We cannot determine the exact number of shares of our common stock
issuable under the investment agreement and the resulting dilution to our
existing shareholders, which will vary with the extent to which we utilize the
investment agreement and the market price of our common stock.
Options
-------
We received the proceeds from the exercise of options to purchase shares
of our common stock of $407,000, $1,480,000 and $1,378,000 during the years
ended June 30, 2002, 2001 and 2000, respectively.
Long Term Debt Obligations
| Payments Due by Period | |||||||||||||||
Contractual Obligations | Less than 1 year | 2-3 Years | 4-5 Years | After 5 Years | Total | ||||||||||
| (In thousands) | |||||||||||||||
Bank credit facility | $ | — | $ | 69,375 | $ | — | $ | — | $ | 69,375 | |||||
Drilling obligation | 2,250 | 4,500 | 4,500 | — | 11,250 | ||||||||||
Abandonment retirement obligation | 105 | 263 | 331 | 4,685 | 5,384 | ||||||||||
Operating leases and other debt obligations | 463 | 940 | 464 | — | 1,867 | ||||||||||
Total contractual cash obligations | $ | 2,818 | $ | 75,078 | $ | 5,295 | $ | 4,685 | $ | 87,876 | |||||
Credit Facility
---------------
Our credit facility with Bank of Oklahoma, U.S. Bank and Hibernia Bank allows us to borrow, repay and reborrowre-borrow amounts, subjectup to the terms and conditionsa maximum amount of the Credit Agreement. At the time we
entered into our Credit Agreement with Bank of Oklahoma and Local Oklahoma
Bank and related promissory notes on May 31, 2002,$100 million. In order to obtain this facility, we granted 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. Under the terms of the Credit Agreement,our credit agreement, the oil and gas properties mortgaged must represent not less than 80% of the engineered value of our oil and gas properties exclusive of the properties that are mortgaged to Kaiser-Francis
under a separate lending arrangement. "Engineered value" for this purpose
means our future net revenues discounted at the discount rate being usedas determined by the Bank of Oklahoma as of the date that the determination is made using theits own pricing parameters used in the engineering report that is furnished to the
Bank of Oklahoma. In addition, any obligations arising from transactions
between us and one or more of the banks providing for the hedging, forward
sale or swap of crude oil or natural gas or interest rate protection will also
be required to be secured by a mortgage on our properties and will
consequently reduce our borrowing base. These hedging obligations will be
required to be secured and repaid on the same basis as our indebtedness and
obligations under the loan documents.
parameters.
Our borrowing base, which determines the amounts that we are allowed to borrow or have outstanding under our credit facility, was initially determined
to be $20is $69.4 million at the time we entered into the Credit Agreement.as of June 30, 2004. Subsequent determinations of our borrowing base will be made by the lending banks at least semi-annually on October 1 and April 1 of each year beginning
October 1, 2002 or as unscheduled redeterminations. In connection with each determination of our borrowing base, the banks will also redetermine the 49
TheWe do not currently have any monthly commitment reduction was $260,000.00 beginningobligation as a result of July 1, 2002our most recent redetermination, and we will continue at that amount
until the amount of thenot have any monthly commitment reduction obligation until it is redetermined.
If an unscheduled redetermination ofredetermined by our borrowing base is made by the
banks, we will be notified of the new borrowing base and monthly commitment
reduction, and this new borrowing base and monthly commitment reduction will
then continue until the next determination date. All determinations
(scheduled or unscheduled) of the borrowing base and the monthly commitment
reduction require the approval of a majority of the lending banks, but the
amount of the borrowing base cannot be increased, and the amount of the
monthly commitment reduction cannot be reduced, without the approval of all of
the lending banks. If at any time any of the oil and gas properties are sold,
the borrowing base then in effect will automatically be reduced by a sum equal
to the amount of prepayment that is required to be made.
In addition, ourOur borrowing base and the revolving commitment of the banks to lend money under the Credit Agreement willcredit agreement must be reduced as of the first day of each month by an amount determined by the banks under the Credit Agreement.our credit agreement. The amount of the borrowing base willmust also be reduced from time to time by the amount of any prepayment that results from our sale of oil and gas Properties.properties. If, as a result of any such monthly commitment reduction or reduction in the amount of our borrowing base, the total amount of our outstanding debt ever
exceedswere to exceed the amount of the revolving commitment then in effect, then, within 30 days after we are notified by the Bank of Oklahoma, we mustwould be required to make a mandatory prepayment of principal that is sufficient to causereduce our total outstanding indebtedness toso that it would not exceed our borrowing base. If for any reason we were unable to pay the full amount of the mandatory prepayment within the 30
requisite day30-day period, we would be in default of our obligations under the
Credit Agreement.
In general, we will be required to immediately make a prepayment of
principal on our revolving notes in an amount equal to 100% of the release
price that we receive from the sale of any of our oil and gas properties. Any
such sale would be required to be approved in advance by a majority of the
lending banks. The amount of the release price will be determined by a
majority of the lending banks in their discretion based upon the loan
collateral value which such banks in their discretion (using such methodology,
assumptions and discounts rates as the banks customarily use in assigning
collateral value to oil and gas properties, oil and gas gathering systems, gas
processing and plant operations) assign to such oil and gas properties at the
time in question. Any such prepayment of principal on our revolving notes
will not be in lieu of, but will be in addition to, any monthly commitment
reduction or any mandatory prepayment of principal required to be paid under
the Credit Agreement.
We are also required to establish and maintain our operating accounts
with the Bank of Oklahoma as agent for the lending banks. These operating
accounts are required to be our primary oil and gas operating bank accounts
for the purpose of depositing proceeds from oil and gas sales received from
the collateral for the credit facility and these accounts are to be maintained
with the Bank of Oklahoma until all amounts due have been paid in full. We
granted a security interest to the lending banks in and to these operating
accounts and all checks, drafts and other items ever received by any Bank for
deposit therein. If any event of default occurs under the loan documents, the
50
Bank of Oklahoma will have the immediate right, without prior notice or
demand, to take and apply against our obligations any and all funds legally
and beneficially owned by us then or thereafter on deposit in the operating
accounts. We are not permitted to redirect the payment of such proceeds of
production without the consent of the Bank of Oklahoma.
Within five days after receiving a written request from the Bank of
Oklahoma, as agent for the lending banks, we are obligated to deliver such
additional mortgages, deeds of trust, instruments, security agreements,
assignments, financing statements, and other documents, as may be reasonably
necessary in the opinion of Bank of Oklahoma and its counsel, to grant valid
first mortgage liens and first, prior and perfected security interests in and
to additional oil and gas properties of such value as the banks deem necessary
to provide additional security for full and prompt payment of all amounts
owed.
agreement.
For so long as the revolving commitment is in existence or any amount is owed under any of the loan documents, withoutwe 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 prior written consentevent of a majority ofdownturn in the lending banks:
(a) We will not be permitted to create, incur, assume or permit to
exist any lien, security interest or other encumbrance on any of our assets or
properties except for certain permitted liens.
(b) We will not be permitted to sell, lease, transfer or otherwise
dispose of, in any fiscal year, any of our oil and gas assets except for sales
of production from our oil and gas properties made in the ordinary course of
our oil and gas businesses, sales made with the consent of a majority of the
lending banks and sales, leases or transfers or other dispositions of oil and
gas properties made by us during any fiscal year, in one or any series of
transactions, the aggregate value of which does not exceed $100,000.00 if, and
only if, such sale, lease, transfer or other disposition does not result in
the occurrence of a default or event of default under our loan documents.
Further, neither we nor any of our subsidiaries can, without the prior written
consent of a majority of the lending banks, sell, lease, transfer or otherwise
dispose of any oil and gas assets unless such disposition is specifically
permitted by the Credit Agreement.
(c) We cannot allow our ratio of consolidated current assets to
consolidated current liabilities to be less than 1.0 to 1.0 as of the end of
any fiscal quarter. At June 30, 2002, we did not meet this covenant primarily
due to a current foreign tax payable of $703,000 relating to the sale of our
Australian property prior to establishing the Credit Agreement. We have
obtained a waiver for this requirement from the lending banks and we are not
in default of the Credit Agreement at June 30, 2002.
(d) We cannot allow our consolidated debt service coverage ratio to
ever be less than 1.20 to 1.0 for any quarterly fiscal period.
(e) Except under very limited circumstances, we will not be
permitted to consolidate or merge with or into any other person.
(f) We will not be permitted to incur, create, assume or in any
manner become or be liable in respect of any indebtedness (including letters
of credit other than those letters of credit permitted in the Credit
51
Agreement) in excess of $100,000.00 in the aggregate, nor may we guarantee or
otherwise in any manner become or be liable in respect of any indebtedness,
liabilities or other obligations of any other person or entity, whether by
agreement to purchase the indebtedness of any other person or entity or
agreement for the furnishing of funds to any other person or entity through
the purchase or lease of goods, supplies or services (or by way of stock
purchase, capital contribution, advance or loan) for the purpose of paying or
discharging the indebtedness of any other person or entity, or otherwise,
except that the foregoing restrictions shall not apply to:
(i) the promissory notes issued under the Credit Agreement
and any renewal or increase thereof, or our other
indebtedness that was disclosed in our Financial
Statements or on a schedule to the Credit Agreement; or
(ii) taxes, assessments or other government charges which
are not yet due or are being contested in good faith
by appropriate action promptly initiated and
diligently conducted, if such reserve as shall be
required by generally accepted accounting principles
shall have been made therefor and levy and execution
thereon have been stayed and continue to be stayed; or
(iii) indebtedness (other than in connection with a loan or
lending transaction) incurred in the ordinary course
of business, including, but not limited to
indebtedness for drilling, completing, leasing and
reworking oil and gas wells or the treatment,
distribution, transportation of sale of production
therefrom;
(iv) any renewals or extensions of (but not increases in)
any of the foregoing; or
(v) indebtedness to the other borrowers under the Credit
Agreement.
(g) We will not be permitted to declare, pay or make, whether in
cash or property, or set aside or apply any money or assets to pay or make any
dividend or distribution during any fiscal year.
(h) We will not be permitted to make or permit to remain
outstanding any loans or advances made by us to or in any person or entity,
except that the foregoing restriction shall not apply to:
(i) loans or advances to any person, the material details of
which have been set forth in our Financial Statements that
were furnished to the banks; or
(ii) advances made in the ordinary course of our oil and gas
business; or
(iii) loans or advances among the borrowers under the Credit
Agreement.
52
(i) We will not be permitted to discount or sell with recourse, or
sell for less than the greater of the face or market value thereof, any of our
notes receivable or accounts receivable.
(j) We cannot allow any material change to be made in the character
of our business as carried on as of May 31, 2002.
(k) We will not be permitted to enter into any transaction with any
of our affiliates, except transactions upon terms that are no less favorable
to us than would be obtained in a transaction negotiated at arm's length with
an unrelated third party.
(l) We will not be permitted to enter into any transaction
providing (i) for the hedging, forward sale, swap or any derivative thereof of
crude oil or natural gas or other commodities, or (ii) for a swap, collar,
floor, cap, option, corridor, or other contract which is intended to reduce or
eliminate the risk of fluctuation in interest rates, as such terms are
referred to in the capital markets, except the foregoing prohibitions shall
not apply to (x) transactions consented to in writing by a majority of the
lending banks which are on terms acceptable to them, or (y) pre-approved
contracts (i) to hedge, forward sell or swap crude oil or natural gas or
otherwise sell up to 75% of our monthly production forecast for all of our (A)
proved and producing oil properties for the period covered by the proposed
hedging transaction, and (B) proved and producing gas properties for the
period covered by the proposed hedging transaction, (ii) with a term of
eighteen (18) months or less, (iii) with "strike prices" per barrel or MCF as
applicable greater than the Bank of Oklahoma's forecasted price in the most
recent engineering evaluation, and (iv) with counter-parties approved by the
Bank of Oklahoma.
(m) We will not be permitted to make any investments in any person
or entity, except such restriction shall not apply to:
(i) investments and direct obligations of the United States of
America or any agency thereof;
(ii) investments in certificates of deposit issued by the
lending banks or certificates of deposit with maturities
of less than one year, issued by other commercial banks in
the United States having capital and surplus in excess of
$500,000,000 and which have a senior unsecured debt rating
of A+ by Standard & Poor's Ratings Group or A1 by Moody's
Investors Service, Inc.; or
(iii) investments in insured money market funds or such
investment with maturities of less than ninety (90) days
at other commercial banks having capital and surplus in
excess of $500,000,000 and which have a senior unsecured
debt rating of A+ by Standard & Poor's Ratings Group or A1
by Moody's Investors Service, Inc.; or
(iv) investments in oil and gas properties; or
(v) investments in other borrowers under the Credit Agreement;
provided such investments may not require a transfer of
assets other than cash.
53
(n) We cannot permit any amendment to, or any alteration of, our
Articles of Incorporation or Bylaws, which amendment or alteration could
reasonably be expected to have a material adverse effect under the Credit
Agreement.
(o) We will not be permitted to enter into or agree to enter into,
any rental or lease agreement resulting or which would result in aggregate
rental or lease payments by us exceeding $100,000.00 in the aggregate in any
fiscal year under all rental or lease agreements under which we are a lessee
of the property or assets covered thereby; provided, however, that the
foregoing restriction shall not apply to oil, gas and mineral leases or
permits or similar agreements entered into in the ordinary course of business
or orders of any governmental authority adjudicating the rights or pooling the
interests of the owners of oil and gas properties or lease agreements in
effect as of May 31, 2002.
(p) We may not allow our accounts payable to become in excess of
120 days past due from the date of invoice, except such accounts payable as
are being contested by us in good faith.
(q) We may not issue any preferred stock without the consent of a
majority of the lending banks.
(r) We cannot permit or suffer to exist any change in a majority of
our current board of director membership or a change or amendment to our
current corporate structure except as set forth in the Credit Agreement.
(s) Except as may be otherwise permitted the Credit Agreement, we
may not directly or indirectly make any payments upon any debt other than
regularly scheduled installments of principal and interest.
(t) We may not repurchase or set aside any funds to repurchase any
stock or partnership interests.
(u) We cannot make, permit or suffer to exist a change in
management.
(v) We may not amend, modify or otherwise alter our loan agreement
and related documents with Kaiser-Francis Oil Company dated December 1, 1999
without the lending banks' prior written consent which such consent shall not
be unreasonably withheld.
Any one or more of the following events are consideredmarket. If an event of default under the Credit Agreement:
(a) If we should fail to pay when due or declared due the principal
of, and/or the interest on, the notes, or any fee or any of our other
indebtedness incurred under our Credit Agreement or any related loan documentoccurs and such failure to pay is not cured within three days after written notice of
such failure is sent to us; or
54
(b) If any representation or warranty made by us under the Credit
Agreement, or in any certificate or statement furnished or made to the banks
pursuant thereto or in connection therewith, or in connection with any
document furnished thereunder, shall prove to be untrue in any material
respect as of the date on which such representation or warranty is made (or
deemed made), or any representation, statement (including financial
statements), certificate, report or other data furnished or to be furnished or
made by us under any loan document proves to have been untrue in any material
respect, as of the date as of which the facts therein set forth were stated or
certified; or
(c) If default is made in the due observance or performance of any
of our covenants or agreements contained in the Credit Agreement or other loan
documents and such default continues for more than thirty days after notice is
received by us; or
(d) If default is made in the due observance or performance of our
negative covenants listed above; or
(e) If default is made in respect of any obligation for borrowed
money in excess of $100,000.00, other than the promissory notes issued under
the Credit Agreement, for which we are liable (directly, by assumption, as
guarantor or otherwise), or any obligations secured by any mortgage, pledge or
other security interest, lien, charge or encumbrance with respect thereto, on
any of our assets or property in respect of any agreement relating to any such
obligations unless we are not liable for same (i.e., unless remedies or
recourse for failure to pay such obligations is limited to foreclosure of the
collateral security therefor), and if such default shall continue for more
than thirty days after notice is received by us; or
(f) If we commence a voluntary case or other proceeding seeking
liquidation, reorganization or other relief with respect to us or our debts
under any bankruptcy, insolvency or other similar law now or hereafter in
effect or seeking an appointment of a trustee, receiver, liquidator, custodian
or other similar official of us or any substantial part of our property, or if
we consent to any such relief or to the appointment of or taking possession by
any such official in an involuntary case or other proceeding commenced against
us, or if we make a general assignment for the benefit of our creditors, or
fail generally to pay our debts as they become due, or take any corporate
action authorizing the foregoing; or
(g) If an involuntary case or other proceeding is commenced against
us seeking liquidation, reorganization or other relief with respect to us or
our debts under any bankruptcy, insolvency or similar law now or hereafter in
effect or seeking the appointment of a trustee, receiver, liquidator,
custodian or other similar official of us or any substantial part of our
property, and such involuntary case or other proceeding should remain
undismissed and unstayed for a period of sixty (60) days; or an order for
relief shall be entered against us under the federal bankruptcy laws; or
(h) A final judgment or judgments or order for the payment of money
in excess of $100,000 during any one (1) fiscal year in the aggregate shall be
rendered against us and such judgments or orders shall continue unsatisfied
and unstayed for a period of thirty days; or
55
(i) In the event our total outstanding indebtedness should at any
time exceed the borrowing base established for the revolving notes, and if we
should fail to comply with the provisions of the Credit Agreement that require
us to immediately prepay an amount sufficient to cause our total outstanding
indebtedness to not exceed our borrowing base; or
(j) A change of management occurs; or
(k) Any security instrument for the indebtedness under the Credit
Agreement for any reason does not, or ceases to, create a valid and perfected
first-priority lien against all of the collateral purportedly covered thereby
and such occurrence would have a material adverse effect.
Upon occurrence of any event of default specified above and after the expiration of any cure period that is provided for in the Credit Agreement,our credit agreement, the entire principal amount due under the notes andloan documents, all interest then accrued thereon,interest and any other liabilities that we might have to the lending banks under the loan documents will all become immediately due and payable, all without notice and
without presentment, demand, protest, notice of protest or dishonor or any
other notice of default of any kind. In any other eventThe foregoing information is provided to alert investors that there is risk associated with our existing debt obligations. It is not intended to provide a summary of default, the Bankterms of Oklahoma, upon requestour agreements with our lenders.
Other Contractual Obligations
We have entered into an agreement with Edward Mike Davis which requires us to drill not less than ten prospects to the J-Sand formation during every twelve month period in our area of mutual interest in Washington County, Colorado. The estimated cost to drill a J-Sand formation prospect approximates $225,000. We successfully completed our drilling commitments for fiscal 2004. We will be required to spend approximately $2.3 million during fiscal 2005.
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 lending banks, maynext five years.
Our corporate office in Denver, Colorado is under an operating lease which will expire in fiscal 2009. Our average yearly payments approximate $310,000. We have additional operating lease commitments which represent office equipment leases and short term debt obligations primarily relating to field vehicles and equipment.
Results of Operations
The following discussion and analysis relates to items that have affected our results of operations for the three years ended June 30, 2004, 2003 and 2002. This analysis should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.
