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 the fiscal year ended June 30, 2003.
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the transition period from _____________.
Commission File No. 0-16203
DELTA PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Colorado 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 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. [X] Yes [ ] 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'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 15, 2003 of voting stock held by
non-affiliates of the registrant was $70,202,000.
As of September 15, 2003, 23,418,000 shares of registrant's Common Stock $.01
par value were issued and outstanding.
Documents incorporated by reference: The information required by Part III of
this Form 10-K is incorporated by reference to the Company's Definitive Proxy
Statement for the Company's 2003 Annual Meeting of Shareholders.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. DESCRIPTION OF BUSINESS ........................................ 4
ITEM 2. DESCRIPTION OF PROPERTY ........................................ 16
ITEM 3. LEGAL PROCEEDINGS .............................................. 36
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ............ 37
ITEM 4A DIRECTORS AND EXECUTIVE OFFICERS ............................... 37
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ....... 40
ITEM 6. SELECTED FINANCIAL DATA ........................................ 41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS ...................................... 41
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ..... 54
ITEM 8. FINANCIAL STATEMENTS ........................................... 54
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE ......................... 54
ITEM 9A. CONTROLS AND PROCEDURES ........................................ 55
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ............. 55
ITEM 11. EXECUTIVE COMPENSATION ......................................... 55
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT ................................................. 55
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ................. 55
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES ......................... 55
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K ...................................................... 56
The terms "Delta," "Company," "we," "our," and "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"
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. Forward-looking statements are generally accompanied by
words such as "estimate," "project," "predict," "believe," "expect,"
"anticipate," "plan," "goal" or other words that convey the uncertainty of
future events or outcomes. Sometimes we will specifically describe a
statement as being a forward-looking statement. In addition, except for the
historical information contained in this report, the matters discussed in this
report are forward-looking statements. These statements by their nature are
subject to certain risks, uncertainties and assumptions and will be influenced
by various factors. Should any of the assumptions underlying a forward-
looking statement prove incorrect, actual results could vary materially.
We believe the factors discussed below are important factors that could
cause actual results to differ materially from those expressed in a forward-
looking statement made herein or elsewhere by us or on our behalf. The factors
listed below are not necessarily all of the important factors. Unpredictable
or unknown factors not discussed herein could also have material adverse
effects on actual results of matters that are the subject of forward-looking
statements. We do not intend to update our description of important factors
each time a potential important factor arises. We advise our shareholders
that they should (1) be aware that important factors not described below could
affect the accuracy of our forward-looking statements and (2) use caution and
common sense when analyzing our forward-looking statements in this document or
elsewhere, and all of such forward-looking statements are qualified by this
cautionary statement.
- Historically, natural gas and crude oil prices have been volatile.
These prices rise and fall based on changes in market demand and
changes in the political, regulatory and economic climate and
other factors that affect commodities markets generally and are
outside of our control.
- Projecting future rates of oil and gas production is inherently
imprecise. Producing oil and gas reservoirs generally have
declining production rates.
- All of our reserve information is based on estimates. Reservoir
engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an
exact way. There are numerous uncertainties inherent in estimating
quantities of proved natural gas and oil reserves.
2
- Changes in the legal, political and/or regulatory environment
could have a material adverse effect on our future results of
operations and financial condition. Our ability to economically
produce and sell our oil and gas production is affected and could
possibly be restrained by a number of legal, political and
regulatory factors, particularly with respect to our offshore
California properties which are the subject of significant
political controversy due to environmental concerns.
- Our drilling operations are subject to various risks common
in the industry, including cratering, explosions, fires and
uncontrollable flows of oil, gas or well fluids.
3
PART I
ITEM 1. DESCRIPTION OF BUSINESS
(a) Business Development.
Delta Petroleum Corporation ("Delta," "we," "us") is a Colorado
corporation organized on December 21, 1984. We maintain our principal
executive offices at 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 engaged in the acquisition, exploration, development and
production of oil and gas properties. As of June 30, 2003, we had varying
interests in 488 gross (260 net) productive wells located in fourteen (14)
states and offshore California. These do not include varying small interests
in 666 gross (5.2 net) wells located primarily in Texas which are owned by our
subsidiary Piper Petroleum Company. We also have interests in five federal
units and one lease offshore California near Santa Barbara along with a
financial interest in a nearby producing offshore federal unit (see Item 2
"Description of Property"). We operate approximately 270 of the wells and the
remaining wells are operated by independent operators. All of these wells are
operated under contracts which we believe are standard in the industry. At
June 30, 2003, we estimated onshore proved reserves to be approximately
3,698,000 Bbls of oil and 55.2 Bcf of gas, of which approximately 2,608,000
Bbls of oil and 28.6 Bcf of gas were proved developed reserves. At June 30,
2003, we estimated offshore proved reserves to be approximately 2,051,000 Bbls
of oil, of which approximately 919,000 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 23,286,000 shares were issued and
outstanding as of June 30, 2003. We have outstanding warrants and options to
non-employees to purchase 1,255,000 shares of common stock at prices ranging
from $3.00 per share to $6.00 per share at June 30, 2003. Additionally, as of
June 30, 2003 we had outstanding options which were granted to our officers,
employees and directors under our incentive plans, to purchase up to 3,411,000
shares of common stock at prices ranging from $0.05 to $9.75 per share.