Fiscal 2004 Compared to Fiscal 2003
Net income.Net income increased $3.8 million to $5.1 million for fiscal 2004, an increase of 290% as compared to $1.3 million 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 noticeDelta.
Revenue. During fiscal 2004, oil and natural gas revenue from continuing operations increased 65% to us declare$37.2 million, as compared to $22.6 million in fiscal 2003. The increase was the principalresult of (i) an average onshore gas prices 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 all interest then accrued on, the notes and
any other liabilities hereunder to be forthwith due and payable, whereupon the
same shall forthwith become due and payable without presentment, demand,
protest, notice of intent to accelerate, notice of acceleration or other
notice of any kind.
Upon the occurrence and(iv) a 40% increase in average daily production during the continuancefiscal year previously discussed above.
Cash payments required on our hedging activities impacted revenues in 2004 and 2003. The cost of any eventsettling of default
beyond any cure period providedour 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 Credit Agreement,years ended June 30, 2004 and 2003 are as follows:
| 2004 | 2003 (1) | |||||||||||||
| Onshore | Offshore | Onshore | Offshore | |||||||||||
Production: | ||||||||||||||
Oil (MBbl) | 552 | 180 | 217 | 227 | ||||||||||
Gas (Mmcf) | 2,842 | — | 2,492 | — | ||||||||||
Production – Discontinued Operations: | ||||||||||||||
Oil (MBbl) | 16 | — | 35 | — | ||||||||||
Gas (Mmcf) | 268 | — | 446 | — | ||||||||||
Average Price – Continuing Operations: | ||||||||||||||
Oil (per barrel) | $ | 33.09 | $ | 22.11 | $ | 28.82 | $ | 20.21 | ||||||
Gas (per Mcf) | $ | 5.27 | $ | — | $ | 4.71 | $ | — | ||||||
Hedge effect | ||||||||||||||
(per Mcf equivalent) | $ | (.14 | ) | $ | — | $ | (.49 | ) | $ | — | ||||
Production Costs: | ||||||||||||||
(per Mcf equivalent) | $ | 1.06 | $ | 3.02 | $ | 1.35 | $ | 2.40 | ||||||
Depletion Expense: | ||||||||||||||
(per Mcf equivalent) | $ | 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”. |
Production Costs. Production costs increased 16% to $9.8 million for fiscal 2004, as compared to $8.4 million for 2003. However, production costs per equivalent Mcf decreased from $1.35 per Mcf equivalent in fiscal 2003 to $1.06 per Mcf equivalent in fiscal 2004. This decrease in production cost per Mcf equivalent can primarily be attributed to our Padget Field acquisition completed during fiscal 2003. The Padget Field added an additional 1.2 Bcf equivalent to current year production with an associated cost of $.22 per Mcf equivalent.
Drilling and Trucking Operations. In March 2004, we acquired a 50% interest in both the lending banks are
authorized at any timeBig Dog Drilling Company and from timeShark Trucking Company. We began drilling our first well with a Big Dog Drilling Company 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.
Depreciation and Depletion Expense.Depreciation and depletion expense increased 96% to time, without notice$9.9 million in fiscal 2004, as compared to us, to set-off$5 million in fiscal 2003. Depreciation and apply any and all deposits (general or special, time or demand,
provisional or final) at any time held and other indebtedness at any time
owing by any of the banks to ordepletion expenses per equivalent Mcf for our credit or our account against any and
allonshore properties increased to $1.46 per Mcf equivalent during fiscal 2004 from $1.02 per Mcf equivalent in fiscal 2003. This increase can be attributed to the acquisition of our indebtedness underChristensen Field in Washington County which had a depreciation and depletion expense of $2.40 per Mcf equivalent and the notesacquisition of our Eland and Stadium fields which had a depreciation and depletion expense of $2.74 per Mcf equivalent.
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 a 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.
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 Expenses. General and administrative 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 loan documents,
irrespectivepersonnel costs, (ii) the expansion of whether or notour 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 banks shall have made any demand under the
loan documents and although such indebtedness may be unmatured. Any amount
set-off by any of the banks is to be applied against the indebtedness owed by
us to the banks. The banks have agreed to promptly notify us after any such
set-off and application, provided that the failure to give such notice shall
not affect the validity of such set-off and application. These rights areincrease in addition to other rights and remedies (including, without limitation, other
rights of set-off) which the banks might have.
Upon the occurrence of andlong-term debt obligations during the continuanceyear.
Discontinued Operations.Included in discontinued operations are (i) income (loss) from operations of any eventproperties sold and (ii) gain (loss) on sale of default, we will not be permittedoil and gas properties. We are required to servicere-class related revenue and expenses relating to sales of our obligations under our loan
agreement with Kaiser-Francis Oil Company from proceeds of the collateral
securing the loan under our Credit Agreement including, but not limited to, oil and gas properties or any related operating fees.
The foregoing does not purport to befor all periods presented. During fiscal 2004, we sold our Pennsylvania properties which resulted in a complete summarygain on sale of the Credit
Agreement$1.9 million. During fiscal 2003, we sold some non-strategic oil and other loan documents. Complete copiesgas properties which resulted in a gain of these documents are
filed as exhibits to our Report on Form 8-K dated May 24, 2002.
56
Results of Operations $277,000.
Fiscal 20022003 Compared to Fiscal 2001
---------------------------------------------------------
2002
Net EarningsIncome (Loss).Our net lossincome for the year ended June 30, 20022003 was $6,253,000$1.3 million compared to net incomeloss of $345,000$6.3 million for the year ended June 30, 2001.2002. The results for the years ended June 30, 2003 and 2002 and 2001 were effectedaffected by the items described in detail below.
Revenue.Total revenue for the year ended June 30, 20022003 was $8,210,000$20.7 million compared to $12,877,000$8 million for the year ended June 30, 2001.2002. Oil and gas sales from continuing operations for the year ended June 30, 20022003 were $8,121,000$22.6 million compared to $12,254,000$8 million for the year ended June 30, 2001.2002. The decreaseincrease in oil and gas sales during the year ended June 30, 20022003 resulted primarily from the sale of twenty producing wells,
five injection wells locatedCastle and Piper acquisitions, completed in Eland and Stadium fields in Stark County,
North Dakota. Oil and gas sales were also impacted by the decrease in oil and
gas prices.
Gain (loss) on sale of oil and gas properties. During the years ended
June 30, 2002 and 2001, we disposed of certain oil and gas properties and
related equipment to unaffiliated entities. We have received proceeds from
the sales of $4,417,000 and $3,700,000 which resulted in a loss on sale of oil
and gas properties of $88,000 for the year ended June 30, 2002 and a gain on
sale of $458,000 for the year ended June 30, 2001.
Other Revenue. Other revenue for the year ended June 30, 2001,
represents amounts recognized from the production of gas previously deferred
pending determination of our interests in the properties.
fiscal 2002.
Production volumes and average prices received for the years ended June 30, 20022003 and 20012002 are as follows:
2002 2001
Onshore Offshore Onshore Offshore
-------- -------- ------- --------
Production:
Oil (barrels) 89,000 262,000 117,000 308,000
Gas (Mcf) 871,000 - 539,000 -
Average Price:
Net of forward contract sales
Oil (per barrel) $22.22 $14.36 $27.10 $18.49
Gas (per Mcf) $ 2.75 - $ 6.27 -
Gross of forward contract sales*
Oil (per barrel) $22.32 $14.45 $27.30 $22.53
Gas (per Mcf) $ 2.75 - $ 6.27 -
We sold 25,000 barrels of our offshore production per month
| 2003 (1) | 2002 (1) | ||||||||||||
| Onshore | Offshore | Onshore | Offshore | ||||||||||
Production: | |||||||||||||
Oil (MBbl) | 217 | 227 | 86 | 262 | |||||||||
Gas (Mmcf) | 2,492 | — | 870 | — | |||||||||
Production – Discontinued Operations: | |||||||||||||
Oil (MBbl) | 35 | — | 3 | — | |||||||||
Gas (Mmcf) | 446 | — | 1 | — | |||||||||
Average Price – Continuing Operations: | |||||||||||||
Oil (per barrel) | $ | 28.82 | $ | 20.21 | $ | 22.22 | $ | 14.36 | |||||
Gas (per Mcf) | $ | 4.71 | $ | — | $ | 2.75 | $ | — | |||||
Hedge effect | |||||||||||||
(per Mcf equivalent) | $ | (.49 | ) | $ | — | $ | .03 | $ | — | ||||
Production Costs: | |||||||||||||
(per Mcf equivalent) | $ | 1.35 | $ | 2.40 | $ | .90 | $ | 1.94 | |||||
Depletion Expense: | |||||||||||||
(per Mcf equivalent) | $ | 1.02 | $ | .79 | $ | 1.58 | $ | .69 | |||||
Production Costs.Production costs from June
2000 to December 2000 at $14.65 per barrel under fixed price contracts with
production purchases. We sold 6,000 barrels per month from March 1, 2001
through June 30, 2001 at $27.31 per barrel under fixed price contracts with
production purchases. If we would not have sold our proportionate shares of
offshore California barrels at $14.65 per barrel under fixed price contracts
with production purchases, we would have realized an increase in income of
$1,242,000 in 2001.
57
Lease Operating Expenses. Lease operating expensescontinuing operations for the year ended June 30, 20022003 were $4,372,000$8.4 million compared to $4,698,000$4.3 million for the year ended June 30, 2001. Lease operating expense2002. Production costs from continuing operations decreased slightly compared to 20012002 as a result of less non-capitalized workover costs incurred during fiscal 20022003 compared to fiscal 2001.2002. On a per BblMcf equivalent basis, production expenses and taxescosts from continuing operations were $5.68$1.35 for onshore properties and $11.64$2.40 for offshore properties during the year ended June 30, 20022003 compared to $3.88$.90 for onshore properties and $12.62$1.94 for offshore properties for the year ended June 30, 2001.
2002. The change in production costs per Mcf equivalent fluctuates with the nature of the properties, including maturity and non-capitalized workover costs. The acquisition of the Padget field in Kansas was the primary contributor to lowering our production cost per Mcf.
| (1) | 2003 and 2002 information has changed to comply with FAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”. |
Depreciation and Depletion Expense. Depreciation and depletion from continuing operations expense for the year ended June 30, 20022003 was $3,347,000$5 million compared to $2,533,000$3.3 million for the year ended June 30, 2001.2002. On a per BblMcf equivalent basis, the depletion rate was $9.57$1.02 for onshore properties and $4.20$.79 for offshore properties during the year ended June 30, 20022003 compared to $8.16$1.58 for onshore properties and $2.71$.69 for offshore properties for the year ended June 30, 2001.
2002.
Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Exploration expenses were $140,000 for the year ended June 30, 2003 compared to $155,000 for the year ended June 30, 2002 compared to $89,000 for the year ended June 30,
2001.
2002.
Abandonment and Impairment ofImpaired Oil and Gas Properties. We recorded an expense for the abandonment and impairment of oil and gas properties for the year ended June 30, 2002 of $1,480,000.$1.5 million. Our proved properties were assessed for impairment on an individual field basis and we recorded impairment provisions attributable to certain producing properties of $878,000$-0- and $174,000$878,000 for the years ended June 30, 20022003 and 2001,2002, respectively. Also during fiscal 2002, we recorded an impairment of $602,000 attributable to our undeveloped properties as future development of these properties are unlikely. The expense in 2001 also included a provision for impairment of the costs
associated with the Kazakhstan licenses of $624,000. We made a determination based on the political risk and lack of expertise in the area that it maywould not be economical to develop this prospect and as such we may not proceed with this prospect. See "Impairment of Long-Lived Assets" in "Description of
Properties."
Professional Fees. Professional fees for the year ended June 30, 20022003 were $1,322,000$842,000 compared to $1,108,000$1.3 million for the year ended June 30, 2001. The
increase in professional2002. Professional fees compared to fiscal 2001 can be primarily
attributed toinclude corporate legal costs, accounting fees for representation in negotiations and discussions
with various state and federal governmental agencies relating to the Company's
undeveloped offshore California leases.
shareholder relations consultants.
General and Administrative Expenses. General and administrative expenses for year ended June 30, 20022003 were $2,036,000$4.3 million compared to $1,470,000$2 million for the year ended June 30, 2001.2002. The increase in general and administrative expenses is primarily attributed to increased costs in anticipation of the acquisitions completed in fiscal 20022003 including office relocation and additional staff.
Stock Option Expense. Stock option expense has been recorded for the
years ended June 30, 2002 and 2001 of $143,000 and $409,000, respectively, for
options granted to certain directors and consultants at option prices below
the market price at the date of grant. The stock option expense for fiscal
2002 and 2001 can primarily be attributed to options to certain consultants
that provide us with shareholder relations services and options to our
directors.
58
Interest and Financing Costs. Interest and financing costs for the year ended June 30, 20022003 were $1,325,000$1.8 million compared to $1,861,000$1.3 million for the year ended June 30, 2001. The decrease in interest and financing costs can be attributed
to the reduction in debt prior to the Castle acquisition which closed on May
31, 2002 in addition to lower interest rates compared to fiscal 2001.
Other Income. Other income of $528,000 for the year ended June 30, 2001
includes the sale of our unsecured claim in bankruptcy against our former
parent, Underwriters Financial Group, in the amount of $350,000.
Results of Operations Fiscal 2001 Compared to Fiscal 2000
---------------------------------------------------------
Net Earnings (Loss). Our net income for the year ended June 30, 2001 was
$345,000 compared to a net loss of $3,367,000 for the year ended June 30,
2000. The results for the years ended June 30, 2001 and 2000 were effected by
the items described in detail below.
Revenue. Total revenue for the year ended June 30, 2001 was $12,877,000
compared to $3,576,000 for the year ended June 30, 2000. Oil and gas sales
for the year ended June 30, 2001 were $12,254,000 compared to $3,356,000 for
the year ended June 30, 2000. The increase in oil and gas sales during the
year ended June 30, 2001 resulted from the acquisitions of twenty producing
wells, five injection wells located in Eland and Stadium fields in Stark
County, North Dakota and the Cedar State gas property in Eddy County, New
Mexico during fiscal 2001 and eleven producing wells in New Mexico and Texas
and the acquisition of an interest in the offshore California Point Arguello
Unit during fiscal 2000. The increase in oil and gas sales were also impacted
by the increase in oil and gas prices. If we would not have sold our
proportionate shares of offshore California barrels at $8.25 and $14.65 per
barrel under fixed price contracts with production purchases, we would have
realized an increase in income of $1,242,000 in 2001 and $2,033,000 in 2000.
Gain on sale of oil and gas properties. During the years ended June 30,
2001 and 2000, we disposed of certain oil and gas properties and related
equipment to unaffiliated entities. We have received proceeds from the sales
of $3,700,000 and $75,000 which resulted in a gain on sale of oil and gas
properties of $458,000 and $76,000 for the years ended June 30, 2001 and 2000,
respectively.
Other Revenue. Other revenue represents amounts recognized from the
production of gas previously deferred pending determination of our interests
in the properties.
Production volumes and average prices received for the years ended June
30, 2001 and 2000 are as follows:
59
2001 2000
Onshore Offshore Onshore Offshore
------- -------- ------- --------
Production:
Oil (barrels) 117,000 308,000 10,000 187,000
Gas (Mcf) 539,000 - 362,000 -
Average Price:
Net of forward contract sales
Oil (per barrel) $27.10 $18.49 $25.95 $11.54
Gas (per Mcf) $ 6.27 - $ 2.62 -
Gross of forward contract sales*
Oil (per barrel) $27.30 $22.53 $25.95 $21.14
Gas (per Mcf) $ 6.27 - $ 2.62 -
_________________
*We sold 25,000 barrels per month from December 1999 to May 2000 at $8.25 per
barrel and we sold 25,000 barrels of our offshore production per month from
June 2000 to December 2000 at $14.65 per barrel under fixed price contracts
with production purchases. We sold 6,000 barrels per month from March 1, 2001
through June 30, 2001 at $27.31 per barrel under fixed price contracts with
production purchases. If we would not have sold our proportionate shares of
offshore California barrels at $8.25 and $14.65 per barrel under fixed price
contracts with production purchases, we would have realized an increase in
income of $1,242,000 in 2001 and $2,033,000 in 2000.
Lease Operating Expenses. Lease operating expenses for the year ended
June 30, 2001 were $4,698,000 compared to $2,405,000 for the year ended June
30, 2000. The increase in lease operating expense compared to 2000 resulted
from the acquisitions of twenty producing wells and five injection wells in
Stark County, North Dakota and the Cedar State gas property in Eddy County,
New Mexico during fiscal 2001 and the acquisition of an interest in eleven new
properties onshore and an interest in the offshore Point Arguello Unit near
Santa Barbara, California during fiscal 2000. On a per Bbl equivalent basis,
production expenses and taxes were $3.88 for onshore properties and $12.65 for
offshore properties during the year ended June 30, 2001 compared to $4.94 for
onshore properties and $11.02 for offshore properties for the year ended June
30, 2000.
Depreciation and Depletion Expense. Depreciation and depletion expense
for the year ended June 30, 2001 was $2,533,000 compared to $888,000 for the
year ended June 30, 2000. On a per Bbl equivalent basis, the depletion rate
was $8.16 for onshore properties and $2.71 for offshore properties during the
year ended June 30, 2001 compared to $4.64 for onshore properties and $3.00
for offshore properties for the year ended June 30, 2000.
Exploration Expenses. Exploration expenses consist of geological and
geophysical costs and lease rentals. Exploration expenses were $89,000 for
the year ended June 30, 2001 compared to $47,000 for the year ended June 30,
2000.
Abandonment and Impairment of Oil and Gas Properties. We recorded an
expense for the abandonment and impairment of oil and gas properties for the
year ended June 30, 2001 of $798,000. Our proved properties were assessed for
impairment on an individual field basis and we recorded impairment provisions
60
attributable to certain producing properties of $174,000 for the year ended
June 30, 2001. The expense in 2001 also includes a provision for impairment
of the costs associated with the Kazakhstan licenses of $624,000. We made a
determination based on the political risk and lack of expertise in the area
that it may not be economical to develop this prospect and as such we may not
proceed with this prospect. Based on an assessment of all properties as of
June 30, 2000, there was no impairment for oil and gas properties in fiscal
2000. See impairment of Long-Lived Assets in "Description of Properties."
Professional Fees. Professional fees for the year ended June 30, 2001
were $1,108,000 compared to $519,000 for the year ended June 30, 2000. The
increase in professional fees compared to fiscal 2000 can be primarily
attributed to legal fees for representation in negotiations and discussions
with various state and federal governmental agencies relating to the Company's
undeveloped offshore California leases.
General and Administrative Expenses. General and administrative expenses
for year ended June 30, 2001 were $1,470,000 compared to $1,258,000 for the
year ended June 30, 2000. The increase in general and administrative expenses
is primarily attributed to the increase in travel, corporate filings, salaries
and contract labor.
Stock Option Expense. Stock option expense has been recorded for the
years ended June 30, 2001 and 2000 of $409,000 and $538,000, respectively.
The stock option expense for fiscal 2001 and 2000 can primarily be attributed
to options to certain consultants that provide us with shareholder relations
services and options to our directors.
Interest and Financing Costs. Interest and financing costs for the year
ended June 30, 2001 were $1,861,000 compared to $1,265,000 for the year ended
June 30, 2000.2002. The increase in interest and financing costs can be attributed to the increase in debt related to the amortizationCastle acquisition, which closed on May 31, 2002.
Discontinued Operations.Included in discontinued operations are (i) income (loss) from operations of the deferred financing costsproperties sold and (ii) gain (loss) on sale of oil and gas properties. We are required to re-class related revenue and expenses relating to the additional debtsales of our oil and gas properties for the new acquisitions duringall periods presented. During fiscal 2001 primarily
relating to the overriding royalties earned by Kaiser-Francis Oil Company
pursuant to the loan agreement.
Other Income. Other income2003, we sold some non-strategic oil and gas properties which resulted in a gain of $528,000 for the year ended June 30, 2001
includes the$277,000. During fiscal 2002, we sold non-strategic oil and gas properties which resulted in a loss on sale of our unsecured claim in bankruptcy against our former
parent, Underwriters Financial Group, in the amount of $350,000.
$88,000.
Critical Accounting Policies and Estimates
------------------------------------------
The discussion and analysis of the Company'sour 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 Advise“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
61
the Company'sour financial statements.
Successful Efforts Method of Accounting
---------------------------------------
We account for itsour 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. Gas and oil 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 costscost 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 the Company iswe 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.
62
Reserve Estimates
-----------------
We estimate
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 very considerablevary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locationlocations 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 the 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 the Company'sour reserves will likely vary from estimates, and such variances may be material.
Impairment of Gas and Oil Properties
------------------------------------
We review itsour oil and gas and oil 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 its gas and oilour developed proved properties and comparescompare such future cash flows to the carrying amount of the gas and oilproved 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 gasoil and oilgas 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 markers,markets, events may arise that would require the Companyus to recordedrecord an impairment of the recorded book values associated with gas and oil properties. As a result of itsour review, the Companywe recognized an impairment of $1,480,000 and $798,000$1.5 million for the year ended June 30, 2002. We did not record a impairment during the years ended June 30, 20022004 and June 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.
On January 1, 2001, respectively. The Company did not
record an impairment during the year ended June 30, 2000.
63
Recently Issued or Proposed Accounting Standards and Pronouncements
-------------------------------------------------------------------
In July 2001, the Financial Accounting Standards Board issued and
approved for issuancewe adopted SFAS No. 143, "Accounting133, “Accounting for Asset Retirement
Allocations."Derivative Instruments and Hedging Activities.” Under SFAS No. 143 requires entities to record133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value of a
liability for an asset retirement obligationare recognized currently in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset and is effective for fiscal years beginning after June 15,
2002. Management is currently assessing the impact SFAS No. 143 will have on
our financial condition and results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, that superseded SFAS No. 121 and
APB Opinion No. 30. SFAS 144 provides guidance on differentiating between
assets held and used, held for sale, and held for disposal other than by sale,
and the required valuation of such assets. SFAS 144 is effective for fiscal
years beginning after December 15, 2001. Management is currently assessing
the impact SFAS No. 144 will have on our financial condition and results of
operations.
Statement 145, Recission of FASB Statements No. 4, 44 and 64, Amendment
of FASB Statement No. 13, and Technical Corrections (SFAS No. 145) was issued
in April 2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, theearnings unless specific hedge accounting criteria in APB 30
will now be used to classify those gains and losses. Anyare met. For qualifying cash flow hedges, the gain or loss on the extinguishmentderivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of debtthe 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 was classifiedthe 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 extraordinary itemeffective component of commodity price risk management (CPRM) activities.
Recently Issued Accounting Standards and Pronouncements
In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities - an interpretation of ARB No. 51” (“FIN 46”). FIN 46 is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (“VIE’s”). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights. Such entities are known as VIE’s. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both.
An enterprise shall consider the rights and obligations conveyed by its variable interests in prior
periods presentedmaking this determination. This guidance applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that does not meetdate. It applies in the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this
Statement are effective forfirst fiscal yearsyear or interim period beginning after JanuaryJune 15, 2003 to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. WeAt this time, we do not believe the Company will be materially impacted by this statement.
Statement 146, Accounting for Exit or Disposal Activities (SFAS No. 146),
was issuedhave an interest in June 2002. SFAS No. 146 addresses significant issues regarding
the recognition, measurement and reporting of disposal activities, including
restructuring activities that are currently accounted in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Activity." SFAS No.
146 will be effective in January 2003. We are currently assessing the impact
of SFAS No. 146.
ITEM 7A. an unconsolidated VIE.
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.
64
Market Rate and Price Risk
--------------------------
Beginning in fiscal 2003, 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 volitalvolatile oil and gas prices and to manage the exposure to commodity price risk. There were no derivative contracts outstanding at June 30, 2004.
Interest Rate Risk
------------------
We were subject to interest rate risk on $24,939,000$69.4 million of variable rate debt obligations at June 30, 2002.2004. The annual effect of a oneten percent change in interest rates would be approximately $250,000.$350,000. The interest rate on these variable rate debt obligations approximates current market rates as of June 30, 2002.
ITEM 8. 2004.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements are included and begin on page F-1. ITEM 9. There are no financial statement schedules since they are either not applicable or the information is included in the notes to the financial statements.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
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, 2004. 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.
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 most recent evaluation of our disclosure controls and procedures utilized to compile information included in this filing.
The information required by Part III, Item 10 "Directors,“Directors and Executive Officers Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act",Registrant,” Item 11 "Executive Compensation",“Executive Compensation,” Item 12 "Security“Security Ownership of Certain Beneficial Owners and Management", andManagement,” Item 13 "Certain“Certain Relationships and Related Transactions",Transactions” and Item 14 “Principal Accounting Fees and Services” is incorporated by reference to Registrant'sthe Company’s definitive Proxy Statement which will be filed with the Securities and Exchange Commission in connection with the 2004 Annual Meeting of Shareholders. For information concerning Item 10 "Directors“Directors and Executive Officers";Officers of the Registrant,” see Part I; Item 4A.
65
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) Financial Statements.
Page No.
Independent Auditors' Report ......................... F-1
Consolidated Balance Sheets for the years ended
June 30, 2002 and 2001 ............................... F-2
Consolidated Statements of Operations for the years
ended June 30, 2002, 2001 and 2000 ................... F-3
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (Loss) for the years
ended June 30, 2002, 2001 and 2000 ................... F-4
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (Loss) for the years
ended June 30, 2002, 2001 and 2000 ................... F-5
Consolidated Statements of Cash Flows for the
years ended June 30, 2002, 2001 and 2000 ............. F-6
Notes to Consolidated Financial Statements ........... F-7
| Page No. | ||
| F-1 | ||
| F-2 | ||
Consolidated Statements of Operations for the years ended June 30, 2004, 2003 and 2002 | F-3 | |
| F-4 | ||
Consolidated Statements of Cash Flows for the years ended June 30, 2004, 2003 and 2002 | F-5 | |
| F-6 | ||
(a)(2) Financial Statement Schedules. None.
(b) Reports on Form 8-K. During the quarter ended June 30, 2002, the
Registrant filed Reports on Form 8-K as follows:
1. Form 8-K; March 1, 2002; Items 2, 5 and 7.
2. Form 8-K; April 30, 2002; Items 5 and 7.
3. Form 8-K; May 24, 2002; Items 2, 5 and 7.
(c)
(a)(3) Exhibits. The Exhibits listed in the Index to Exhibits appearing at page 6746 are filed as part of this report. 66
INDEX TO EXHIBITS
2. Plans of Acquisition, Reorganization, Arrangement, Liquidation, or
Succession. Not applicable.
3. Articles of IncorporationManagement contracts and By-laws. The Articles of Incorporation and
Articles of Amendmentcompensatory plans required to Articles of Incorporation and By-laws ofbe filed as exhibits are marked with a “*”.
(b) Reports on Form 8-K. During the quarter ended June 30, 2004, the Registrant were filed as Exhibits 3.1, 3.2, and 3.3, respectively, to
the Registrant's Form 10 Registration Statement under the Securities
Exchange Act of 1934, filed September 9, 1987 with the Securities and
Exchange Commission and are incorporated herein by reference.
4. Instruments Defining the Rights of Security Holders. Statement of
Designation and Determination of Preferences of Series A Convertible
Preferred Stock of Delta Petroleum Corporation is incorporated by
Reference to Exhibit 28.3 of the Current ReportReports on Form 8-K datedduring the last quarter covered by this Report as follows:
1. Form 8-K; April 12, 2004; Item 5.
2. Form 8-K; April 23, 2004; Items 2 and 7.
3. Form 8-K; May 11, 2004; Item 5.
4. Form 8-K; June 15, 1988.29, 2004; Items 2 and 7.
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. Filed herewith electronically. | |
| 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. Not applicable. | |
| 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. | |
| 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 Exhibit10.22 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. | |
| 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. | |
| 11. | Statement Regarding Computation of Per Share Earnings. Not applicable. | |
| 12. | Statement Regarding Computation of Ratios. Not applicable. | |
| 21. | Subsidiaries of the Registrant. Filed herewith electronically. | |
| 23.1 | Consent of KPMG LLP. Filed herewith electronically. | |
| 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. | |
| 32.1 | 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. |
Report of Designation and Determination of Preferences of
Series B Convertible Preferred Stock of Delta Petroleum Corporation is
incorporated by reference to Exhibit 28.1 of the Current Report on Form
8-K dated August 9, 1989. Statement of Designation and Determination of
Preferences of Series C Convertible Preferred Stock of Delta Petroleum
Corporation is incorporated by reference to Exhibit 4.1 of the current
report on Form 8-K dated June 27, 1996.
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.
67
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.
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 Loan Agreement (without exhibits) between Kaiser-Francis Oil Company and
Delta Petroleum Corporation dated December 1, 1999. Incorporated by
reference from Exhibit 10.2 to the Company's Form 8-K dated December 1,
1999.
10.10 Promissory Note dated December 1, 1999. Incorporated by reference from
Exhibit 10.3 to the Company's Form 8-K dated December 1, 1999.
10.11 July 29, 1999 Agreement between GlobeMedia AG and Delta Petroleum
Corporation with November 23, 1999 amendment. Incorporated by reference
from Exhibit 99.1 to the Company's Form 8-K dated January 4, 2000.
10.12 Letter Agreement between GlobeMedia AG and Delta Petroleum Corporation
dated November 23, 1999. Incorporated by reference from Exhibit 99.3
to the Company's Form 8-K dated January 4, 2000.
10.13 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.
10.14 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.
10.15 Investment Agreement dated July 21, 2000 between Delta Petroleum
Corporation and Swartz Private Equity, LLC and related agreements.
Incorporated by reference from Exhibit 99.2 to the Company's Form 8-K
dated July 10, 2000.
10.16 Purchase and Sale Agreement between Delta Petroleum Corporation and
Castle Offshore LLC and BWAB Limited Liability Company dated August 4,
2000. Incorporated by reference from Exhibit 10.1 to the Company's Form
8-K dated September 29, 2000.
10.17 Documents evidencing financing arrangements between Hexagon Investments
and Delta Petroleum Corporation dated September 28, 2000. Incorporated
by reference from Exhibit 10.2 to the Company's Form 8-K dated September
29, 2000.
68
10.18 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.
10.19 Agreements between Evergreen Resources, Inc., and Delta Petroleum
Corporation dated January 3, 2001. Incorporated by reference from
Exhibit 10.1 to the Company's Form 8-K dated January 22, 2001.
10.20 Purchase and Sale Agreement (without exhibits) dated March 29, 2001
between Delta Petroleum Corporation and Panaco, Inc. Incorporated by
reference from Exhibit 10.1 to the Company's Form 8-K dated April 13,
2001.
10.21 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.
10.22 Delta Petroleum Corporation 2002 Incentive Plan incorporated by
reference from Exhibit A to the Company's definitive proxy statement
filed May 1, 2002.
10.23 Agreement between Delta Petroleum Corporation and Amber Resources
Company dated July 1, 2001, incorporated by reference Exhibit 10.3 to
the Company's Form 8-K dated October 25, 2001.
10.24 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.
10.25 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.
10.26 Purchase and Sale Agreement between Delta Petroleum Corporation and
Sovereign Holdings, LLC, incorporated by reference from Exhibit 10.1 to
the Company's Form 8-K dated March 1, 2002.
10.27 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.
10.28 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. Incorporation by reference from Exhibit 10.1
to the Company's Form 8-K dated May 24, 2002.
10.29 Agreement and Plan of Merger among Delta Petroleum Corporation, Delta
Acquisition Company, Inc., Piper Petroleum Company and John H. Wilson,
II executed February 2002.
11. Statement Regarding Computation of Per Share Earnings. Not applicable.
12. Statement Regarding Computation of Ratios. Not applicable.
69
13. Annual Report to Security Holders, Form 10-Q or Quarterly Report to
Security Holders. Not applicable.
16. Letter re: Change in Certifying Accountants. Not applicable.
17. Letter Regarding Change inIndependent Registered Public Accounting Principles. Not applicable.
18. Subsidiaries of the Registrant. Not applicable.
19. Published Report Regarding Matters Submitted to Vote of Security
Holders. Not applicable.
20. Consent of Experts and Counsel.
23.1 KPMG LLP. Filed herewith electronically.
21. Power of Attorney. Not applicable.
99. Additional Exhibits. Not applicable.
70
Independent Auditors' Report
Firm
The Board of Directors and Stockholders
Delta Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation (the Company) and subsidiarysubsidiaries as of June 30, 20022004 and 20012003, and the related consolidated statements of operations, stockholders'stockholders’ equity and comprehensive income, (loss), and cash flows for each of the years in the three year period ended June 30, 2002.then ended. These consolidated financial statements are the responsibility of the Company'sCompany’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 auditingthe standards generally
accepted inof the United States of America.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 misstatements. 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 statementsstatement 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, 20022004 and 20012003, and the results of their operations and their cash flows for each of the years in the
three-year periodthen ended June 30, 2002, in conformity with accounting principles generally accepted in the United States of America.
/s/ KPMG LLP
KPMG LLP
Denver, Colorado
September 12, 2002
F-1
As described in Note 2 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of July 1, 2002.
/s/ KPMG LLP |
KPMG LLP |
Denver, Colorado |
September 3, 2004 |
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, June 30,
2002 2001
----------- -----------
ASSETS
Current Assets:
Cash and cash equivalents $ 1,024,000 $ 518,000
Marketable securities available for sale 485,000 -
Trade accounts receivable and other 4,713,000 1,945,000
Prepaid assets 785,000 594,000
Other current assets 442,000 538,000
----------- -----------
Total current assets 7,449,000 3,595,000
----------- -----------
Property and Equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting): 73,002,000 29,955,000
Less accumulated depreciation and depletion (7,018,000) (5,024,000)
----------- -----------
Net property and equipment 65,984,000 24,931,000
----------- -----------
Long term assets:
Deferred financing costs 260,000 241,000
Marketable securities available for sale - 221,000
Partnership net assets 384,000 844,000
----------- -----------
Total long term assets 644,000 1,306,000
----------- -----------
$74,077,000 $29,832,000
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current portion of long-term debt $ 3,498,000 $ 3,038,000
Accounts payable 3,488,000 2,071,000
Current foreign tax payable 703,000 -
Other accrued liabilities 31,000 46,000
----------- -----------
Total current liabilities 7,720,000 5,155,000
----------- -----------
Long-term debt, net of current portion 21,441,000 6,396,000
----------- -----------
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
22,618,000 shares at June 30, 2002
and 11,161,000 at June 30, 2001 226,000 112,000
Additional paid-in capital 76,514,000 40,700,000
Put option on Delta stock (2,886,000) -
Accumulated other comprehensive income (85,000) 69,000
Accumulated deficit (28,853,000) (22,600,000)
----------- -----------
Total stockholders' equity 44,916,000 18,281,000
----------- -----------
Commitments $74,077,000 $29,832,000
=========== ===========
| June 30, 2004 | June 30, 2003 | |||||||
| (In thousands) | ||||||||
| ASSETS | ||||||||
Current Assets: | ||||||||
Cash and cash equivalents | $ | 2,078 | $ | 2,271 | ||||
Marketable securities available for sale | 912 | 662 | ||||||
Trade accounts receivable, net of allowance for doubtful accounts | 9,092 | 4,410 | ||||||
Prepaid assets | 1,136 | 764 | ||||||
Inventory of oil field equipment | 1,350 | — | ||||||
Other current assets | 385 | 560 | ||||||
Total current assets | 14,953 | 8,667 | ||||||
Property and Equipment: | ||||||||
Oil and gas properties, successful efforts method of accounting | 272,892 | 90,151 | ||||||
Drilling and trucking equipment | 3,965 | — | ||||||
Other | 1,147 | 336 | ||||||
Total property and equipment | 278,004 | 90,487 | ||||||
Less accumulated depreciation and depletion | (21,665 | ) | (12,669 | ) | ||||
Net property and equipment | 256,339 | 77,818 | ||||||
Long term assets: | ||||||||
Investment in LNG project | 1,022 | — | ||||||
Deferred financing costs | 131 | 117 | ||||||
Partnership net assets | 259 | 245 | ||||||
Total long term assets | 1,412 | 362 | ||||||
| $ | 272,704 | $ | 86,847 | |||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities: | ||||||||
Current portion of long-term debt | $ | 109 | $ | 10,039 | ||||
Accounts payable | 12,326 | 3,604 | ||||||
Other accrued liabilities | 1,855 | 1,087 | ||||||
Derivative instruments | — | 468 | ||||||
Current foreign tax payable | — | 703 | ||||||
Total current liabilities | 14,290 | 15,901 | ||||||
Long-term Liabilities: | ||||||||
Bank debt, net | 69,375 | 22,175 | ||||||
Asset retirement obligation | 2,542 | 868 | ||||||
Other debt, net | 255 | — | ||||||
Total long-term liabilities | 72,172 | 23,043 | ||||||
Minority Interest | 245 | — | ||||||
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 38,447,000 shares at June 30, 2004 and 23,286,000 shares at June 30, 2003 | 384 | 233 | ||||||
Additional paid-in capital | 207,811 | 75,642 | ||||||
Accumulated other comprehensive (loss) income | 342 | (376 | ) | |||||
Accumulated deficit | (22,540 | ) | (27,596 | ) | ||||
Total stockholders’ equity | 185,997 | 47,903 | ||||||
Commitments and contingencies | $ | 272,704 | $ | 86,847 | ||||
See accompanying notes to consolidated financial statements.