On June 20, 2003, Delta acquired producing oil and gas interests and
related undeveloped acreage in Kansas from JAED Production Company ("JAED"),
an unrelated entity, for which Delta paid $9,000,000 in cash 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 announcement
of the transaction. Delta recorded a purchase price adjustment of
approximately $291,000 which reflects the net revenues after operating costs
and acquisition related costs from the effective date of June 1, 2003 through
the closing date of June 20, 2003.
Also on June 20, 2003, Delta increased its credit facility from $20
million to $29.3 million with Bank of Oklahoma and Local Oklahoma Bank (the
"Banks"). The proceeds from this facility were used for the acquisitions of
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JAED during fiscal 2003 and Castle Energy Corporation ("Castle") during fiscal
2002. At June 30, 2003, our total borrowings were approximately $32,214,000.
A substantial portion of our oil and gas properties are pledged as collateral
for our 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.
At June 30, 2003, 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. 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. At June 30, 2003, 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.
On May 31, 2002, Delta acquired all of the domestic oil and gas
properties of Castle. The properties acquired from Castle consisted of
interests in approximately 525 producing wells located in fourteen (14)
states, plus associated undeveloped acreage. Delta issued 9,566,000 shares of
Common Stock to Castle as part of the purchase price. Although all of these
shares have been registered for sale, none has yet been sold.
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, which BWAB exercised. 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. This transaction
was exempt from registration under Section 4(2) of the Securities Act of 1933.
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 of the sale, we recorded a loss on sale of oil and gas properties of
$1,000.
On February 19, 2002, we completed the acquisition of Piper Petroleum
Company ("Piper"), a privately owned oil and gas company headquartered in Fort
Worth, Texas. We issued 1,377,240 shares of our restricted common stock for
100% of the shares of Piper. The 1,377,240 shares of restricted common stock
were valued at approximately $5,234,000 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
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and royalty interests in over 700 gross (5.3 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."
Subsequent to June 30, 2003, we completed the acquisition of certain oil
and gas properties for a purchase price of approximately $13,000,000, which
consisted of one million shares of our common stock valued at approximately
$5,000,000, $2 million in cash and $6 million in notes payable due October 3,
2003.
(b) Business of Issuer.
During the year ended June 30, 2003, 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 owned
subsidiaries and through Amber, we currently own producing and non-producing
oil and gas interests, undeveloped leasehold interests and related assets in
fourteen (14) 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, Louisiana, New Mexico,
Pennsylvania, Texas, Wyoming, and offshore California.
We intend to drill on some of our leases (presently owned or subsequently
acquired); may farm out or sell all or part of some of the leases to others;
and/or we may participate in joint venture arrangements to develop certain
other leases. Such transactions may be structured in a number of different
manners which 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.
(1) Principal Products or Services and Their 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 purchasers as referenced in
(6) below. Oil is picked up and transported by the purchaser from the
6
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 is
usually included in the calculation of the price paid for the natural gas.
(3) Status of Any Publicly Announced New Product or Service. 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, including major oil
companies and other independent operators which are more experienced and which
have greater financial resources. We do not hold a significant competitive
position in the oil and gas industry.
(5) Sources and Availability 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 outside of our control.
These factors include national and international economic conditions,
availability of drilling rigs, casing, pipe, and other equipment and supplies,
proximity to pipelines, the supply and price of other fuels, and the
regulation of prices, production, transportation, and marketing by the
Department of Energy and other federal and state governmental authorities.
(6) Dependence on One or a Few Major Customers. During our fiscal year
ended June 30, 2003, we sold a significant portion of our oil and gas
production to the following companies: Dynegy, 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
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.
--------
Our business is affected by numerous governmental laws and regulations,
including energy, environmental, conservation, tax and other laws and
7
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.
-------------------------
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 currently expect any
material adverse effect upon our results of operations or financial position
as a result of compliance with such laws and regulations.
Although future environmental obligations are not expected to have a
material adverse effect on our results of operations or financial condition,
there can be no assurance that future developments, such as increasingly
stringent environmental laws or enforcement thereof, will not cause us to
incur substantial environmental liabilities or costs.
8
Hazardous Substances and Waste Disposal.
----------------------------------------
We currently own or lease interests in numerous properties that have been
used for many years for natural gas and crude oil production. Although the
operator of such properties may have utilized operating and disposal practices
that were standard in the industry at the time, hydrocarbons or other wastes
may have been disposed of or released on or under the properties owned or
leased by us. In addition, some of these properties have been operated by
third parties over whom we had no control. The U.S. Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA") and
comparable state statutes impose strict, joint and several liability on owners
and operators of sites and on persons who disposed of or arranged for the
disposal of "hazardous substances" found at such sites. The Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes govern
the management and disposal of wastes. Although CERCLA currently excludes
petroleum from cleanup liability, many state laws affecting our operations
impose clean-up liability regarding petroleum and petroleum related products.
In addition, although RCRA currently classifies certain exploration and
production wastes as "non-hazardous," such wastes could be reclassified as
hazardous wastes thereby making such wastes subject to more stringent handling
and disposal requirements. If such a change in legislation were to be
enacted, it could have a significant impact on our operating costs, as well as
the gas and oil industry in general.
Oil Spills.