F-2
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| Years Ended June 30, | ||||||||||||
| 2004 | 2003 | 2002 | ||||||||||
| (In thousands, except per share amounts) | ||||||||||||
Revenue: | ||||||||||||
Oil and gas sales | $ | 37,235 | $ | 22,576 | $ | 8,013 | ||||||
Realized gain (loss) on derivative instruments, net | (859 | ) | (1,858 | ) | 39 | |||||||
Total revenue | 36,376 | 20,718 | 8,052 | |||||||||
Operating expenses: | ||||||||||||
Production costs | 9,776 | 8,410 | 4,257 | |||||||||
Drilling and trucking operations | 232 | — | — | |||||||||
Exploration expense | 2,406 | 140 | 155 | |||||||||
Depreciation and depletion | 9,914 | 4,999 | 3,326 | |||||||||
Dry hole costs | 2,132 | 537 | 396 | |||||||||
Abandoned and impaired oil and gas properties | — | — | 1,480 | |||||||||
Professional fees | 1,174 | 842 | 1,322 | |||||||||
General and administrative (includes stock compensation of $329,000, $123,000 and $143,000 for the years ended June 30, 2004, 2003 and 2002 respectively.) | 6,875 | 4,295 | 2,060 | |||||||||
Total operating expenses | 32,509 | 19,223 | 12,996 | |||||||||
Income (loss) from continuing operations | 3,867 | 1,495 | (4,944 | ) | ||||||||
Other income and (expense): | ||||||||||||
Other income | 122 | 31 | 113 | |||||||||
Minority interest | 70 | — | — | |||||||||
Interest and financing costs | (1,762 | ) | (1,767 | ) | (1,325 | ) | ||||||
Total other expense | (1,570 | ) | (1,736 | ) | (1,212 | ) | ||||||
Income (loss) before discontinued operations and cumulative effect of change in accounting principle | $ | 2,297 | $ | (241 | ) | $ | (6,156 | ) | ||||
Discontinued operations: | ||||||||||||
Income (loss) from operations of properties sold, net | 872 | 1,241 | (9 | ) | ||||||||
Gain (loss) on sale of properties | 1,887 | 277 | (88 | ) | ||||||||
Income (loss) before cumulative effect of change in accounting principle | 5,056 | 1,277 | (6,253 | ) | ||||||||
Cumulative effect of change in accounting principle | — | (20 | ) | — | ||||||||
Net income (loss) | $ | 5,056 | $ | 1,257 | $ | (6,253 | ) | |||||
Basic income (loss) per common share: | ||||||||||||
Income (loss) before discontinued operations and cumulative effect of change in accounting principle | $ | .09 | $ | (.01 | ) | $ | (.49 | ) | ||||
Discontinued operations | .10 | .06 | * | |||||||||
Income (loss) before cumulative effect of change in accounting principle | .19 | .05 | (.49 | ) | ||||||||
Cumulative effect of change in accounting principle | — | * | — | |||||||||
Net income (loss) | $ | .19 | $ | .05 | $ | (.49 | ) | |||||
Diluted income (loss) per common share: | ||||||||||||
Income (loss) before discontinued operations and cumulative effect of change in accounting principle | $ | .08 | $ | (.01 | ) | $ | (.49 | ) | ||||
Discontinued operations | .09 | .06 | * | |||||||||
Income (loss) before cumulative effect of change in accounting principle | .17 | .05 | (.49 | ) | ||||||||
Cumulative effect of change in accounting principle | — | * | — | |||||||||
Net income (loss) | $ | .17 | $ | .05 | $ | (.49 | ) | |||||
| * | Less than $.01 per common |
See accompanying notes to consolidated financial statements.
F-3
AND SUBSIDIARIES
Consolidated Statement of Stockholders' Changes in Stockholders’
Equity and Comprehensive Income (Loss)
Years Ended June 30, 2002, 2001 and 2000
Accumulated
other
Compre-
Common Stock Additional Put Option hensive
-------------------- paid-in on income Comprehensive Accumulated
Shares Amount capital Delta stock (loss) income (loss) deficit Total
---------- -------- ----------- ------------ --------- ------------- ----------- ----------
Balance, July 1, 2000 6,390,000 $ 64,000 29,476,000 - (115,000) (19,578,000) 9,847,000
Comprehensive loss:
Net loss - - - - (3,367,000) (3,367,000) (3,367,000)
----------
Other comprehensive
loss, net of tax
Unrealized gain on
equity securities - - - - 79,000 -
Less: Reclassification
adjustment for
losses included
in net loss - - - - 13,000 192,000 192,000
----------
Comprehensive loss - - - - - (3,175,000)
==========
Stock options granted
as compensation - - 500,000 - - - 500,000
Shares issued for cash,
net of commissions 603,000 6,000 1,018,000 - - - 1,024,000
Shares issued for cash
upon exercise of options 1,049,000 10,000 1,368,000 - - - 1,378,000
Shares and options issued
with financing 75,000 1,000 565,000 - - - 566,000
Shares issued for oil and
gas properties 215,000 2,000 548,000 - - - 550,000
Shares issued for deposit
on oil and gas properties 90,000 1,000 272,000 - - - 273,000
---------- -------- ---------- --------- -------- ----------- ----------
Balance, July 1, 2000 8,422,000 $ 84,000 33,747,000 - 77,000 (22,945,000) 10,963,000
Comprehensive loss:
Net loss - - - - - 345,000 345,000 345,000
----------
Other comprehensive
loss, net of tax
Unrealized gain on
equity securities - - - - (8,000) (8,000) (8,000)
----------
Comprehensive loss - - - - - 337,000
==========
Stock options granted
as compensation - - 520,000 - - - 520,000
Fair value of warrants
issued for common stock
investment agreement - - 1,436,000 - - - 1,436,000
Warrant issued in exchange
for common stock
investment agreement - - (1,436,000) - - - (1,436,000)
Shares issued for cash,
net of commissions 1,004,000 10,000 2,412,000 - - - 2,422,000
Shares issued for cash
upon exercise of options 922,000 9,000 1,471,000 - - - 1,480,000
Conversion of note
payable and accrued
interest to common stock 200,000 2,000 509,000 - - - 511,000
Shares issued for oil and
gas properties 851,000 9,000 2,945,000 - - - 2,954,000
Shares reacquired and
retired (239,000) (2,000) (904,000) - - - (906,000)
---------- -------- ---------- --------- -------- ----------- ----------
Balance, June 30, 2001 11,160,000 112,000 40,700,000 - 69,000 (22,600,000) 18,281,000
F-4
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (Loss)
Years Ended June 30, 2002, 2001 and 2000
Accumulated
other
Compre-
Common Stock Additional Put Option hensive
-------------------- paid-in on income Comprehensive Accumulated
Shares Amount capital Delta stock (loss) income (loss) deficit Total
---------- -------- ----------- ------------ --------- ------------- ----------- ----------
Comprehensive loss:
Net loss - - - - - (6,253,000) (6,253,000) (6,253,000)
----------
Other comprehensive
loss, net of tax
Unrealized loss on
equity securities - - - - (154,000) (154,000) (154,000)
----------
Comprehensive income - - - - - (6,407,000)
==========
Stock options granted
as compensation - - 143,000 - - - 143,000
Shares issued for cash,
net of commissions 72,000 1,000 224,000 - - - 225,000
Shares issued for cash
upon exercise of options 266,000 2,000 405,000 - - - 407,000
Shares issued for
services 14,000 - 48,000 - - - 48,000
Shares issued for oil
and gas properties 9,703,000 97,000 26,862,000 - - - 26,959,000
Put option on Delta
stock - - 2,886,000 (2,886,000) - -
Shares issued for all
outstanding shares of
Piper Petroleum Company 1,377,000 14,000 5,220,000 - - - 5,234,000
Shares issued for debt 51,000 - 157,000 - - - 157,000
Shares reacquired and
retired (25,000) - (131,000) - - - (131,000)
---------- -------- ----------- ---------- -------- ----------- -----------
Balance, June 30, 2002 22,618,000 $226,000 76,514,000 (2,886,000) (85,000) (28,853,000) 44,916,000
========== ======== ========== ========== ======== =========== ===========
| Common stock | Additional capital | Put option on Delta stock | Accumulated income/(loss) | Comprehensive income (loss) | Accumulated deficit | Total | |||||||||||||||||||||||
| Shares | Amount | ||||||||||||||||||||||||||||
| (In thousands, except per share amounts) | |||||||||||||||||||||||||||||
Balance July 1, 2001 | 11,160 | $ | 112 | $ | 40,700 | $ | — | $ | 69 | $ | (22,600 | ) | $ | 18,281 | |||||||||||||||
Comprehensive loss: | |||||||||||||||||||||||||||||
Net loss | — | — | — | — | — | (6,253 | ) | (6,253 | ) | (6,253 | ) | ||||||||||||||||||
Other comprehensive loss, net of tax | |||||||||||||||||||||||||||||
Unrealized loss on equity securities | — | — | — | — | (154 | ) | (154 | ) | (154 | ) | |||||||||||||||||||
Comprehensive loss | — | — | — | — | — | (6,407 | ) | ||||||||||||||||||||||
Stock options granted as compensation | — | — | 143 | — | — | — | 143 | ||||||||||||||||||||||
Shares issued for cash, net of commissions | 72 | 1 | 224 | — | — | — | 225 | ||||||||||||||||||||||
Shares issued for cash upon exercise of options | 266 | 2 | 405 | — | — | — | 407 | ||||||||||||||||||||||
Shares issued for services | 14 | — | 48 | — | — | — | 48 | ||||||||||||||||||||||
Shares issued for oil and gas properties | 9,703 | 97 | 26,862 | — | — | — | 26,959 | ||||||||||||||||||||||
Put option on Delta Stock | — | — | 2,886 | (2,886 | ) | — | — | — | |||||||||||||||||||||
Shares issued for all outstanding shares of Piper Petroleum Company | 1,377 | 14 | 5,220 | — | — | — | 5,234 | ||||||||||||||||||||||
Shares issued for debt | 51 | — | 157 | — | — | — | 157 | ||||||||||||||||||||||
Shares reacquired and retired | (25 | ) | — | (131 | ) | — | — | — | (131 | ) | |||||||||||||||||||
Balance, June 30, 2002 | 22,618 | 226 | 76,514 | (2,886 | ) | (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 equity securities, net | — | — | — | — | 177 | 177 | — | 177 | |||||||||||||||||||||
Comprehensive income | — | — | — | — | — | 966 | |||||||||||||||||||||||
Stock options granted as compensation | 124 | — | — | — | 124 | ||||||||||||||||||||||||
Put option on Delta Stock | — | — | (2,886 | ) | 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 comprehensive gain, net of tax | |||||||||||||||||||||||||||||
Change in fair value of derivative hedging instruments | — | — | — | — | 468 | 468 | — | 468 | |||||||||||||||||||||
Unrealized gain on equity 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 | |||||||||||||||
See accompanying notes to consolidated financial statements.
F-5
AND SUBSIDIARY
SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended June 30,
2002 2001 2000
------------ ------------ -----------
Cash flows operating activities:
Net income (loss) $ (6,253,000) $ 345,000 $(3,367,000)
Adjustments to reconcile net income (loss) to cash
used in operating activities:
Depreciation and depletion 3,347,000 2,533,000 888,000
Stock option expense 143,000 520,000 500,000
Amortization of financing costs 582,000 506,000 467,000
Abandoned and impaired properties 1,480,000 798,000 -
(Gain) loss on sale of oil and gas properties 88,000 (458,000) (75,000)
Loss on sale of securities available for sale - - 113,000
Shares issued for services 48,000 - -
Net changes in operating assets and operating
liabilities:
(Increase) decrease in trade accounts receivable (1,265,000) (1,204,000) (553,000)
Increase in prepaid assets (191,000) (221,000) (373,000)
(Increase) decrease in other current assets (6,000) 66,000 (63,000)
Decrease in accounts payable trade 172,000 222,000 1,243,000
(Increase) decrease in other accrued liabilities (15,000) (269,000) 144,000
Deferred revenue - (59,000) (69,000)
------------ ------------ -----------
Net cash provided by (used in) operating activities $ (1,870,000) $ 2,779,000 $(1,145,000)
------------ ------------ -----------
Cash flows from investing activities:
Additions to property and equipment, net (17,959,000) (11,613,000) (7,760,000)
Deposit on purchase of oil and gas properties - - (6,000)
Proceeds from sale of oil and gas properties 4,313,000 3,700,000 75,000
Proceeds from sale of securities available for sale - - 135,000
Merger with Piper Petroleum 74,000 - -
(Increase) decrease in long term assets 460,000 (169,000) (675,000)
------------ ------------ -----------
Net cash used in investing activities (13,112,000) (8,082,000) (8,231,000)
------------ ------------ -----------
Cash flows from financing activities:
Stock issued for cash upon exercise of options 407,000 1,480,000 1,378,000
Issuance of common stock for cash 225,000 2,422,000 1,024,000
Proceeds from borrowings 21,778,000 14,394,000 12,817,000
Repayment of borrowings and financing costs (6,922,000) (12,777,000) (5,640,000)
------------ ------------ -----------
Net cash provided by financing activities 15,488,000 5,519,000 9,579,000
------------ ------------ -----------
Net increase in cash 506,000 216,000 203,000
------------ ------------ -----------
Cash at beginning of period 518,000 302,000 99,000
------------ ------------ -----------
Cash at end of period $ 1,024,000 $ 518,000 $ 302,000
------------ ------------ -----------
Supplemental cash flow information -
Cash paid for interest and financing costs $ 779,000 $ 1,677,000 $ 741,000
============ ============ ===========
Non-cash financing activities:
Shares issued for all outstanding shares of
Piper Petroleum Company $ 5,234,000 $ - $ -
============ ============ ===========
Common stock issued for the purchase
of oil and gas properties, net of return of
deposited shares $ 26,959,000 $ 2,954,000 $ 823,000
============ ============ ===========
Shares reacquired and retired for
oil and gas properties and option exercise $ 131,000 $ 906,000 $ -
============ ============ ===========
Common stock issued for note payable
and accrued interest or accounts payable $ 157,000 $ 511,000 $ -
============ ============ ===========
Common stock, options and overriding royalties
issued for services relating to debt financing $ - $ 330,000 $ 891,000
============ ============ ===========
| Years Ended June 30, | ||||||||||||
| 2004 | 2003 | 2002 | ||||||||||
| (In thousands) | ||||||||||||
Cash flows operating activities: | ||||||||||||
Net income (loss) | $ | 5,056 | $ | 1,257 | $ | (6,253 | ) | |||||
Adjustments to reconcile net income (loss) to cash used in operating activities: | ||||||||||||
Depreciation and depletion | 9,854 | 4,942 | 3,326 | |||||||||
Depreciation and depletion – discontinued operations | 328 | 791 | 21 | |||||||||
Accretion of abandonment obligation | 60 | 57 | — | |||||||||
Stock compensation expense | 329 | 124 | 143 | |||||||||
Amortization of financing costs | 324 | 456 | 582 | |||||||||
Minority interest | (70 | ) | — | — | ||||||||
Abandoned and impaired properties | — | — | 1,480 | |||||||||
(Gain) loss on sale of oil and gas properties | (1,887 | ) | (277 | ) | 88 | |||||||
Shares issued for services | — | — | 48 | |||||||||
Cumulative effect of change in accounting principle | — | 20 | — | |||||||||
Net changes in operating assets and operating liabilities: | ||||||||||||
Increase in trade accounts receivable | (4,878 | ) | (101 | ) | (1,265 | ) | ||||||
(Increase) decrease in prepaid assets | (372 | ) | 21 | (191 | ) | |||||||
Increase in inventory | (1,350 | ) | — | — | ||||||||
(Increase) decrease in other current assets | 205 | (78 | ) | (6 | ) | |||||||
Increase in accounts payable | 1,361 | 116 | 172 | |||||||||
Increase (decrease) in other accrued liabilities | 663 | 671 | (15 | ) | ||||||||
Net cash provided by (used in) operating activities | 9,623 | 7,999 | (1,870 | ) | ||||||||
Cash flows from investing activities: | ||||||||||||
Additions to property and equipment, net | (158,504 | ) | (15,637 | ) | (17,959 | ) | ||||||
Proceeds from sale of oil and gas properties | 10,787 | 850 | 4,313 | |||||||||
Merger with Piper Petroleum | — | — | 74 | |||||||||
Minority interest contributions | 315 | — | — | |||||||||
Payment on investment transaction | (1,022 | ) | — | — | ||||||||
Increase (decrease) in long term assets | (14 | ) | 139 | 460 | ||||||||
Net cash used in investing activities | (148,438 | ) | (14,648 | ) | (13,112 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Stock issued for cash upon exercise of options | 3,563 | 975 | 407 | |||||||||
Issuance of common stock for cash | 97,902 | — | 225 | |||||||||
Proceeds from borrowings | 69,979 | 9,000 | 21,778 | |||||||||
Payment of financing fees | (368 | ) | (354 | ) | (249 | ) | ||||||
Repayment of borrowings | (32,454 | ) | (1,725 | ) | (6,673 | ) | ||||||
Net cash provided by financing activities | 138,622 | 7,896 | 15,488 | |||||||||
Net (decrease) increase in cash and cash equivalents | (193 | ) | 1,247 | 506 | ||||||||
Cash at beginning of period | 2,271 | 1,024 | 518 | |||||||||
Cash at end of period | $ | 2,078 | $ | 2,271 | $ | 1,024 | ||||||
Supplemental cash flow information – Cash paid for interest and financing costs | $ | 1,818 | $ | 1,312 | $ | 779 | ||||||
Non-cash financing activities: | ||||||||||||
Common stock issued for the purchase of oil and gas properties | $ | 30,526 | $ | 922 | $ | 26,959 | ||||||
Common stock issued for all outstanding shares of Piper Petroleum Company | $ | — | $ | — | $ | 5,234 | ||||||
Common stock reacquired and retired for oil and gas properties and option exercise | $ | — | $ | — | $ | 131 | ||||||
Common stock issued for note payable and accrued interest or accounts payable | $ | — | $ | — | $ | 157 | ||||||
See accompanying notes to consolidated financial statements.
F-6
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
2002
(1) SummaryNature of Significant Accounting Policies
Organization and Principles of Consolidation
Delta Petroleum Corporation ("Delta"(“Delta”) was organized December 21, 1984 and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. 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.
At June 30, 20022004 the Company owned 4,277,977 shares of the common stock of Amber Resources Company ("Amber"(“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company also engaged in
acquiring, exploring, developing and producingthat owns undeveloped oil and gas properties.
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"(“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. Piper was merged into a subsidiary wholly owned by Delta.
The Company’s results of operations are substantially dependent on the price received for its crude oil and natural gas products and the results of our exploration and development activities. Prices for these products are subject to fluctuations in response to changes in supply, market uncertainty and political instability.
(2) Summary of Significant Accounting Policies
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of Delta, Amber and Piper (collectively, the Company). All intercompany balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders'shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber'sAmber’s earnings/losses for all periods. Liquidity
The Company has incurred losses from operations overCertain reclassifications have been made to amounts reported in previous years to conform to the past
several years coupled with significant deficiencies in cash flow from
operations, with the exception of fiscal 2001. As of June 30, 2002,2004 presentation.
In March 2004, the Company hadacquired a working capital deficit50% interest in Big Dog Drilling, LLC (“BDDC”) and a 50% interest in Shark Trucking Company, LLC (“STC”). Delta controls both entities and has consolidated the activities of $271,000.
During fiscal 2002, the Company has taken steps to reduce lossesboth BDDC and generate cash flow fromSTC in 2004. The results of operations through the acquisition of Piper and all of
the domestic oil and gas properties of Castle Energy Corporation ("Castle").
(See acquisition discussions in Note 3.) The Company believes these
acquisitions will provide sufficient cash flow to meet its obligations in a
timely manner.
F-7
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(1) Summary of Significant Accounting Policies, Continued
minority interest were not significant.
Cash Equivalents
Cash equivalents consist of money market funds. For purposes of the
statements of cash flows, theThe Company considers all highly liquid investments with maturities at date of acquisition of three months or less to be cash equivalents.
Marketable Securities
The Company classifies its investment securities as available-for-
saleavailable-for-sale securities. Pursuant to Statement of Financial Accounting Standards 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.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(2) Summary of Significant Accounting Policies, Continued
| Cost | Unrealized Gain (Loss) | Estimated Market Value | ||||||||
| (In thousands) | ||||||||||
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 | |||||
June 30, 2002 | ||||||||||
Bion Environmental Technologies, Inc. | $ | 152 | $ | (92 | ) | $ | 60 | |||
Tipperary Oil & Gas Company | 418 | 7 | 425 | |||||||
| $ | 570 | $ | (85 | ) | $ | 485 | ||||
Inventories
Inventories consist of pipe, other production equipment and natural as placed in storage. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value.
Revenue Recognition
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, 2004 and 2003, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.
Property and Equipment
The Company followsaccounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting for
its oilaccounting. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas activities. Accordingly,lease acquisition costs associated with the
acquisition, drilling,are also capitalized. Exploration costs, including personnel costs, certain geological geophysical expenses and equipping of successful exploratory wells are
capitalized.
Geologicaldelay rentals for gas and geophysical costs, delay and surface rentals and
drilling costs of unsuccessful exploratory wellsoil leases, are charged to expense as incurred. CostsExploratory 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 drilling development wells, both successfula partial interest in a proved property is accounted for as a cost recovery and unsuccessful, are capitalized.
Upon the sale or retirement of oil and gas properties, the cost
thereof and the accumulated depreciation and depletion are removed from the
accounts and anyno gain or loss is creditedrecognized 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 operations.
F-8
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notesexpense. If the unproved properties are determined to Consolidated Financial Statements
June 30, 2002, 2001be productive, the related costs are transferred to proved gas and 2000
(1) Summaryoil properties. Proceeds from sales of Significant Accounting Policies, Continued
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. Capitalized
costs
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(2) Summary of undeveloped properties are assessed periodically on an individual
field basis and a provision for impairment is recorded, if necessary, through
a charge to operations.
FurnitureSignificant Accounting Policies, Continued
Other property and equipment are recorded at cost or estimated fair value upon acquisition and depreciated using the straight-line method over their estimated lives ranging from three to five years.
useful lives.
Certain of the Company'sCompany’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'sCompany’s share of net working capital in such entities.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards No. 121 "Accounting144 “Accounting for the Impairment or Disposal of Long-Lived Assets and for Long-Lived Assets to be Disposed
of"Assets” (SFAS No. 121)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'smanagement’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. 121144 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'sasset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, the Company has recorded an $878,000no impairment provision attributable to certain producing properties for the yearyears ended June 30, 2002, $6,0002004 and 2003 and $878,000 for the year ended June 30, 2001 and no impairment provision
for the year ended June 30, 2000.
2002.
For undeveloped properties, the need for an impairment reserve is based on the Company'sCompany’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 F-9
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(1) Summary of Significant Accounting Policies, Continued
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 anno impairment provision attributable to certain undeveloped properties of $602,000 for the yearyears ended June 30, 2002, $168,000 for the year
ended June 30, 2001,2004, 2003 and had no impairment for the year ended June 30, 2000.
2002.
In addition, the Company recorded an impairment provision attributed to certain undeveloped foreign properties of $624,000$602,000 for the year ended June 30, 20012002 and had no similar foreign impairment for the other periods presented.
Gas Balancingyears ended June 30, 2004 and 2003.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(2) Summary of Significant Accounting Policies, Continued
Asset Retirement Obligations
In July 2001, the Financial Accounting Standards Board 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 uses the sales methodadopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting for gas balancingprinciple on prior years of gas production. Under this method, all proceeds from production when
delivered to a third party pipeline which are credited$20,000, net of tax effects, related to the Company are
recorded as revenue until such time asdepreciation and accretion expense that would have been reported had the Company has produced its sharefair value of the total estimated reservesasset retirement obligations, and corresponding increase in the carrying amount of the property. Thereafter, additional amounts
received arerelated long-lived assets, been recorded as a liability. At June 30, 2002,when incurred. The Company’s asset retirement obligations arise from the Company had noplugging 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 outas the obligations remained with the seller. The following is a reconciliation of balance.
the Company’s asset retirement obligations for the years ended June 30, 2004 and 2003.
| Years Ended June 30, | ||||||
| 2004 | 2003 | |||||
| (In thousands) | ||||||
Asset retirement obligation – beginning of period | $ | 868 | $ 644 | |||
Accretion expense | 60 | 57 | ||||
Change in estimate | 438 | — | ||||
Obligations acquired | 1,522 | 181 | ||||
Obligations settled | (3 | ) | (14) | |||
Obligations on sold properties | (238 | ) | — | |||
Asset retirement obligation – end of period | 2,647 | 868 | ||||
Less: Current asset retirement obligation | (105 | ) | — | |||
Long-term asset retirement obligation | $ | 2,542 | $ 868 | |||
The pro forma effects of the application of SFAS No. 143 on net income would have been immaterial and there would have been no effect on earnings per share.
Derivative Financial Instruments
The Company may, from timeperiodically enters into commodity derivative contracts and fixed-price physical contracts to time in the ordinary course of
business, enter into non-speculative hedge arrangements, commodity swap
agreements, forward sale contracts, commodity futures, optionsmanage its exposure to oil and other
similar agreements relating to natural gas price volatility. The Company primarily utilizes future contracts, swaps or options which are generally placed with major financial institutions or with counterparties of high credit quality that the Company believes are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil.
oil and natural futures which have a high degree of historical correlation with actual prices received by the Company
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(2) Summary of Significant Accounting Policies, Continued
In June 1998, the Financial Accounting Standards Board ("FASB"(“FASB”) issued Statement of Financial Accounting Standards ("SFAS"(“SFAS”) No. 133, "Accounting“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'sderivative’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. SFAS 133 requires that a company must formally document,
designate, and assess the effectiveness of transactions that receive hedge
accounting.
F-10
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
At June 30, 2002, 20012004, the Company had no outstanding derivative financial instruments. At June 30, 2003, the Company had a current derivative liability and 2000
(1) Summarya corresponding accumulated other comprehensive loss of Significant Accounting Policies, Continued
$468,000.
Stock Option Plans
The Company accounts for its stock option plans in accordance with the provisions of Accounting Principles Board ("APB"(“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. The
Company adoptedIn December, 2002 the disclosure requirement ofFASB issued SFAS No. 148, “Accounting for Stock-based Compensation-Transition and Disclosure.” SFAS 148 amends FASB Statement No. 123, Accounting“Accounting for Stock-Based Compensation, and provides pro forma net income (loss) and pro
forma earnings (loss) per share disclosuresCompensation” to provide alternative methods of transition for employee stock option grants
made as ifa voluntary change to the fair-value based method definedof 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 provisions of SFAS No. 123 had148 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 applied.
determined using the fair value of the options at the grant date, the Company’s net income (loss) for the years ended June 30, 2004, 2003 and 2002 would have been as follows:
| Year Ended June 30, | ||||||||||||
| 2004 | 2003 | 2002 | ||||||||||
| (In thousands, except per share amounts) | ||||||||||||
Net income (loss) | $ | 5,056 | $ | 1,257 | $ | (6,253 | ) | |||||
FAS 123 compensation effect | (4,316 | ) | (209 | ) | (790 | ) | ||||||
Net Income (loss) after FAS 123 compensation effect | $ | 740 | $ | 1,048 | $ | (7,043 | ) | |||||
Income (loss) per common share: | ||||||||||||
Basic | $ | .03 | $ | .05 | $ | (.55 | ) | |||||
Diluted | $ | .02 | $ | .04 | $ | (.55 | ) | |||||
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(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 carryforwards. 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 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. The effect of potentially dilutive securities outstanding was antidilutive during yearsyear ended June 30, 2002 and 2000.
F-11
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(1) Summary of Significant Accounting Policies, Continued
2002.
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 July 2001,January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities - an interpretation of ARB No. 51” (“FIN 46”). FIN 46 is an interpretation of Accounting Standards Board approvedResearch Bulletin 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (“VIE’s”). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, issuance SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS
No. 143entities over which control is achieved through means other than voting rights. Such entities are known as VIE’s. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both.
An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to variable interest entities created after January 31, 2003, and to record the fair value of a liability forvariable interest entities in which an asset
retirement obligationenterprise obtains an interest after that date. It applies in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset
and is effective forfirst fiscal yearsyear or interim period beginning after June 15, 2002. The Company
is currently assessing the impact SFAS No. 143 will have on its financial
condition and results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets,2003 to variable interest entities in which an enterprise holds a variable interest that superseded SFAS No. 121 and
APB Opinion No. 30. SFAS 144 provides guidance on differentiating between
assets held and used, held for sale, and held for disposal other than by sale,
and the required valuation of such assets. SFAS 144 is effective for fiscal
years beginning after December 15, 2001. The Company is currently assessing
the impact SFAS No. 144 will have on its financial condition and results of
operations.
Statement 145, Recission of FASB Statements No. 4, 44 and 64,
Amendment of FASB Statement No. 13, and Technical Corrections (SFAS No. 145)
was issued in April 2002. This statement rescinds SFAS No. 4, Reporting Gains
and Losses from Extinguishment of Debt, which required all gains and losses
from extinguishment of debt to be aggregated and, if material, classified as
an extraordinary item, net of income taxes. As a result, the criteria in APB
30 will now be used to classify those gains and losses. Any gain or loss on
the extinguishment of debt that was classified as an extraordinary item in
prior periods presented that does not meet the criteria in APB 30 for
classification as an extraordinary item shall be reclassified. The provisions
of this Statement are effective for fiscal years beginning after Januaryit acquired before February 1, 2003. The Company doesAt this time, we do not believe this statement will have a material impact
to the Financial Statements.
F-12
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(1) Summary of Significant Accounting Policies, Continued
Statement 146, Accounting for Exit or Disposal Activities (SFAS No.
146), was issued in June 2002. SFAS No. 146 addresses significant issues
regarding the recognition, measurement and reporting of disposal activities,
including restructuring activities that are currently accounted in EITF Issue
No. 94-3, "Liability Recognition for Certain Employee Termination Activity."
SFAS No. 146 will be effective in January 2003. The Company is currently
assessing the impact of SFAS No. 146.
Reclassification
Certain amounts in the 2001 and 2000 financial statements have been
reclassified to conform to the 2002 financial statement presentation.
(2)
(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 $9,722,000$10.8 million and $9,359,000,$10.2 million at June 30, 20022004 and 2001,2003, 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'sCompany’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'sCompany’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.
The ownership rights in each of these properties have been retained under various suspension notices issued by the Mineral Management Service (MMS) of the
F-13
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(2) Oil and Gas Properties, Continued U.S. Federal Government (MMS) whereby as long as the owners of each property were progressing toward defined milestone objectives, the owners'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. No such consistency determination has as yet been made.
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 California Coastal Zone Management Planning (CZMP)CZMA, and by the MMS for other technical requirements.
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.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(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, 20022004 and June 30, 20012003 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. 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.
As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, and the leases are still valid. If the leases are found not to be valid for some reason, or if the United States either does not comply with the order requiring it to make a consistency determination or finds that development is inconsistent with the CZMA, 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.
On January 9, 2002, Deltathe 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 forty undeveloped federal leases, some of which are part of Delta'sthe Company’s Offshore California properties. 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. Delta's claim (including the claim of its subsidiary Amber
Resources Company) for lease bonuses and rentals paid by Delta and its
predecessors is in excess of $152,000,000. In addition, its claim for
exploration costs and related expenses will also be substantial. 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 F-14
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(2) Oil and Gas Properties, Continued
to the Coastal Zone Management ActCZMA 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 forty
undeveloped leases are located insuit seeks compensation for the Offshore Santa Maria Basin off the coast
of Santa Barbaralease bonuses and San Luis Obispo counties, and in the Santa Barbara
Channel off Santa Barbara and Ventura counties. None of these leases are
currently impaired, but in the event that there is some future adverse ruling
by the California Coastal Commission under the Coastal Zone Management Act and
Delta decides not to appeal such rulingrentals paid to the SecretaryFederal 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 Commerce, or the
Secretary of Commerce either refuses to hear Delta's appeal of any such ruling
or ultimately makes a determination adverse to Delta, it is likely that some
or all of these leases would become impaired and written off at that time.$152 million. In addition, it shouldThe Company’s claim for exploration costs and related expenses will also be noted that Delta's pending litigation against the
United States is predicated on the ruling of the lower court in California v.
Norton. The United States has appealed the decision of the lower court to the
9th Circuit Court of Appeals.substantial. In the event, however, that the United StatesCompany 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.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(3) Oil and Gas Properties, continued
Fiscal 2004 – Significant Acquisitions
On June 29, 2004, the Company acquired substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc (“Alpine”) for a total purchase price of $120.6 million, net of a $1.9 million downward purchase price adjustment, which reflect the net revenues after operating costs and related acquisition costs from the effective date of June 1, 2004 through closing at June 29, 2004. Alpine was a privately held exploration and production company, active primarily in South East Texas and Louisiana. Based on a preliminary valuation assessment, the total acquisition cost was allocated $38 million to proved developed producing, $73.9 million to proved undeveloped and $8.7 to unproved properties. See sale of oil and gas properties in Note 15.
On September 19, 2003, the Company completed an acquisition of certain producing and drilling prospects in Colorado (the “South Tongue Prospect”) and Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, “Davis”), pursuant to the terms of a Purchase and Sale Agreement effective as of August 1, 2003. The total consideration paid for these properties was 1,000,000 shares of the Company’s common stock, $8 million, of which $2 million was paid in cash and $6 million in the form of a short-term promissory note payable that was paid on October 3, 2003 and 26,000 shares of the Company’s common stock to an unrelated individual who introduced the two parties. The shares issued were recorded at a price of $5.15 per share, a five day average surrounding the announcement of the transaction. The Company recorded an upward purchase price adjustment of approximately $220,000 which reflects the operating and acquisition related costs in excess of net revenue from the effective date of August 1, 2003 through the closing date of September 19, 2003. The total acquisition cost of $13.1 million was allocated between proved developed producing of $5.2 million and unproved undeveloped of $7.9 million based on preliminary information.
On April 22, 2004, the Company amended its agreement with Davis to, among other things, add certain oil and gas leases located in Colorado known as the “North Tongue Prospect,” decrease the amount of Davis’s reversionary working interest after payout in the properties acquired under the initial agreement from 50% to 42.5%, change the definition of payout, change certain drilling obligations and modify the Company’s obligation to issue additional shares of stock to Davis upon the designation of Bonus Prospects. The initial consideration required to be paid to Davis upon execution of the Amended Agreement was 1,525,000 shares of the Company’s common stock, valued at $17.3 million. The entire amount was allocated to unproved undeveloped properties.
The amended agreement eliminates the Company’s obligation to issue shares for Bonus Prospects that existed under the initial agreement with respect to the South Tongue Prospect, but it added a new obligation to issue additional shares for Bonus Prospects that are designated with respect to the North Tongue Prospect. With regard to the North Tongue Prospect only, for any prospect that is identified at any time after drilling, coring, testing and logging to contain in combination from specified formations at least one million barrels of recoverable oil or six billion cubic feet of recoverable gas or a combination of oil or gas equal to or exceeding one million barrels of oil equivalent using a six million cubic feet to one barrel gas-to-oil ratio, as determined by independent engineers, then such acreage is required to be designated as a “Bonus Prospect.”
Upon designation of a Bonus Prospect, the Company is required to issue to Davis as additional purchase price, up to 190,000 shares of the Company’s common stock, or such lesser amount so that the value of such stock based upon the average closing price of the stock for the immediately preceding 30-day period may equal but does not exceed $950,000, for each Bonus Prospect (a “Bonus”). This requirement applies only to the North Tongue Prospect and is limited to a maximum of five Bonus Prospects. No Bonus or additional shares are payable for prospects located on the South Tongue Prospect, regardless of potential or ultimate production. The Company is obligated to file additional registration statements at the Company’s expense covering the re-sale of each issuance of shares for each Bonus Prospect designation.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(3) Oil and Gas Properties, Continued
The following unaudited pro forma consolidated statements of operations information assumes that the Alpine and Davis property acquisitions occurred as of July 1, 2002:
| Years Ended June 30, | ||||||
| 2004 | 2003 | |||||
| (In thousands, except per share amounts) | ||||||
Oil and gas sales | $ | 69,683 | $ | 58,433 | ||
Net income, net of tax | $ | 14,246 | $ | 15,796 | ||
Net income per common share: | ||||||
Basic | $ | .43 | $ | .53 | ||
Diluted | $ | .40 | $ | .51 | ||
The above unaudited adjusted Pro Forma Consolidated Statements of Operations, based on the historical producing property operating results of Alpine, Davis and Delta’s adjusted for Delta’s proforma depletion, an estimate of additional administrative costs and approximately $3 million of pro forma income tax expense in 2004 are not necessarily indicative of the results of operations if Delta would have acquired the Alpine and Davis properties at July 1, 2002.
Fiscal 2004 – Additional Acquisitions
On December 10, 2003, the Company completed an acquisition of certain production and acreage located primarily in Eland and Stadium fields in Stark County, North Dakota, from Sovereign Holdings, LLC, a privately - held Colorado limited liability company (“Sovereign”), pursuant to the terms of a Purchase and Sale Agreement effective as of December 1, 2003. The total consideration paid for these properties was 773,500 shares of the Company’s common stock. The shares issued were recorded at a price of $5.58, a five day average surrounding the closing of the transaction. The Company recorded a downward purchase price adjustment of approximately $84,000 which reflects the operating and acquisition related costs in excess of net revenue from the effective date of December 1, 2003 through the closing date of December 5, 2003. The total acquisition cost of $4.2 million was allocated to proved developed producing properties.
On February 24, 2004, the Company acquired certain properties in Texas from Labyrinth Enterprises, LLC, an unrelated entity, for $1.5 million in cash and 185,000 shares of the Company’s common stock valued at $1.6 million based on a five day average surrounding the closing of the transaction.