------------
Under the Federal Oil Pollution Act of 1990, as amended ("OPA"), (i)
owners and operators of onshore facilities and pipelines, (ii) lessees or
permittees of an area in which an offshore facility is located and (iii)
owners and operators of tank vessels ("Responsible Parties") are strictly
liable on a joint and several basis for removal costs and damages that result
from a discharge of oil into the navigable waters of the United States. These
damages include, for example, natural resource damages, real and personal
property damages and economic losses. OPA limits the strict liability of
Responsible Parties for removal costs and damages that result from a discharge
of oil to $350 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 regulations by the Responsible Party, its agent or subcontractor
or in certain other circumstances.
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
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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") 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.
--------------------
Offshore oil and gas operations in U.S. waters are subject to regulations
of the United States Department of the Interior which currently impose strict
liability upon the lessee under a Federal lease for the cost of clean-up of
pollution resulting from the lessee's operations, 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, 2004.
Abandonment Costs. 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 $868,000 at June 30,
2003 and a cumulative effect of change in accounting principle on prior years
of $20,000 in our consolidated statement of operations for the year ended June
30, 2003. 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.
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(12) Employees. We have twenty-two full time employees. Additionally,
certain operators, engineers, geologists, geophysicists, landmen, pumpers,
draftsmen, title attorneys and others necessary for our operations are
retained on a contract or fee basis as their services are required.
Certain Risks.
--------------
Prospective investors should consider carefully, in addition to the
other information in this Annual Report, the following:
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 obligated to make substantial
monthly payments to our lenders on loans which encumber our oil and gas
properties and our production revenue. We currently owe Bank of Oklahoma and
Local Oklahoma Bank approximately $27.7 million, and we are currently required
to pay approximately $600,000 per month to service this debt. We also
currently owe Kaiser-Francis Oil Company approximately $4.5 million, and we
are required to make minimum monthly payments of principal and interest on the
Kaiser-Francis debt that are equal to the greater of $150,000 or 75% of net
cash flows from our property acquisitions that were completed on November 1,
1999 and December 1, 1999. The entire amount of the Kaiser-Francis debt will
become due and payable in full on July 1, 2004. It is likely that we will
sell some of our properties to pay the amount due on the Kaiser-Francis debt
at that time. Although we also intend to seek outside capital to either
refinance our bank debt or provide liquidity, at the present time we are
almost totally dependent upon the revenues that we receive from our oil and
gas properties to service our debt. In the event that oil and gas prices
and/or production rates drop to a level 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 lose our interest in some or all of our properties.
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 conclude funding
transactions.
2. A default under our credit agreement could cause us to lose our
properties.
Our credit facility with Bank of Oklahoma and Local Oklahoma Bank allows
us to borrow, repay and reborrow amounts. 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, 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. Our
borrowing base, which determines the amounts that we are allowed to borrow or
have outstanding under our credit facility, was recently increased to $29.3
million. Subsequent determinations of our borrowing base will be made by the
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lending banks at least semi-annually on October 1 and April 1 of each year 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. Our monthly commitment reduction is currently $600,000
and will continue at that amount until the amount of the monthly commitment
reduction is redetermined. 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 exceeds the amount of the revolving commitment then in
effect, then within 30 days after we are notified by the Bank of Oklahoma, we
must make a mandatory prepayment of principal that is sufficient to cause our
total outstanding indebtedness to 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 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 of an event of default and after the expiration of any cure
period that is provided in our credit agreement, the entire principal amount
due under the notes, 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. The 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 the
terms of our agreements with our lenders.
3. History of net income (loss).
Although we had net income of $1,257,000 during fiscal 2003 we incurred
substantial losses from our operations during fiscal 2002, and we had an
accumulated deficit of $27,596,000 at June 30, 2003. During fiscal year ended
June 30, 2003, we had total revenue of $23,980,000 and operating expenses of
$20,967,000. During the fiscal year ended June 30, 2002, we had total revenue
of $8,033,000, operating expenses of $13,074,000 and a net loss for the year
of $6,253,000. During fiscal 2001 we had total revenue of $12,712,000,
operating expenses of $11,093,000 and had net income of $345,000.
4. The substantial cost to develop certain of our offshore California
properties could result in a reduction of our interest in these
properties or penalize us.
Certain of our offshore California undeveloped properties, in which we
have ownership interests ranging from 2.49% to 75%, are attributable to our
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interests in four of our five federal units (plus one additional lease)
located offshore California near Santa Barbara. 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
costs, based on our current ownership interest, is estimated to be over $200
million. Operating expenses for the same properties over the same period of
time, including platform operating costs, well maintenance and repair costs,
oil, gas and water treating costs, lifting costs and pipeline transportation
costs, are estimated to be approximately $3.5 billion, with our share, based
on our current ownership interest, estimated to be approximately $300 million.
There will be additional costs of a currently undetermined amount to develop
the Rocky Point Unit. Each working interest owner will be required to pay its
proportionate share of these costs based upon the amount of the interest that
it owns. If we are unable to fund our share of these costs or otherwise cover
them through farmouts or other arrangements, then we could either forfeit our
interest in certain wells or properties or suffer other penalties in the form
of delayed or reduced revenues under our various unit operating agreements.
5. The development of the offshore units could be delayed or halted.
Our offshore California leases are located in federal units that have
been formally approved and are regulated by the Minerals Management Service of
the federal government ("MMS"). There has historically been political
resistance to the development of these leases due to environmental concerns.
At the request of the local regulatory agencies of the affected Tri-Counties
in California, the MMS initiated a study, called the California Offshore Oil
and Gas Energy Resources(COOGER) study, which was intended to present a
long-term regional perspective of potential onshore constraints that should be
considered when developing the existing undeveloped offshore leases. The
COOGER study took several years to complete and was presented as a final
document in January of 2000. During the period while the COOGER study was
being completed, the MMS unilaterally approved suspensions of operations for
the affected leases which had the effect of allowing most of our offshore
leases to continue in effect after their stated expiration dates. During that
same period, the State of California commenced litigation in Federal Court in
California which, among other things, challenged the ability of the MMS under
federal law to approve the subject suspensions and thereby extend the terms of
the leases without providing the State of California with a formal
determination that the granting of the suspensions was consistent with the
requirements of the Coastal Zone Management Act. On June 22, 2001, the
California 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
California with a consistency determination under federal law. On July 2,
2001 these milestones were suspended by the MMS, but as of the date of this
prospectus the MMS has not yet made a consistency determination. On January
9, 2002 we and several other plaintiffs filed a separate lawsuit in the United
States Court of Federal Claims in Washington, D.C. alleging that the U.S.
Government materially breached the terms of the leases for our Offshore
13
California properties. Our suit seeks compensation for the lease bonuses and
rentals paid to the Federal Government, exploration costs, and related
expenses. While it is still our present intent to develop our Offshore
California properties as soon as possible, the ultimate outcome and effects of
the litigation pertaining to these properties are not certain at the present
time. In the event that we make a determination that development of all or any
portion of these properties is not feasible, we intend to write off an
appropriate portion of these assets on our balance sheet irrespective of the
status of our litigation against the United States government at that time.
As of June 30, 2003, these properties had an aggregate carrying value of
$10,164,000.
6. We will have to incur substantial costs in order to develop our reserves
and we may not be able to secure funding.
Relative to our financial resources, we have significant undeveloped
properties in addition to those in offshore California discussed above that
will require substantial costs to develop. During the year ended June 30,
2003, we did not participate in the drilling of any offshore wells, but we did
participate in the drilling of 9 onshore wells, of which three were non-
productive, at a cost to us of approximately $2,145,000. The cost of these
wells either has been or will be paid out of our cash flow. Although we
believe that we will participate in the drilling of additional wells during
our 2004 fiscal year, our level of oil and gas activity, including exploration
and development and property acquisitions, will be to a significant extent
dependent upon our cash flow from operations which is in turn dependent upon
the prices that we receive from the sale of our oil and gas production.
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 of 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 40% of the wells in which we
own an interest and we are dependent upon the operators of the wells that we
14
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
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. 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 authorities for which we act as a producer. We are therefore
dependent upon our ability to sell oil and gas at the prevailing well head
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. Our business is not diversified.
Since all of our resources are devoted to one industry, purchasers of our
common stock will be 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.
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
15
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.
14. We depend on key personnel.
We currently have only three employees that serve in management roles,
and the loss of any one of them could severely harm our business. In
particular, Roger A. Parker is 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.
ITEM 2. DESCRIPTION OF PROPERTY
(a) Office Facilities.
Our offices are located at 475 Seventeenth Street, Suite 1400, Denver,
Colorado 80202. We lease approximately 9,500 square feet of office space for
approximately $15,500 per month and the lease will expire in September, 2008.
(b) Oil and Gas Properties.
We own interests in producing oil and gas properties located primarily in
fourteen (14) 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
authority or agency other than the Securities and Exchange Commission during
the past two years.
Principal Properties.
---------------------
The following is a brief description of our principal properties:
Onshore:
--------
We own interests in approximately 488 gross (260 net) producing wells in
fourteen (14) states, not including interests in those wells owned by our
subsidiary, Piper Petroleum Company ("Piper"). Piper owns varying very small
interests in 666 gross (5.2 net) wells located primarily in Texas. Piper's
wells produce approximately 70 bbls per day and 470 mcf per day net to Piper's
interests. In addition to our producing properties, we have interests in
undeveloped properties and unproved undeveloped properties throughout the
United States.
Our principal onshore producing properties are in the following states:
16
Alabama
-------
We own and operate a 98.4% working interest in 52 coal bed methane gas
wells at depths of about 2,500 feet in Tuscaloosa County. These wells produce
approximately 1800 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 16 barrels per day and 100 mcf per day net to our interest.
Kansas
------
We own interests in 21 gross (16.7 net) wells in 9 separate leases
located in Sumner County, Kansas. Delta operates all of the wells located on
these leases. Current production is 850 BOPD and 450 MCFD, which is 670 BOPD
and 360 MCFD net to our interest.
Texas
-----
We own interests in 112 gross (43.9 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 37 of these wells. These
wells are scattered throughout 33 counties and are drilled to various depths
and reservoirs with varying working interests. In aggregate these wells
produce approximately 240 barrels of oil and 3,600 mcf of gas per day net to
our interest.
Pennsylvania
------------
We own 142 wells with an average working interest of approximately 64% 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 1,007 mcf
per day net to our interests.
Louisiana
---------
In Louisiana we own interests in 15 wells with an average working
interest of 58.4% located in Acadia, Catahoula, Plaquemines and Pointe Coupee
parishes. We produce primarily from the Wilcox formation at a depth of 10,000
to 11,000 feet. We operate 11 of these wells. Daily production is
approximately 220 barrels of oil per day net to our interests.