On February 26, 2004, the Company acquired approximately 135,000 leasehold acres in the Columbia River Basin project in eastern Washington from an unrelated entity for $1.4 million in cash. The Company will become the operator once drilling begins on this acreage. Subsequent to the quarter end, the Company purchased approximately 23,000 additional net acreage in this project through State and Federal lease sales.
In March 2004, the Company acquired a 50% interest in Big Dog Drilling Company, LLC (“BDDC”) for an initial investment of approximately $3 million. The remaining interest is owned by Davis. BDDC’s primary assets include two drilling rigs rated at drilling depths of up to 10,000 feet and certain additional drilling equipment.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(3) Oil and Gas Properties, Continued
Also in March 2004, the Company acquired a 50% interest in Shark Trucking Company, LLC (“STC”) for an initial investment of approximately $276,000. STC has a similar ownership structure to that of BDDC. STC’s primary assets include the ownership of trucking equipment used for the mobilization of drilling rigs and equipment.
The drilling rigs and trucking company will be used primarily for drilling activities on Delta’s properties. Increasing drilling rig rates, periodic lack of availability of drilling rigs and increased drilling by Delta were contributing factors to this venture.
On April 21, 2004, the Company acquired a fifty percent interest in approximately 1,300 leasehold acres in the Midway Loop Project located in Polk County, Texas from Wilsource Enterprises, LLC for $340,000 and 31,250 shares of the Company’s common stock valued at $289,000.
Also on April 21, 2004, the Company acquired a seventy five percent interest in approximately 9,800 leasehold acres in the Divide Creek Extension Project located in Mesa County, Colorado from Wilsource Enterprises, LLC for $90,000 in cash and 187,500 shares of the Company’s common stock valued at $1.7 million.
During the current fiscal year, the Company agreed to invest an aggregate of $1 million for a 6.25% interest as a member of 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 an existing platform located offshore California. If the limited liability company is successful in its appeal(s)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 the lower court's decisiondate of this report, the limited liability company had not yet engaged in any revenue generating activities. The Company has accounted for its investment at cost. This investment is recorded under Long term assets.
Fiscal 2003 - Acquisitions
On June 20, 2003, the Norton caseCompany acquired producing oil and gas interests and related undeveloped acreage in Kansas from JAED Production Company “JAED”, an unrelated entity. The Company paid $9 million and issued 200,000 shares of common stock. The shares issued were recorded at a stock price of $4.61, a five day average closing price surrounding the pending litigation with Delta is not settled, it would be necessary
for Delta to reevaluate whetherannouncement of the leases should be considered impaired at
that time. Astransaction. The Company recorded a purchase price adjustment of approximately $291,000 which reflects the ruling innet revenues after operating costs and acquisition related costs from the Norton case currently stands, the United
States has been ordered to make a consistency determination under the Coastal
Zone Management Act, but the leases are still valid. Ifeffective date of June 1, 2003 through the appellate
process the leases are found notclosing date of June 20, 2003. The total acquisition cost of $9.6 million was allocated between proved developed producing of $7.6 million and proved undeveloped of $2 million.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to be valid for some reason, or if the United
States is finally ordered to make a consistency determinationConsolidated Financial Statements
June 30, 2004, 2003 and either does
not do so or finds that development is inconsistent with the Coastal Zone
Management Act, it would appear that the leases would become impaired even
though Delta would undoubtedly proceed with its litigation. It is also
possible that other events could occur during the appellate process that would
cause the leases to become impaired,2002
(3) Oil and Delta will continuously evaluate
those factors as they occur.Gas Properties, Continued
Fiscal 2002 - Acquisitions - 2002
On February 19, 2002, Delta completed the acquisition of Piper Petroleum Company ("Piper"(“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. Delta issued 1,377,240 shares of restricted common stock for 100% of the shares of Piper. The 1,377,240 shares of restricted common stock waswere valued at approximately $5,234,000$5.2 million based on the five-day average closing price surrounding the announcement of the merger. In addition, Delta issued 51,000 shares for the cancellation of certain debt of Piper. As a result of the acquisition, the Company acquired Piper'sPiper’s working
F-15
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(2) Oil and Gas Properties, Continued and royalty interests in over 700 gross (4.6 net) wells which are primarily located in Texas, Oklahoma and Louisiana along with a 5% working interest in the Comet Ridge coal bed methane gas project in Queensland, Australia. On May 24, 2002 the Company completed the sale of our undivided interests in Australia, to Tipperary Corporation, in exchange for Tipperary'sTipperary’s producing properties in the West Buna Field (Hardin and Jasper counties, Texas)which had a fair market value of approximately $4,100,000,$4.1 million, $700,000 in cash, and 250,000 unregistered shares of Tipperary common stock. No gain or loss was recorded on this transaction. In addition, on May 28, 2002, the Company sold a commercial office building obtained in the merger with Piper located in Fort Worth, Texas to a non-affiliate for its fair value of $417,000. No gain or loss was recorded on this transaction. The total acquisition cost, net of purchase price adjustments, of approximately $4,803,000$4.8 million was allocated between proved developed producing of $3,882,000,$3.9 million, proved developed non-producing of $336,000, and proved undeveloped of $585,000. No gain or loss was recorded on
this transaction. Net daily production from the West Buna Field approximates 900,000 cubic feet equivalent.
On May 31, 2002, the Company acquired all of the domestic oil and gas properties of Castle Energy Corporation. The properties acquired from Castle consist of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. The Company issued 9,566,000 shares of Common Stock to Castle Energy Corporation as part of the purchase price. The shares issued were recorded at a stock price of $3.97, the closing stock price at May 31, 2002, discounted by 30% according to a fair market appraisal of Delta'sDelta’s stock obtained from Snyder & Company, an independent evaluationvaluation expert.
The Company iswas entitled to repurchase up to 3,188,667 of our shares from Castle for $4.50 per share for a period of one year after closing.closing (May 31, 2003). The Company did not repurchase its shares on May 31, 2003. This right is reflected in stockholders'stockholders’ equity at its fair value as a put option on Delta stock.stock until expiration. The Company'sCompany’s agreement with Castle was effective as of October 1, 2001 and the net operating revenues from the properties between the effective date and the May 31, 2002 closing date were recorded as an adjustment to the purchase price. As a part of the acquisition, upon closing, Delta granted an option to acquire a 4% working interest in the properties acquired for a cost of $878,000 to BWAB Limited Liability Company ("BWAB"(“BWAB”), a less than 10% shareholder of Delta. The difference between the $878,000 paid by BWAB which was less than fair value, and 4% of the cost of the Castle properties was treated as an additional acquisition cost by Delta for its consultation and assistance related to the transaction.
The Company recorded a purchase price adjustment of approximately $5,817,000$5.8 million which reflects the net revenues after operating costs and acquisition related costs from the effective date of October 1, 2001 through the closing date of May 31, 2002. The total acquisition cost of approximately $40,767,000$40.8 million 767,000 was allocated between proved developed producing of $32,614,000, proved developed non-producing of $3,396,000,$32.6 million and proved undeveloped of $4,757,000.$8.2 million. The Company recorded oil and gas revenues of $1,148,000$1.1 million and operating expenses of $485,000 for the month of June 2002 relating to these properties.
F-16
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(2)2002
(3) Oil and Gas Properties, Continued
In addition to the acquisitions described above, the Company acquired additional oil and gas properties in Colorado, Oklahoma and Texas during fiscal 2002. The consideration for these acquisitions was $667,000 and 137,476 shares of the Company'sCompany’s restricted common stock with a fair value of $375,000 based on the closingmarket price on the date of closing.
Acquisitions 2001
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 July 10, 2000,March 31, 2004, the Company paid $3,745,000, during fiscal 2000,
issued 90,000 sharescompleted the sale of all of our Pennsylvania properties to Castle Energy Corporation, a 25% shareholder of Delta at March 31, 2004, for cash consideration of $8 million, which the Company's common stock valued at approximately
$273,000 previously recorded asCompany believes is fair value, with an effective date of January 1, 2004 and resulted in a depositgain on sale of oil and gas properties and on
September 28, 2000, the Company paid $1,845,000 to acquire interests in 20
producing wells, 5 injection wells and acreage located in the Eland and
Stadium fields in Stark County, North Dakota ("North Dakota"). The July 10,
2000 and September 28, 2000 payments resulted in the acquisition by the
Company of 67% and 33%, respectively, of the ownership interest in each
property acquired. The $3,745,000 payment on July 10, 2000 was financed
through borrowings from an unrelated entity and personally guaranteed by two
of the Company's officers, while the payment on September 28, 2000 was
primarily paid out of the Company's net revenues$1.9 million. Revenues from the effective datesale of the acquisitions through closing. Delta also issued 100,000 shares of its
restricted common stock, valued at $450,000, to an unaffiliated party for its
consultation and assistance related to the transaction. The common stock
issued was recorded at a 10% discount to market, which was based on the quoted
market price of the stock at the time the commission was earned and is
recorded inthese oil and gas properties.
In addition toproperties were approximately $1.2 million for the North Dakota acquisition, the Company acquired
additional oilnine months ended March 31, 2004 and gas properties during fiscal 2001 in New Mexico and South
Dakota. The consideration for these acquisitions, which include stock
commissions relating to the acquisitions, were $2,567,000 and 751,238 shares
of the Company's common stock valued at $2,504,000.
Acquisitions - 2000
On November 1, 1999, the Company acquired interests in 10 operated
wells in New Mexico and 1 non-operated well in Texas ("New Mexico") for a cost
of $2,880,000. The acquisition was financed through borrowings from an
unrelated entity at an interest rate of 18% per annum.
On December 1, 1999, the Company completed the acquisition of 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 its three
platforms (Hidalgo, Harvest and Hermosa) ("Point Arguello"), along with a 100%
interest in two and an 11.11% interest in one of the three leases within the
adjacent unproved undeveloped Rocky Point Unit from Whiting Petroleum
Corporation ("Whiting"), a shareholder. Whiting retained its proportionate
share of future abandonment liability associated with both the onshore and
offshore facilities of the Point Arguello Unit. The acquisition had a
F-17
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(2) Oil and Gas Properties, Continued
purchase price of approximately $6,759,000 consisting of $5,625,000 in cash
and 500,000 shares (which included the 300,000 shares issued during fiscal
1999) of the Company's restricted common stock with a fair market value of
$1,134,000. The total acquisition cost of $5,059,000 was allocated between
proved developed producing of $1,970,000, proved undeveloped of $1,700,000 and
unproved undeveloped of $1,389,000. The Company assigned to BWAB a 3%
overriding royalty interest in the Point Arguello properties as consideration
for arranging the transaction.
The Company committed to sell 25,000 barrels per month from December
1999 to May 2000 at $8.25 per barrel and from June 2000 to December 2000 at
$14.65. If the Company would not have committed to sell its proportionate
shares of its barrels at $8.25 and $14.65 per barrel, the Company would have
realized an increase in income of $1,242,000$1.8 million for the year ended June 30, 20012003.
On December 5, 2003, the Company completed the sale of certain properties located in Texas to Sovereign for cash consideration of $2.6 million. The effective date of the transaction is January 1, 2004 and $2,033,000it 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, 2000.
In addition to the New Mexico and Point Arguello acquisitions, the
Company acquired additional oil and gas properties in New Mexico and South
Dakota. The consideration for these acquisitions, which include stock
commissions relating to the acquisitions, were $2,567,000 and 15,000 shares of
the Company's common stock valued at $32,000.
Dispositions
2003.
On March 1, 2002, Delta completed the sale of 21 producing wells and acreage located primarily in the Eland and Stadium fields of Stark County, North Dakota, to Sovereign Holdings, LLC, a privately-held Colorado limited liability company, for cash consideration of $2,750,000$2.8 million pursuant to a purchase and sale agreement dated February 1, 2002 and effective January 1, 2002. The Company recorded an impairment on these properties of $102,000 prior to the sale. As a result of the sale, the Company recorded a loss on the sale of these oil and gas properties of $1,000. See unaudited proforma consolidated
statements of operations above. Approximately $1,300,000$1.3 million of the proceeds from the sale were used to pay existing debt.
During the years ended June 30, 2002, 20012003 and 2000,2002, the Company has
disposed of certainadditional non-strategic oil and gas properties and related equipment to unaffiliated entities in addition to the North Dakota dispositiondispositions described above. The Company has received proceeds from these sales of $1,667,000
$3,700,000$850,000 and $75,000$1.5 million and such sales resulted in a net gain (loss) on sale of oil and gas properties of $(87,000), $458,000$277,000 and $76,000$(87,000) for the years ended June 30, 2003 and 2002, 2001 and 2000, respectively.
F-18
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(2) Oil and Gas Properties, Continued
The following unaudited pro forma consolidated statements of
operations information assumes that the acquisition of Castle's properties and
the sale of the North Dakota properties discussed above occurred as of July 1,
2000:
Year Ended
June 30,
2002 2001
----------- -----------
Oil and gas sales $19,775,000 $30,259,000
=========== ===========
Net income (loss) $(6,493,000) $ 467,000
=========== ===========
Net income (loss) per common share:
Basic $ (.51) $ .02
=========== ===========
Diluted $ (.51) $ .02
=========== ===========
The above unaudited adjusted Pro Forma Consolidated Statements of
Operations are based on the historical results of Castle and Delta and are not
necessarily indicative of the results of operations that would have actually
occurred had Delta owned these properties for the periods presented.
(3)
(4) Long Term Debt
Bank Debt
On June 30,
----------------------------
2002 2001
---- ----
A $18,918,000 -
B 6,021,000 7,337,000
C - 2,097,000
----------- ----------
$24,969,000 $9,434,000
Current Portion 3,498,000 3,038,000
----------- ----------
Long-Term Portion $21,441,000 $6,396,000
=========== ==========
F-19
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(3) Long Term Debt, Continued
A. On May 31, 2002,29, 2004, the Company obtained aamended and restated its credit facility. The new $20$100 million credit facility with Bank of Oklahoma, U.S. Bank National Association and Local OklahomaHibernia National Bank (the "Banks)“Banks”). At June 30, 2004, the Company had an available borrowing base of $70 million and was fully funded. The facility has a variable interest rate component of LIBOR +1.75% to 2.85% and/or prime + 1.5%+.5% / - -.5% based on the total debt outstanding and ano current monthly commitment reduction of $260,000.reduction. The proceeds from this facility were used for the acquisition of Castle and to
pay off the remaining US Bank debt. The Company paid a 1% commitment fee in
aggregate to the banks. This fee was recorded as a deferred financing fee and
will be amortized over the life of the loan which matures on May 31, 2005June 30, 2007 and is collateralized by substantially all of Delta'sDelta’s oil and gas properties
excluding the oil and gas properties collateralized under the Kaiser-Francis
Oil Company ("KFOC") note discussed below.properties. The Company'sCompany’s borrowing base and monthly commitment amount will be redetermined at least semi-annually. See Subsequent event footnote for activity after year end.
If as a result of any such monthly commitment reduction or reduction in the amount of ourthe borrowing base, the total amount of our outstanding debt ever exceeds the amount of the revolving commitment then in effect, then within 30 days after we arethe Company is notified by the Bank of Oklahoma, wethe Company must make a mandatory prepayment of principal that is sufficient to cause ourthe Company’s total outstanding indebtedness to not exceed ourthe borrowing base. The Company is required to meet quarterly debt covenants and restrictions.restrictions, which includes a current ratio to be not less than 1.0 to 1.0 and a funded debt ratio to not be greater than 3.0 to 1.0 after adjustments. At June 30, 2002,2004, the Company did not meetwas in compliance with its current ratio covenant of 1.0 to 1.0. This was primarily due
to a current foreign tax payable of $703,000 relating to the sale of its
Australian property prior to establishing the loan agreement. Thequarterly debt covenants and restrictions.
Kaiser Francis Oil Company has
obtained a waiver for this requirement from the Banks and is not in default of
the loan agreement at June 30, 2002.
B. - Debt
On December 1, 1999, the Company borrowed $8,000,000$8 million at prime plus 1-1/2%1 1/2% from KFOC). In addition, the Company will be required to pay a fee of
$250,000 on June 1, 2003 if the loan has not been retired prior to this date.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. The Company is
required to make minimum monthly paymentsDuring the third quarter of principal and interest equal to
the greater of $150,000 or 75% of net cash flows from the acquisitions
completed on November 1, 1999 and December 1, 1999. The loan is
collateralized by the Company's oil and gas properties acquired with the loan
proceeds.
C. On October 25, 2000, the Company borrowed $3,000,000 at prime plus
3%, secured by the acquired interests in the Eland and Stadium fields in Stark
County, North Dakota, from US Bank National Association (US Bank). At June
30, 2002,fiscal 2004, the loan was paid in full.
(4) Stockholders'
Maturities of long-term debt, in thousands of dollars based on contractual terms are as follows:
YEAR ENDING June 30, | |||
2005 | $ | 109 | |
2006 | 112 | ||
2007 | 69,486 | ||
2008 | 24 | ||
2009 | 8 | ||
| $ | 69,739 | ||
(5) 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, 2002, 20012004, 2003 and 2000,2002, no preferred stock was issued.
F-20
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012003, 2004 and 2000
(4) Stockholders'2002
(5) Stockholders’ Equity, Continued
Common Stock
In addition to the common stock transactions described earlier in Note (2), the Company raised additional capital through the sale of shares of its common stock, net of commissions, of $225,000, $2,422,000$97.9 million and $1,024,000$225,000 during the years ended June 30, 2004 and 2002, 2001respectively. The Company did not raise capital through the issuance of shares of its common stock during the year-ended June 30, 2003. Offering costs of $6.1 million and 2000, respectively. Commissions$25,000 respectively consisted of cash and/or warrantscommission and legal service relating to purchase shares of the Company's common stocktransactions and were accounted for as an adjustment to stockholders'stockholders’ equity. The warrants
were issued with exercise prices at market or at a discount of 10% or less.
Swartz Agreement
On July 21, 2000, the Company entered into an investment agreement
with Swartz Private Equity, LLC ("Swartz") and issued Swartz a warrant to
purchase 500,000 shares of common stock exercisable at $3.00 per share until
May 31, 2005. A warrant to purchase 150,000 shares of the Company's common
stock at $3.00 per share for five years was also issued to another unrelated
company as consideration for its efforts in this transaction and have been
recorded as an adjustment to equity. In the aggregate, the Company issued
options to Swartz and the other unrelated company valued at $1,436,000 as
consideration for the firm underwriting commitment of Swartz and related
services to be rendered are recorded in additional paid in capital. The
options were valued at market based on the quoted market price at the time of
issuance.
The investment agreement entitles the Company to issue and sell
("Put") up to $20 million of its common stock to Swartz, subject to a formula
based on the Company's stock price and trading volume over a three year period
following the effective date of a registration statement covering the resale
of the shares to the public. Pursuant to the terms of this investment
agreement the Company is not obligated to sell to Swartz all of the common
stock and additional warrants referenced in the agreement nor does the Company
intend to sell shares and warrants to the entity unless it is beneficial to
the Company. Each time the Company sells shares to Swartz, the Company is
required to also issue five (5) year warrants to Swartz in an amount
corresponding to 15% of the Put amount. Each of these additional warrants
will be exercisable at 110% of the market price for the applicable Put.