New Mexico
----------
We own interests in 36 wells in New Mexico, including the East Carlsbad
field in Eddy County where 10 of 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.
17
Other States
------------
We also own varying interests in producing wells in the following states:
California (Sacramento Basin), Colorado (Denver-Julesburg and Piceance
Basins), Nebraska, Michigan, Mississippi, Montana, Oklahoma, and Wyoming.
Offshore
---------
Offshore Federal Waters: Santa Barbara, California Area
-------------------------------------------------------
Unproved Undeveloped Properties
-------------------------------
We own interests in five undeveloped federal units (plus one additional
lease) located in federal waters offshore California near Santa Barbara.
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 any interest in any offshore California
production except for our small interest in the Point Arguello Unit discussed
below, and there is no assurance that any of our undeveloped properties will
ever achieve production.
Most of the early offshore production was from Pliocene age sandstone
reservoirs. The more recent developments are from the highly fractured zones
of the Miocene age Monterey Formation. The Monterey is productive in both the
Santa Barbara Channel 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 surveys 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
reserves in fields under development and in fields for which development is
18
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 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.
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. There can be no assurance that we
can farm out our interests on acceptable terms.
These units have been formally approved and are regulated by 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.
19
We do not act as operator of any offshore California properties and
consequently will not generally control the timing of either the development
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 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.
20
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.
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.
21
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
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.
22
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
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. In the event, however, that we receive any
23
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.
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 a portion of the Rocky Point Unit from
the Point Arguello platforms that are already in existence.
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:
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.
24
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
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.
25
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 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
26
(assumed to be 38 years), is estimated by the partners to be in excess of $3
billion. 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 we do not have sufficient cash available to pay our
share of expenses when they become payable under the respective operating
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 sales of our common stock (which may result in
substantial ownership dilution to existing shareholders), (b) bank debt from
one or 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
more 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 or all of our interests in 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. Regardless 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 arrangements or other partnership or joint
venture relationships, or 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 connection
with our plans to obtain funding from outside sources as necessary to pay our
proportionate share 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.
27
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 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.
As a result of the Norton case, the Gato Canyon 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. 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
MMS 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. 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 presence of oil
28
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.
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 anticipated 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.
29
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 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. We own 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
30
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
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 case. (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 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 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 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 or two developmental wells on the
Point Arguello Unit during fiscal 2004. 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.
31
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map page
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32
(c) Production.
During the years ended June 30, 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, $10,164,000, 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 several onshore properties. These properties are carried at our cost
basis, $12,518,000, 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 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.
33
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 and none during the year ended June 30, 2003.
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,
2003 2002 2001
---------- ---------- ----------
Onshore Offshore Onshore Offshore Onshore Offshore
------- -------- ------- -------- ------- --------
Average sales price:
Oil (per barrel) $28.81 $20.21 $22.22 $14.36 $27.10 $18.49
Natural Gas (per Mcf) $ 4.67 $ - $ 2.75 $ - $ 6.27 $ -
Hedge effect
(per barrel equivalent) $(2.50) $ - $ .17 $ - $(0.11) $ -
Production costs
(per Bbl equivalent) $ 8.37 $14.41 $ 5.68 $11.64 $ 3.88 $12.65
(d) Productive Wells and Acreage.
The table below shows, as of June 30, 2003, 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 28 7.9 9,280 2,576
Texas (4) 28 16.7 84 27.2 14,560 5,020
Colorado 6 3.5 5 4.00 1,040 780
Oklahoma 3 .96 0 0 120 38
California:
Onshore 10 .558 5 .7 1,200 134
Offshore 38 2.3 0 0 11,042 669
Wyoming 0 0 2 .634 320 101
Nebraska 1 .0625 0 0 40 3
Michigan 1 .0096 0 0 40 0
Mississippi 4 .3 4 1.0 1,440 332
Alabama 0 0 72 69.6 2,880 2,784
Pennsylvania 0 0 142 91.1 5,680 3,644
Louisiana 13 7.6 2 .88 1,160 586
Montana 10 3.2 1 .50 720 288
Kansas 21 20.2 0 0 840 808
--- ----- --- ----- ------ ------
143 56.59 345 203.5 55,482 19,107
34
(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.
(e) Undeveloped Acreage.
At June 30, 2003, we held undeveloped acreage by state as set forth
below:
Undeveloped Acres (1) (2)
-------------------------
Location Gross Net
California, offshore(3) 64,905 15,837
California, onshore 640 96
Colorado 5,163 3,283
Wyoming 1,200 632
Alabama 1,040 1,028
Texas 8,923 3,265
------ ------
Total 81,871 24,141
______________________
(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.
(f) Drilling Activity.
During the years indicated, we drilled or participated in the drilling of
the following productive and nonproductive exploratory and development wells:
35
Year Ended Year Ended Year Ended
June 30, 2003 June 30, 2002 June 30, 2001
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 3 1.55 5 2.70 6 2.24
--- ---- --- ---- --- ----
Total 3 1.55 5 2.70 6 2.24
Development Wells(1):
Productive:
Oil 0 .00 4 .242 3 .18
Gas 6 5.15 6 .491 7 .37
Nonproductive 0 .00 0 .00 0 .00
--- ---- --- ----- --- ----
Total 6 5.15 10 .733 10 .55
Total Wells(1):
Productive:
Oil 0 .00 4 .242 3 .18
Gas 6 5.15 6 2.700 7 .37
Nonproductive 3 1.55 5 .491 6 2.24
--- ---- --- ----- --- ----
Total Wells 9 6.70 15 3.433 16 2.79
______________________
(1) Does not include wells in which the 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 2004.
ITEM 3. LEGAL PROCEEDINGS
On January 9, 2002, we and several other plaintiffs filed a lawsuit in
the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government has materially breached the terms of forty undeveloped
federal leases, some of which are part of our Offshore California properties.
The Complaint is based on allegations by the collective plaintiffs that the
United States has materially breached the terms of certain of their Offshore
California leases by attempting to deviate significantly from the procedures
and standards that were in effect when the leases were entered into, and by
failing to carry out its own obligations relating to those leases in a timely
and fair manner. More specifically, the plaintiffs have alleged that the
judicial determination in the California v. Norton case that a 1990 amendment
to the Coastal Zone Management Act 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.
36
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. 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, which motion has not yet been heard
by the court.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth
quarter of our fiscal year.
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS.
The following information with respect to Directors and Executive
Officers is furnished pursuant to Item 401(a) of Regulation S-K.
Name Age Positions Period of Service
- ---- --- --------- -----------------
Aleron H. Larson, Jr. 58 Chairman of the Board, May 1987 to Present
Secretary and a Director
Roger A. Parker 41 President, Chief May 1987 to Present
Executive Officer and
a Director
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
Kevin K. Nanke 38 Treasurer and Chief December 1999 to
Financial Officer Present
The following is biographical information as to the business experience
of each of our current officers and directors.
37
Aleron H. Larson, Jr. has operated as an independent in the oil and gas
industry individually and through public and private ventures since 1978. Mr.
Larson served as 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"), 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 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 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 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 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 the
Independent Producers Association of the Mountain States (IPAMS).
Jerrie F. Eckelberger is an investor, real estate developer and attorney
who has practiced law in the State of Colorado since 1971. He graduated from
Northwestern University with a Bachelor of Arts degree in 1966 and received
his Juris Doctor degree in 1971 from the University of Colorado School of Law.
From 1972 to 1975, Mr. Eckelberger was a staff attorney with the eighteenth
Judicial District Attorney's Office in Colorado. From 1975 to present, Mr.
Eckelberger has practiced 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 development of real estate in Colorado. 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 Member of the
Woods at Pole Creek, a Colorado limited liability company, specializing in
real estate development.
James B. Wallace has been involved in the oil and gas business for over
40 years and has been a partner of Brownlie, Wallace, Armstrong and Bander
Exploration in Denver, Colorado since 1992. From 1980 to 1992 he was Chairman
of the Board and Chief Executive Officer of BWAB Incorporated. Mr. Wallace
38
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 listed on
the New York Stock Exchange. He received a B.S. Degree in Business
Administration from the University of Southern California in 1951.
Joseph L. Castle II has been a Director of Castle Energy Corporation
("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") Settlement
Trust.
Russell S. Lewis 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's Global Registry Services Group, which maintains the authoritative
database for all ".com", ".net" and ".org" domain names in the Internet.
John P. Keller 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, 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.
There is no family relationship among or between any of our Officers
and/or Directors.
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.
39
Messrs. Castle, Wallace and Eckelberger serve as the Incentive Plan
Committee and as the Compensation Committee.
Messrs. Lewis, Keller, Eckelberger and Wallace serve as the Audit
Committee and 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'
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.
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) Market Information.
Delta's common stock currently trades under the symbol "DPTR" on NASDAQ.
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, 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
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
On September 15, 2003 the closing price of the Common Stock was $5.24.
(b) Approximate Number of Holders of Common Stock.
The number of holders of record of our Common Stock at September 15, 2003
was approximately 1,000 which does not include an estimated 2,600 additional
holders whose stock is held in "street name."
(c) 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.
On June 30, 2003, we completed an acquisition of certain oil and gas
properties in Kansas from JAED Production Company, Inc. ("JAED") in exchange
for cash and stock. We issued 200,000 shares of our common stock to JAED as
part of the consideration paid.
40
This transaction was exempt from registration under Section 4(2) of the
Securities Act of 1933. The investor was provided with complete information
about Delta. We reasonably believe that the investor is an "Accredited
Investor" as such term is defined in Rule 501 of Regulation D promulgated
under the Securities Act of 1933 at the time the transaction occurred. The
investor acquired the shares for investment purposes. A restrictive legend
was placed on the certificate issued to the investor, and stop transfer orders
were given to our transfer agent.
Options
-------
We received the proceeds from the exercise of options to purchase shares
of our common stock of $975,000, $407,000 and $1,480,000 during the years
ended June 30, 2003, 2002 and 2001, respectively.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information should be read in
conjunction with our financial statements and the accompanying notes.