To exercise a Put, the Company must have an effective registration
statement on file with the Securities and Exchange Commission covering the
resale to the public by Swartz of any shares that it acquires under the
investment agreement. Swartz will pay the Company the lesser of the market
price for each share minus $0.25, or 91% of the market price for each share of
common stock under the Put. The market price of the shares of common stock
during the 20 business days immediately following the date the Company
exercises a Put is used to determine the purchase price Swartz will pay and
the number of shares the Company will issue in return.
F-21
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(4) Stockholders' Equity, Continued
If the Company does not Put at least $2,000,000 worth of its common
stock to Swartz during each one year period following the effective date of
the Investment Agreement, it must pay Swartz an annual non-usage fee. This fee
equals the difference between $200,000 and 10% of the value of the shares of
common stock it Put to Swartz during the one year period. The fee is due and
payable on the last business day of each one year period. Each annual non-
usage fee is payable to Swartz, in cash, within five (5) business days of the
date it accrued. The Company is not required to pay the annual non-usage fee
to Swartz in years it has met the Put requirements. The Company is also not
required to deliver the non-usage fee payment until Swartz has paid for all
Puts that are due. If the investment agreement is terminated, the Company must
pay Swartz the greater of (i) the non-usage fee described above, or (ii) the
difference between $200,000 and 10% of the value of the shares of common stock
Put to Swartz during all Puts to date. The Company may terminate its right to
initiate further Puts or terminate the investment agreement at any time by
providing Swartz with written notice of its intention to terminate. However,
any termination will not affect any other rights or obligations the Company
has concerning the investment agreement or any related agreement.
The Company cannot determine the exact number of shares of its
common stock issuable under the investment agreement and the resulting
dilution to its existing shareholders, which will vary with the extent to
which the Company utilizes the investment agreement and the market price of
its common stock.
Non-Qualified Stock Options-Directors and Employees
On May 31, 2002 at the annual meeting of the shareholders, the shareholders ratified the Company'sCompany’s 2002 Incentive Plan (the "Incentive Plan"“Incentive Plan”) under which it reserved up to an additional 2,000,000 shares of common stock. This plan supercedes the Company'sCompany’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 our 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'sCompany’s various plans and related information for the years ended June 30, 2004, 2003 and 2002 2001 and 2000
follows:
F-22
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(4) Stockholders' Equity, Continued
2002 2001 2000
Weighted-Average Weighted-Average Weighted-Average
Exercise Exercise Exercise
Options Price Options Price Options Price
--------- ------ ---------- ----- ---------- -----
Outstanding-beginning of year 2,956,215 $ 3.14 1,635,886 $ 1.36 1,640,163 $ 1.05
Granted 547,500 $ 2.32 1,882,500 $ 4.00 387,500 $ 1.60
Exercised (95,228) $(0.62) (562,171) $(0.81) (391,777) $(0.29)
Expired (30,000) $(4.56) - - - -
---------- ------- --------- ------- --------- ------
Outstanding-end of year 3,378,487 $ 3.07 2,956,215 $ 3.14 1,635,886 $ 1.36
========= ====== ========= ======= ========== ======
Exercisable at end of year 3,358,487 $ 3.06 2,896,215 $ 3.12 1,635,886 $ 1.36
======== ====== ======== ====== ======== ======
| 2004 | 2003 | 2002 | |||||||||||||||||||
| Weighted-Average Exercise | Weighted-Average Exercise | Weighted-Average Exercise | |||||||||||||||||||
| Options | Price | Options | Price | Options | Price | ||||||||||||||||
Outstanding-beginning of year | 3,410,987 | $ | 3.15 | 3,378,487 | $ | 3.07 | 2,956,215 | $ | 3.14 | ||||||||||||
Granted | 1,736,000 | $ | 5.63 | 255,000 | $ | 2.79 | 547,500 | $ | 2.32 | ||||||||||||
Exercised | (435,215 | ) | $ | 2.51 | (217,500 | ) | $ | (1.59 | ) | (95,228 | ) | $ | (0.62 | ) | |||||||
Expired / Returned | (11,000 | ) | $ | (6.39 | ) | (5,000 | ) | $ | 3.20 | (30,000 | ) | $ | (4.56 | ) | |||||||
Outstanding-end of year | 4,700,772 | $ | 4.10 | 3,410,987 | $ | 3.15 | 3,378,487 | $ | 3.07 | ||||||||||||
Exercisable at end of year | 4,300,772 | $ | 4.11 | 3,240,987 | $ | 3.15 | 3,358,487 | $ | 3.06 | ||||||||||||
The Company issued options to its Non-employee Directors. Accordingly, the Company recorded stock option expense in the amount of $329,000, $114,000 and $113,000 $110,000 and $92,000,for options issued to its Directors for the years ended June 30, 2002, 20012004, 2003 and 2000,2002, respectively, for options issued below market.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(5) Stockholders’ Equity, Continued
Exercise prices for options outstanding under our various plans as of June 30, 20022004 ranged from $0.05$.05 to $9.75 per share. The weighted-average remaining contractual life of those unvested options is 6.5 years. All but 20,000400,000 options are fully vested at June 30, 2002. The weighted-average remaining contractual
life of those options is 7.96 years.2004. A summary of the outstanding and exercisable options at June 30, 2002,2004, segregated by exercise price ranges, is as follows:
Exercise Price Range | Options Outstanding | Weighted Average Exercise Price | Weighted (in years) | Exercisable Options | Weighted Average Exercise Price | |||||||
$0.05 - $1.12 | 180,000 | $ | 0.05 | 4.25 | 180,000 | $ | 0.05 | |||||
$1.13 - $3.25 | 1,119,272 | 2.05 | 5.95 | 1,119,272 | 2.05 | |||||||
$3.26 - $9.75 | 3,401,500 | 4.99 | 7.43 | 3,001,500 | 5.12 | |||||||
| 4,700,772 | $ | 4.10 | 6.95 | 4,300,772 | $ | 4.11 | ||||||
The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following Weighted-
averageWeighted-average assumptions for the years ended June 30, 2002, 20012004, 2003 and 2000,2002, respectively, risk-free interest rate of 4.73%4.32%, 5.1%2.84% and 5.5%4.73%, dividend yields of 0%, 0% and 0%, volatility factors of the expected market price of the Company'sCompany’s common stock of 65.68%50.43%, 64.03%65.32% and 56.07%65.68% and a weighted-average expected life of the options of 5.56, 4.16 and 6.37 6.15 and 6.6 years.
The Company applies APB Opinion 25 and related Interpretations in
accounting for its plans. Accordingly, no compensation cost is recognized for
options granted at a price equal or greater to 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 (loss) for the years ended June 30, 2002,
2001 and 2000 would have been as follows:
Non-Qualified Stock Options (Non-Employee)
The Company has also issued options to non-employees. Accordingly, the Company recorded stock option expense in the amount of $30,000, $299,000zero, $10,000 and $446,000$30,000 to non-employees for the years ended June 30, 2002, 20012004, 2003 and 2000,2003, respectively.
A summary of the stock option and warrant activity and related information for the years ended June 30, 2002, 20012004, 2003 and 20002002 is as follows:
F-24
| 2004 | 2003 | 2002 | |||||||||||||||||||
| Weighted-Average Exercise | Weighted-Average Exercise | Weighted-Average Exercise | |||||||||||||||||||
| Options | Price | Options | Price | Options | Price | ||||||||||||||||
Outstanding-beginning of year | 1,255,000 | $ | 3.38 | 1,954,000 | $ | 3.62 | 2,140,000 | $ | 3.56 | ||||||||||||
Granted | — | $ | — | — | $ | — | 35,000 | $ | 3.25 | ||||||||||||
Exercised | (1,197,500 | ) | $ | (2.48 | ) | (250,761 | ) | $ | (2.51 | ) | (171,000 | ) | $ | (2.04 | ) | ||||||
Expired | — | $ | — | (448,239 | ) | $ | 4.76 | (50,000 | ) | $ | (6.00 | ) | |||||||||
Outstanding-end of year | 57,500 | $ | 3.80 | 1,255,000 | $ | 3.38 | 1,954,000 | $ | 3.62 | ||||||||||||
Exercisable at end of year | 57,500 | $ | 3.80 | 1,255,000 | $ | 3.38 | 1,954,000 | $ | 3.62 | ||||||||||||
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(4) Stockholders'2002
(5) Stockholders’ Equity, Continued
2002 2001 2000
Weighted-Average Weighted-Average Weighted-Average
Exercise Exercise Exercise
Options Price Options Price Options Price
------- ----- -------- ----- ------- -----
Outstanding-beginning of year
2,140,000 $ 3.56 1,562,500 $ 3.33 1,194,500 $ 4.09
Granted 35,000 $ 3.25 1,250,000 $ 3.46 1,090,000 $ 2.99
Exercised (171,000) $(2.04) (360,000)$ (2.85) (657,000) $(1.92)
Re-priced - - - - 350,000 $ 1.93
Returned for re-pricing - - - - (350,000) $(3.48)
Purchased from Kaiser-Francis
Oil Co - - (250,000)$ (2.00) - -
Expired (50,000) $(6.00) (62,500)$(6.125) (65,000) $(2.00)
--------- ------ --------- ------- --------- ------
Outstanding end of year 1,954,000 $ 3.62 2,140,000 $ 3.56 1,562,500 $ 3.33
========= ====== ========= ======= ========= ======
Exercisable at end of
year 1,954,000 $ 3.62 2,140,000 $ 3.56 1,562,500 $ 3.33
========= ====== ========= ======= ========= ======
Exercise prices for options outstanding under the plans as of June 30, 20022004 ranged from $2.00$3.25 to $6.00$5.00 per share. All options are fully vested at June 30, 2002.2004. The weighted-average remaining contractual life of those options is 1.71.25 years. A summary of the outstanding and exercisable options at June 30, 2002,2004, 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
- -------- ----------- ---------- ----------- ----------- ----------
$2.00-$3.25 1,084,000 $2.97 2.47 1,084,000 $2.97
$3.26-$6.00 870,000 4.43 0.94 870,000 4.43
--------- ------ ---- --------- -----
1,954,000 $3.62 1.71 1,954,000 $3.62
========= ===== ==== ========= =====
F-25
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(5)
Exercise Price Range | Options Outstanding | Weighted Average Exercise Price | Weighted (in years) | Exercisable Options | Weighted Average Exercise Price | |||||||
$3.25 - $5.00 | 57,500 | $ | 3.80 | 0.25 | 57,500 | $ | 3.80 | |||||
(6) Employee Benefits
The Company adopted a profit sharing plan on January 1, 2002. All employees are eligible to participate in 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.
Prior to the adoption of a profit sharing plan, the Company sponsored a qualified tax deferred savings plan in the form of a Savings Incentive Match Plan for Employees ("SIMPLE"(“SIMPLE”) IRA plan available to companies with fewer than 100 employees. Under the profit sharingSIMPLE plan, the Company'sCompany’s employees made annual salary reduction contributions of up to 3% of an employee'semployee’s base salary up to a maximum of $6,000 (adjusted for inflation) on a pre-tax basis. The Company matched contributions on behalf of employees who met certain eligibility requirements.
For the years ended June 30, 2002, 20012004, 2003 and 20002002 the Company contributed $68,000, $18,000$262,000, $147,000 and $18,000,$68,000, respectively under the plans.
(6)
(7) 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, swaps or options. 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 and such amounts are reclassified to realized gain (loss) on derivative instruments as the associated production occurs.
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.
As of June 30, 2004, the Company had no derivative instruments in place. The realized net losses from hedging activities were $859,000 and $1.9 million for the years ended June 30, 2004 and 2003.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(8) Income Taxes
At June 30, 2004, 2003 and 2002, 2001 and 2000, the Company'sCompany’s significant deferred tax assets and liabilities are summarized as follows:
| 2004 | 2003 | 2002 | ||||||||||
(In thousands) | ||||||||||||
Deferred tax assets: | ||||||||||||
Net operating loss/depletion carryforwards (1) | $ | 13,278 | $ | 13,927 | $ | 11,534 | ||||||
Other | 19 | 255 | 87 | |||||||||
Gross deferred tax assets | 13,297 | 14,182 | 11,621 | |||||||||
Less valuation allowance | (8,990 | ) | (10,279 | ) | (10,549 | ) | ||||||
Deferred tax liability: | ||||||||||||
Oil and gas properties principally due to differences in basis resulting from depreciation and depletion | (4,307 | ) | (3,903 | ) | (1,072 | ) | ||||||
Net deferred tax asset: | $ | — | $ | — | $ | — | ||||||
| (1) | Included in net operating loss carryforwards is $1.1 million, $618,000 and $379,000, which relate to the tax |
No income tax benefit has been recorded for the years ended June 30, 2002, 20012004, 2003 or 20002002 since the benefit of the net operating loss carryforward and other net deferred tax assets arising in those periods has been offset by the change in the valuation allowance for such net deferred tax assets. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion of 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 taxable income over the periods in which the deferred tax assets are deductible, management believes it is not more likely than not that the Company will realize the benefits of these deductible differences at June 30, 2004. The amount of the deferred tax asset considered realizable to offset deferred tax liabilities, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.
At June 30, 2002,2004, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes of approximately $28,700,000$35 million and $28,000,000.$33.1 million, respectively. If not utilized, the tax net operating loss carryforwards will expire during the period from 20022005 through 2022.2024. If not utilized, approximately $1.8$2.8 million of net operating losses will expire over the next five years. Net operating loss carryforwards attributable to Amber prior to 1993 of approximately $1,162,000,$362,000, included in the above amounts, are available only to offset future taxable income of Amber.
In addition, Delta Petroleum and their Subsidiariesits subsidiaries experienced a change in ownership in May 2002 with the acquisition of CastleCastle’s oil and gas properties and as a result, its annual net operating loss carry-forward usage is limited. The Company
believes it has a substantial unapplied built-in gain at June 30, 2002. In
addition, the limitation is increased by the Company's net built-in gain at
the time of change in ownership to the extent the related assets are sold in
the subsequent five year period. The annual limitation due to the ownership change is estimated to be $2,922,000.
(7)approximately $3 million.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(9) Related Party Transactions
Transactions with Officers
The Company's
Until March 12, 2003, the Company’s Board of Directors hashad 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 recompleted by us on our acreage (provided that any well to be re-entered or recompleted is notwas then producing economic quantities of hydrocarbons). On FebruaryMarch 12, 2001,2003, the Company's Board of Directors permitted
Aleron H. Larson, Jr., Chairman, Roger A. Parker, President, and Kevin Nanke,
CFO, to purchase working interests of 5% each for Messrs. Larson and Parker
and 2-1/2% for Mr. Nanke in the Company's Cedar State gas property located in
F-27
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(7) Related Party Transactions, Continued
Eddy County, New Mexico and in the Company's Ponderosa Prospect consisting of
approximately 52,000 gross acres in Harding and Butte Counties, South Dakota
held for exploration. Theserescinded this right. The officers were authorized to purchase these
interests on or before March 1, 2001 at a purchase price equivalent to the
amounts paid by Delta for each property as reflected upon our books by
delivering to us shares of Delta common stock at the February 12, 2001 closing
price of $5.125 per share, the market closing price on this date. Messrs.
Larson and Parker each delivered 10,256 shares in fiscal 2002 and 31,310
shares in fiscal 2001 and Mr. Nanke delivered 5,128 shares in fiscal 2002 and
15,655 shares in fiscal 2001 in exchange for their interests in these
properties. Also on February 12, 2001, the Company granted Messrs. Larson and
Parker and Mr. Nanke the right todid not participate in the drilling of the Austin
State #1 well in Eddy County, New Mexico by committing on February 12, 2001
(prior to any bore hole knowledge or information relating to the objective
zone or zones) to pay 5% each for Messrs. Larson and Parker and 2-1/2% for Mr.
Nanke of Delta's working interest costs of drilling and completion or
abandonment costs which costs were paid in Delta common stock at $5.125 per
share, the market closing price on this date. All of these officers committed
to participate in the well.
Company wells during fiscal 2003.
Effective June 1, 2002, Mr. Parker exchanged properties with a fair market value of approximately $150,000 in exchange for a reduction in joint interest billing owed to the Company. The fair market value was initially determined by the Company'sCompany’s engineer and verified by ouran independent engineer.
On January 3, 2000, the Company's Compensation Committee authorized
the officers of the Company to purchase some of the Company's securities
available for sale at the market closing price on that date. The Company's
officers purchased 47,250 shares of the Company's marketable securities
available for sale for a cost of $238,000. Because the market price per share
was below the Company's cost basis the Company recorded a loss on this
transaction of $108,000.
On December 30, 1999, the Company's Incentive Plan Committee granted
the Chief Financial Officer 25,000 options to purchase the Company's common
stock at $.01 per share. Stock option expense of $62,000 has been recorded
based on the difference between the option price and the quoted market price
on the date of grant.
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'sCompany’s indebtedness, each officer was assigned a 1% overriding royalty interest ("ORRI"(“ORRI”) in the properties acquired with the proceeds of the borrowings. Each officer earned approximately $71,000, $83,000$66,000, $108,000 and $35,000$71,000 for their respective 1% ORRI during fiscal 2004, 2003 and 2002, 2001respectively.
The Company’s officers have employment agreements, which among other things include termination and 2000, respectively.
F-28
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(7) Related Party Transactions, Continued
change of control clauses. These employment agreements terminate in November 2004.
Accounts Receivable Related Parties
At June 30, 2002,2004, the Company had $264,000$18,000 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 and
advances.Company. The amounts are due on open account and are non-interest bearing.
Subsequent to year end, advanced amounts of $203,000 were paid in full.
Transactions with Other Stockholders
BWAB Limited Liability Company
On January 18, 2001 and April 13, 2001, Franklin Energy LLC, an
affiliate of BWAB earned 20,250 and 10,000 shares of the Company's common
stock, respectively for their assistance in the purchase and sale of the
certain oil and gas properties. The shares issued were valued at $121,000
which was a 10% discountfull subsequent to market, based on the quoted market price of our
stock at the date of the acquisition. The shares were accounted for as an
adjustment to the purchase price and capitalized to oil and gas properties.
On September 29, 2000, the Company borrowed $500,000 with and
interest rate of 10% from BWAB. On December 18, 2000, the note and accrued
interest of $11,000 was converted into 200,000 shares of the Company's
restricted common stock.
Burdette A. Ogle
The Company has a month to month consulting agreement with Messrs.
Burdette A. Ogle and Ronald Heck (collectively "Ogle"), a less than 10%
shareholder, which provides for a monthly fee of $10,000.
The Company annually pays Ogle a $350,000 minimum production payment
as payment for interests in certain undeveloped Federal Units offshore Santa
Barbara which were assigned to the Company by Ogle. This payment is recorded
as an addition to undeveloped offshore California properties. As of June 30,
2002, the Company has paid a total of $2,600,000 in minimum royalty payments
and is to pay a minimum of $350,000 annually until the earlier of: 1) when
production payments accumulate to $8,000,000; 2) when 80% of the ultimate
reserves of any lease under the agreement have been produced; or 3) 30 years
from the date of purchase, January 3, 1995.
Evergreen Resources, Inc.
On January 3, 2001, the Company granted an option to acquire 50% of
the properties acquired under the Ogle transaction discussed above to
Evergreen Resources, Inc. ("Evergreen"), a less than 10% shareholder, until
September 30, 2001. The option expired September 30, 2001.
F-29
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(8)year end.
(10) Earnings Per Share
The following table sets forth the computation of basic and diluted earnings per share:
| Years Ended June 30, | ||||||||||
| 2004 | 2003 | 2002 | ||||||||
| (In thousands, except per share amounts) | ||||||||||
Numerator: | ||||||||||
Numerator for basic and diluted earnings per share – income available to common stockholders | $ | 5,056 | $ | 1,257 | $ | (6,253 | ) | |||
Denominator: | ||||||||||
Denominator for basic earnings per share-weighted average shares outstanding | 27,041 | 22,865 | 12,682 | |||||||
Effect of dilutive securities, stock options and warrants | 2,591 | 954 | * | |||||||
Denominator for diluted earnings per common share | 29,632 | $ | 23,819 | 12,682 | ||||||
Basic earnings per common share | $ | .19 | $ | .05 | $ | (.49 | ) | |||
Diluted earnings per common share | $ | .17 | $ | .05 | $ | (.49 | ) | |||
| * | Potentially dilutive securities outstanding |
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2002
(11) Commitments
The Company rents an office in Denver under an operating lease which expires in September 2008.fiscal 2009. Rent expense, net of sublease rental income, for the years ended June 30, 2002, 20012004, 2003 and 20002002 was approximately $108,700,
$82,000$272,000, $210,000 and $60,000,$109,000, respectively. Future minimum payments under non-
cancelablenon-cancelable operating leases are as follows:
| (In thousands) | |||
2005 | $ | 354 | |
2006 | 357 | ||
2007 | 360 | ||
2008 | 345 | ||
2009 | 87 | ||
| $ | 1,503 | ||
(12) Selected Quarterly Financial Data (Unaudited)
Fiscal 2004 | 1st Quarter(1) | 2nd Quarter(1) | 3rd Quarter(1) | 4th Quarter | |||||||||
| (In thousands, except per share amounts) | |||||||||||||
Total revenue | $ | 7,444 | $ | 8,006 | $ | 10,342 | $ | 11,641 | |||||
Income from continuing operations | 1,853 | 1,208 | 813 | 621 | |||||||||
Net income | 1,364 | 652 | 2,454 | 586 | |||||||||
Net income per common share: (2) | |||||||||||||
Basic | $ | .06 | $ | .03 | $ | .09 | $ | .02 | |||||
Diluted | $ | .05 | $ | .03 | $ | .08 | $ | .02 | |||||
Fiscal 2003 | 1st Quarter(1) | 2nd Quarter(1) | 3rd Quarter(1) | 4th Quarter(1) | |||||||||
| (In thousands, except per share amounts) | |||||||||||||
Total revenue | $ | 5,648 | $ | 5,704 | $ | 6,975 | $ | 5,653 | |||||
Income (loss) from continuing operations | 634 | 850 | 1,715 | (186 | ) | ||||||||
Net income (loss) | 117 | 428 | 1,307 | (595 | ) | ||||||||
Net income (loss) per common share: (2) | |||||||||||||
Basic | $ | .01 | $ | .02 | $ | .06 | $ | (.03 | ) | ||||
Diluted | $ | ** | $ | .02 | $ | .05 | $ | * | |||||
Fiscal 2003 $ 213,500
2004 $ 211,900
2005 $ 205,300
2006 $ 210,000
2007 $ 210,000
Thereafter $ 259,000
F-30
| * | Potentially dilutive securities outstanding were anti-dilutive |
| ** | less than $.01 per share |
| (1) | Selected quarterly financial data represents information previously reported and not restated for the reclass adjustments relating to FAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”. |
| (2) | The sum of individual quarterly net income per share may not agree with year-to-date net income per share as each period’s computation is based on the weighted average number of common shares outstanding during the period. |
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(9) Commitments, Continued
Beginning in fiscal 2003, we began to hedge a portion of our oil and gas
production using swap and collar agreements. The purpose of these hedge
agreements, whereby the Company generally receives a fixed price for its
production, 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 Company entered into agreements to hedge
approximately 40% of its offshore oil production for production months July
2002 through March 2003. In addition, the Company has entered into agreements
to hedge approximately 40% of its onshore oil production and 30% of its
onshore gas production for production months August 2002 through September
2003.
(10) Selected Quarterly Financial Data (Unaudited)
(13) Disclosures About Capitalized Costs, Cost Incurred and Major Customers
Capitalized costs related to oil and gas producing activities are as follows:
June 30,
2002 2001
----- ----
Unproved undeveloped offshore
California properties* $9,722,000 $ 9,359,000
Proved undeveloped offshore
California properties 843,000 1,149,000
Undeveloped onshore
domestic properties 10,114,000 1,616,000
Developed Offshore California
properties 6,204,000 4,699,000
Developed onshore domestic
properties 45,893,000 13,038,000
---------- ----------
72,776,000 29,861,000
Accumulated depreciation
and depletion (6,925,000) (4,940,000)
---------- -----------
$65,851,000 $24,921,000
=========== ===========
* The unproved undeveloped offshore California properties have no proved
reserves.
| June 30, | ||||||||
| 2004 | 2003 | |||||||
| (In thousands) | ||||||||
Unproved undeveloped offshore California properties | $ | 10,844 | $ | 10,164 | ||||
Unproved undeveloped onshore domestic properties | 38,903 | 1,680 | ||||||
Proved undeveloped offshore California properties | — | 843 | ||||||
Proved undeveloped onshore domestic properties | 86,720 | 9,995 | ||||||
Proved developed offshore California properties | 9,103 | 7,190 | ||||||
Proved developed onshore domestic properties | 127,322 | 60,279 | ||||||
| 272,892 | 90,151 | |||||||
Accumulated depreciation and depletion | (21,317 | ) | (12,509 | ) | ||||
| $ | 251,575 | $ | 77,642 | |||||
Costs incurred in oil and gas producing activities are as follows:
| Years Ended June 30, | ||||||||||||||||||
| 2004 | 2003 | 2002 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||
| Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||
Unproved property acquisition costs | $ | 37,223 | $ | 680 | $ | 694 | $ | 442 | $ | 9,115 | $ | 363 | ||||||
Proved property acquisition costs | 128,587 | — | 10,784 | — | 38,290 | — | ||||||||||||
Developed cost incurred on undeveloped reserves | 3,789 | 1,070 | 815 | 986 | 418 | 678 | ||||||||||||
Development costs – other | 20,986 | — | 4,335 | — | 569 | 521 | ||||||||||||
Exploration costs | 2,406 | — | 140 | — | 108 | 47 | ||||||||||||
| $ | 192,991 | $ | 1,750 | $ | 16,768 | $ | 1,428 | $ | 48,500 | $ | 1,609 | |||||||
Transferred amounts from undeveloped to developed properties | $ | 3,795 | $ | 843 | $ | 168 | $ | — | $ | — | $ | 306 | ||||||
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(11)2002
(13) 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:
| June 30, | ||||||||||||||||||||
| 2004 | 2003 | 2002 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Onshore | Offshore | Onshore | Offshore | Onshore | Offshore | |||||||||||||||
Revenue | ||||||||||||||||||||
Oil and gas revenues | $ | 33,260 | $ | 3,975 | $ | 17,987 | $ | 4,589 | $ | 4,257 | $ | 3,756 | ||||||||
Expenses: | ||||||||||||||||||||
Production costs | 6,519 | 3,257 | 5,140 | 3,270 | 1,213 | 3,044 | ||||||||||||||
Depletion | 8,978 | 705 | 3,860 | 1,075 | 2,216 | 1,099 | ||||||||||||||
| Exploration | 2,406 | — | 140 | 108 | 47 | |||||||||||||||
Abandonment and impaired properties | — | — | — | — | 1,480 | — | ||||||||||||||
Dry hole costs | 2,132 | — | 537 | — | 396 | — | ||||||||||||||
Results of operations of oil and gas producing activities | $ | 13,225 | $ | 13 | $ | 8,310 | $ | 244 | $ | (1,156 | ) | $ | (434 | ) | ||||||
Income (loss) from operations of properties sold, net | 872 | — | 1,241 | — | (9 | ) | — | |||||||||||||
Gain (loss) on sale of properties | 1,887 | — | 277 | — | (88 | ) | — | |||||||||||||
Results of discontinued operations of oil and gas producing activities | $ | 2,759 | $ | — | $ | 1,518 | $ | — | $ | (97 | ) | $ | — | |||||||
Statement of Financial Accounting Standards 131 "Disclosures“Disclosures about segments of an enterprises and Related Information"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 managesCompany’s business segment includes its business through one operating segment.
F-33
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notesonshore 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 Consolidated Financial Statements
June 30, 2002, 2001the drilling and 2000
(11) Disclosures About Capitalized Costs, Cost Incurred and Major Customers,
Continued
trucking companies have not been presented.
The Company'sCompany’s sales of oil and gas to individual customers which exceeded 10% of the Company'sCompany’s total oil and gas sales for the years ended June 30, 2004, 2003 and 2002 2001were:
| 2004 | 2003 | 2002 | |||||||
A | 17 | % | 13 | % | 3 | % | |||
B | 17 | % | — | % | — | % | |||
C | 14 | % | 17 | % | 2 | % | |||
D | 10 | % | 18 | % | 73 | % | |||
E | — | % | — | % | 10 | % |
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2004, 2003 and 2000 were:
2002 2001 2000
---- ---- ----
A 73% 59% 71%
B 10% 19% -
C 3% 5% 13%
(12)
(14) 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"“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“indicated additional reserves"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.
F-34
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 2001 and 2000
(12) Information Regarding Proved Oil and Gas Reserves (Unaudited)
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“proved developed reserves"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 undrilled 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
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
SUBSIDIARIES
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(12)2002
(14) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
A summary of changes in estimated quantities of proved reserves for the years ended June 30, 2002, 20012004, 2003 and 20002002 are as follows:
Onshore Offshore
GAS OIL GAS OIL
(MCF) (BBLS) (MCF) (BBLS)
----- ------ ----- ------
Balance at July 1, 1999 3,827,000 143,000 - -
Revisions of quantity
estimate 449,000 10,000 - -
Purchase of properties 3,166,000 107,000 - 1,771,000
Production (362,000) (10,000) - (187,000)
--------- -------- ------ ---------
Balance at June 30, 2000 7,080,000 250,000 - 1,584,000
Revisions of quantity
estimate (3,743,000) (25,000) - (90,000)
Extensions and discoveries 102,000 3,000 - -
Purchase of properties 1,782,000 233,000 - 747,000
Sales of properties - - - (720,000)
Production (539,000) (117,000) - (308,000)
---------- -------- ------- ---------
Balance at June 30, 2001 4,682,000 344,000 - 1,213,000
Revisions of quantity
estimate (269,000) 71,000 - (49,000)
Extensions and discoveries 42,000 2,000 - -
Purchase of properties 43,680,000 3,845,000 - -
Sales of properties (3,311,000) (256,000) - -
Production (871,000) (87,000) - (262,000)
---------- --------- -------- ---------
43,953,000 3,919,000 - 902,000
========== ========= ======== =========
Proved developed reserves:
June 30, 2000 5,672,000 120,000 - 908,000
June 30, 2001 4,474,000 342,000 - 906,000
June 30, 2002 25,100,000 1,651,000 - 849,000
F-36
| Onshore | Offshore | ||||||||||||||
GAS (Mmcf) | OIL (MBbl) | GAS (Mmcf) | OIL (MBbl) | ||||||||||||
| (In thousands) | |||||||||||||||
Balance at July 1, 2001 | $ | 4,682 | $ | 344 | $ | — | $ | 1,213 | |||||||
Revisions of quantity estimate | (269 | ) | 71 | — | (49 | ) | |||||||||
Extensions and discoveries | 42 | 2 | — | — | |||||||||||
Purchase of properties | 43,680 | 3,845 | — | — | |||||||||||
Sales of properties | (3,311 | ) | (256 | ) | — | — | |||||||||
Production | (871 | ) | (87 | ) | — | (262 | ) | ||||||||
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 | |||||||||||
Proved developed reserves: | |||||||||||||||
June 30, 2001 | 4,474 | 342 | — | 906 | |||||||||||
June 30, 2002 | 25,100 | 1,651 | — | 849 | |||||||||||
June 30, 2003 | 28,611 | 2,608 | — | 919 | |||||||||||
June 30, 2004 | 55,786 | 6,240 | — | 695 | |||||||||||
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(12)2002
(14) 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, 2004 | |||||||||
Future net cash flows | $ | 953,532 | $ | 51,625 | $ | 1,005,157 | |||
Future costs: | |||||||||
Production | 225,046 | 23,558 | 248,604 | ||||||
Development | 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 | |||
Estimated future development cost anticipated for fiscal 2005 and 2006 on existing properties | $ | 53,129 | $ | 4,378 | $ | 57,507 | |||
June 30, 2003 | |||||||||
Future cash flows | $ | 377,458 | $ | 46,898 | $ | 424,356 | |||
Future costs: | |||||||||
Production | 99,243 | 24,787 | 124,030 | ||||||
Development | 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 | |||
June 30, 2002 | |||||||||
Future cash flows | $ | 247,611 | $ | 16,600 | $ | 264,211 | |||
Future costs: | |||||||||
Production | 84,109 | 10,067 | 94,176 | ||||||
Development | 15,056 | 1,089 | 16,145 | ||||||
Income taxes | 28,078 | — | 28,078 | ||||||
Future net cash flows | 120,368 | 5,444 | 125,812 | ||||||
10% discount factor | 62,217 | 1,211 | 63,428 | ||||||
Standardized measure of discounted future net cash flows | $ | 58,151 | $ | 4,233 | $ | 62,384 | |||
Standardized measure of discounted future net cash flows before tax | $ | 72,073 | $ | 4,233 | $ | 76,306 | |||
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2002, 20012004, 2003 and 2000
(12)2002
(14) 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, 2002, 20012004, 2003 and 20002002 are as follows:
| 2004 | 2003 | 2002 | ||||||||||
| (In thousands) | ||||||||||||
Beginning of the year | $ | 107,211 | $ | 62,384 | $ | 15,974 | ||||||
Sales of oil and gas production during the period, net of production costs | (27,459 | ) | (16,082 | ) | (3,807 | ) | ||||||
Purchase of reserves in place | 248,478 | 14,335 | 70,097 | |||||||||
Net change in prices and production costs | 26,088 | 37,957 | (1,879 | ) | ||||||||
Changes in estimated future development costs | 8,592 | (8,251 | ) | (233 | ) | |||||||
Extensions, discoveries and improved recovery | 11,599 | 3,032 | 96 | |||||||||
Revisions of previous quantity estimates, estimated timing of development and other | (25,807 | ) | 25,675 | (398 | ) | |||||||
Previously estimated development costs Incurred during the period | 4,859 | 1,801 | 1,869 | |||||||||
Sales of reserves in place | (17,934 | ) | (1,122 | ) | (7,011 | ) | ||||||
Change in future income tax | (58,311 | ) | (18,756 | ) | (13,921 | ) | ||||||
Accretion of discount | 10,721 | 6,238 | 1,597 | |||||||||
End of year | $ | 288,037 | $ | 107,211 | $ | 62,384 | ||||||
(15) Subsequent event
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 $19.3 million. The Company paid $8.8 million toward its credit facility relating to the sale of these properties. There was no gain or loss on this transaction.
SIGNATURES
Pursuant to the requirements of the Section 13 or 15 (d) or 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 20th10th day of September 2002.
DELTA PETROLEUM CORPORATION
By: /s/ Roger A. Parker
---------------------------------
Roger A. Parker, President and
Chief Executive Officer
By: /s/ Kevin K. Nanke
---------------------------------
Kevin K. Nanke, Treasurer and
Chief Financial Officer
2004.
DELTA PETROLEUM CORPORATION | ||
By: | /s/ Roger A. Parker | |
Roger A. Parker, 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
- ------------------- ----
Aleron H. Larson, Jr., Director September 20, 2002
- ----------------------------------
Aleron H. Larson, Jr., Director
/s/ Roger A. Parker September 20, 2002
- ----------------------------------
Roger A. Parker, Director
September __, 2002
- ----------------------------------
James B. Wallace, Director
/s/ Jerrie F. Eckelberger September 20, 2002
- ----------------------------------
Jerrie F. Eckelberger, Director
September __, 2002
- ----------------------------------
John P. Keller
/s/ Joseph L. Castle II
- ---------------------------------- September 20, 2002
Joseph L. Castle II
September __, 2002
- ----------------------------------
Russell S. Lewis
CERTIFICATIONS
I, Roger A. Parker, certify that:
1. I have reviewed this annual report on Form 10-K of Delta Petroleum
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report.
Dated: September 20, 2002
/s/ Roger A. Parker
-----------------------------------
Roger A. Parker
Chief Executive Officer
(Principal Executive Officer)
I, Kevin K. Nanke, certify that:
1. I have reviewed this annual report on Form 10-K of Delta Petroleum
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report.
Dated: September 20, 2002
/s/ Kevin K. Nanke
-----------------------------------
Kevin K. Nanke
Chief Financial Officer
(Principal Financial Officer)
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
AND CHIEF FINANCIAL OFFICER OF
DELTA PETROLEUM CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350
We certify that, to the best of our knowledge, the Quarterly Report on
Form 10-K of Delta Petroleum Corporation, for the period ending June 30, 2002:
(1) complies with the requirements of Section 13(a) or 15(d) of the
Securities and Exchange Act of 1934; and
(2) the information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations of Delta
Petroleum Corporation.
/s/ Roger A. Parker /s/ Kevin K. Nanke
- ---------------------------- ------------------------------
Roger A. Parker Kevin K. Nanke
Chief Executive Officer Chief Financial Officer
September 20, 2002 September 20, 2002
Signature and Title | Date | |
/s/ Aleron H. Larson, Jr. | September 10, 2004 | |
Aleron H. Larson, Jr., Director | ||
/s/ Roger A. Parker | September 10, 2004 | |
Roger A. Parker, Director | ||
/s/ James B. Wallace | September 10, 2004 | |
James B. Wallace, Director | ||
/s/ Jerrie F. Eckelberger | September 10, 2004 | |
Jerrie F. Eckelberger, Director | ||
/s/ John P. Keller | September 10, 2004 | |
John P. Keller, Director | ||
/s/ Joseph L. Castle II | September 10, 2004 | |
Joseph L. Castle II, Director | ||
/s/ Russell S. Lewis | September 10, 2004 | |
Russell S. Lewis, Director | ||
F-32