Fiscal Years Ended June 30,
-------------------------------------------------------------------
2003 2002 2001 2000 1999
----------- ----------- ----------- ----------- -----------
Total Revenues $23,980,000 $ 8,033,000 $12,712,000 $ 3,576,000 $ 1,695,000
Income/(Loss) from
Operations $ 3,013,000 $(5,041,000) $ 1,619,000 $(2,079,000) $(2,905,000)
Net Income (Loss) $ 1,257,000 $(6,253,000) $ 345,000 $(3,367,000) $(2,999,000)
Income/(Loss)
Per Share $ .05 $ (.49) $ .03 $ (0.46) $ (0.51)
Total Assets $86,847,000 $74,077,000 $29,832,000 $21,057,000 $11,377,000
Total Liabilities $38,944,000 $29,161,000 $11,551,000 $10,094,000 $ 1,531,000
Stockholders' Equity $47,903,000 $44,916,000 $18,281,000 $10,963,000 $ 9,846,000
Total Long Term Debt $32,214,000 $24,939,000 $ 9,434,000 $ 8,245,000 $ 1,000,000
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Liquidity and Capital Resources
-------------------------------
Liquidity is a measure of a company's ability to access cash. We have
historically addressed our long-term liquidity requirements through the
issuance of debt and equity securities, when market conditions permit, and
most recently through the use of our bank credit facility and cash provided by
operating activities. 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.
41
We continue to examine alternative sources of long-term capital,
including bank borrowings, the issuance of debt instruments, the sale of
common stock, the sales of non-strategic assets, and joint venture financing.
Availability of these sources of capital and, therefore, our ability to
execute our operating strategy will depend upon a number of factors, some of
which are beyond our control.
We believe that borrowings under the Revolving Credit Facility, projected
operating cash flows and cash on hand will be sufficient to meet the
requirements of our business. However, future cash flows are subject to a
number of variables including the level of production and oil and natural gas
prices. We cannot assure you that operations and other capital resources will
provide cash in sufficient amounts to maintain planned levels of capital
expenditures or that increased capital expenditures will not be undertaken.
Actual levels of capital expenditures may vary significantly due to a variety
of factors, including but not limited to; drilling results, product pricing
and future acquisition and divestitures of properties.
Working Capital
---------------
Although we show a working capital deficit of $7,234,000 at June 30,
2003, we believe our current obligations will be paid from current cash flow.
Our current portion of long-term debt includes a monthly commitment of
$600,000 relating to our credit facility and the entire Kaiser Francis note
payable of $4,546,000 which is due and payable on June 1, 2004.
Cash Provided by (Used in) Operating Activities
-----------------------------------------------
During the year ended June 30, 2003, we had cash provided by operating
activities of $7,999,000 compared to cash used in operating activities of
$1,870,000 during the same period ended June 30, 2002. This increase in
operating activities is a result of the increase in oil and natural gas sales
relating to the Castle and Piper acquisitions completed during fiscal 2002.
Cash Used in Investing Activities
---------------------------------
During the year ended June 30, 2003, we had cash used in investing
activities of $14,468,000 compared to cash used in investing activities of
$13,112,000 during the same period ended June 30, 2002. Investing activities
for fiscal 2003 included $9,000,000 used for the acquisition of JAED,
$6,637,000 for exploration and development activities, offset by proceeds from
sales of properties of $850,000. Investing activities for fiscal 2002
included approximately $13,500,000, net of purchase price adjustments, used
for the acquisition of Castle, approximately $4,460,000 for exploration and
development costs, offset by proceeds from sale of properties of $4,313,000.
Cash Provided by Financing Activities
-------------------------------------
During the year ended June 30, 2003, we had cash provided by financing
activities of $7,896,000 compared to $15,488,000 for the same period ended
42
June 30, 2002. Financing activities for fiscal 2003 consist of proceeds from
borrowings of $9,000,000 to acquire JAED, repayment of borrowings and
financing costs of $2,079,000 and stock issued for cash upon exercise of
options of $975,000. Financing activities for fiscal 2002 consist of proceeds
from borrowings of $21,778,000, repayment of borrowings and financing costs of
$6,922,000, stock issued for cash upon exercise of options of $407,000 and
stock issued for cash of $225,000.
Fiscal 2003 Acquisition
-----------------------
On June 20, 2003, Delta acquired producing oil and gas interests and
related undeveloped acreage in Kansas from JAED Production Company ""JAED"),
an unrelated entity. Delta paid $9,000,000 in cash 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 announcement of the
transaction. Delta recorded a purchase price adjustment of approximately
$291,000 which reflects the net revenues after operating costs and acquisition
related costs from the effective date of June 1, 2003 through the closing date
of June 20, 2003.
Fiscal 2004 Property Expenditures
---------------------------------
We estimate our capital expenditures for onshore properties to range from
$3.5 million to $7.7 million depending on drill rig availability and success
of drilling programs for the year ending June 30, 2004. We anticipate that we
will drill one to two developmental wells on the Point Arguello Unit during
fiscal 2004. Each well will cost approximately $2.8 million ($170,000 to our
interest). We anticipate paying for all capital expenditures out of
anticipated cash flow which assumes certain price levels for production.
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, 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. The Investment Agreement was amended and restated on April 10, 2002. 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. On December 20, 2002 the parties entered into an
agreement which terminated the investment agreement with Swartz.
Options
-------
We received the proceeds from the exercise of options to purchase shares
of our common stock of $975,000, $407,000 and $1,480,000 during the years
ended June 30, 2003, 2002 and 2001, respectively.
43
Credit Facility
---------------
Our credit facility allows us to borrow, repay and reborrow amounts
subject to the terms and conditions 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 in 2002, 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, certain bank accounts and proceeds. Under
the terms of the 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 used by
the Bank of Oklahoma as of the date that the determination is made using the
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.
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 million at the time we entered into the Credit Agreement and
expanded to $29.3 million with the conclusion of the JAED Acquisition in June
of 2003. Subsequent determinations of our borrowing base will be made by the
lending banks at least semi-annually on October 1 and April 1 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. The monthly commitment reduction was adjusted to
$600,000 beginning as of August 1, 2003 and will continue at that amount until
the amount of the monthly commitment reduction is redetermined.
If an unscheduled redetermination of 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, our borrowing base and the revolving commitment of the banks
to lend money under the Credit Agreement will be reduced as of the first day
of each month by an amount determined by the banks under the Credit Agreement.
The amount of the borrowing base will 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
44
amount of our 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 are notified by the Bank of Oklahoma, we must make a mandatory
prepayment of principal that is sufficient to cause our total outstanding
indebtedness to 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 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 proceeds
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
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.
Results of Operations Fiscal 2003 Compared to Fiscal 2002
---------------------------------------------------------
Net Income (Loss). Our net income for the year ended June 30, 2003 was
$1,257,000 compared to a net loss of $6,253,000 for the year ended June 30,
2002. The results for the years ended June 30, 2003 and 2002 were affected by
the items described in detail below.
Revenue. Total revenue for the year ended June 30, 2003 was $23,980,000
compared to $8,033,000 for the year ended June 30, 2002. Oil and gas sales
for the year ended June 30, 2003 were $25,561,000 compared to $8,082,000 for
the year ended June 30, 2002. The increase in oil and gas sales during the
year ended June 30, 2003 resulted primarily from the Castle and Piper
acquisitions completed during fiscal 2002.
45
Production volumes and average prices received for the years ended June
30, 2003 and 2002 are as follows:
2003 2002
Onshore Offshore Onshore Offshore
------- -------- ------- --------
Production:
Oil (barrels) 252,000 227,000 89,000 262,000
Gas (Mcf) 2,938,000 - 871,000 -
Average Price:
Oil (per barrel) $28.81 $20.21 $22.22 $14.36
Gas (per Mcf) $ 4.67 $ - $ 2.75 $ -
Hedge effect
(per barrel equivalent) $(2.50) $ - $0.17 $ -
Gain (Loss) on Sale of Oil and Gas Properties. During the years ended
June 30, 2003 and 2002, we disposed of certain oil and gas properties and
related equipment to unaffiliated entities. We have received proceeds from
the sales of $850,000 during the year ended June 30, 2003 and $4,313,000
during the year ended June 30, 2002, which resulted in a gain on sale of oil
and gas properties of $277,000 for the year ended June 30, 2003 and a loss on
sale of $88,000 for the year ended June 30, 2002.
Lease Operating Expenses. Lease operating expenses for the year ended
June 30, 2003 were $9,479,000 compared to $4,314,000 for the year ended June
30, 2002. Lease operating expense increased compared to 2002 primarily as a
result of the Castle and Piper Acquisitions. On a per Bbl equivalent basis,
production expenses and taxes were $8.37 for onshore properties and $14.41 for
offshore properties during the year ended June 30, 2003 compared to $5.68 for
onshore properties and $11.64 for offshore properties for the year ended June
30, 2002. The change in lease operating expense per Bbl equivalent fluctuates
with the nature of the properties including maturity and non-capitalized
workover costs incurred during the year.
Depreciation and Depletion Expense. Depreciation and depletion expense
for the year ended June 30, 2003 was $5,790,000 compared to $3,347,000 for the
year ended June 30, 2002. On a per Bbl equivalent basis, the depletion rate
was $6.27 for onshore properties and $4.73 for offshore properties during the
year ended June 30, 2003 compared to $9.57 for onshore properties and $4.20
for offshore properties for the year ended June 30, 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.
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, 2002 of $1,480,000. Our proved properties were assessed
for impairment on an individual field basis and we recorded impairment
provisions attributable to certain producing properties of $-0- and $878,000
for the years ended June 30, 2003 and 2002, respectively. Also during fiscal
2002, we recorded an impairment of $602,000 attributable to our undeveloped
46
properties as future development of these properties is unlikely. We made a
determination based on the political risk and lack of expertise in the area
that it may not be economical to develop our prospect located in Kazakhstan
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, 2003
were $842,000 compared to $1,322,000 for the year ended June 30, 2002.
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
the Company's undeveloped offshore California leases.
General and Administrative Expenses. General and administrative expenses
for year ended June 30, 2003 were $4,179,000 compared to $2,060,000 for the
year ended June 30, 2002. The increase in general and administrative expenses
is primarily attributed to increased costs for the acquisitions completed in
fiscal 2002 including office relocation and additional staff.
Interest and Financing Costs. Interest and financing costs for the year
ended June 30, 2003 were $1,767,000 compared to $1,325,000 for the year ended
June 30, 2002. The increase in interest and financing costs can be attributed
to the increase in debt relating to the Castle acquisition which closed on May
31, 2002.
Results of Operations Fiscal 2002 Compared to Fiscal 2001
---------------------------------------------------------
Net Income (Loss). Our net loss for the year ended June 30, 2002 was
$6,253,000 compared to net income of $345,000 for the year ended June 30,
2001. The results for the years ended June 30, 2002 and 2001 were affected by
the items described in detail below.
Revenue. Total revenue for the year ended June 30, 2002 was $8,033,000
compared to $12,712,000 for the year ended June 30, 2001. Oil and gas sales
for the year ended June 30, 2002 were $8,082,000 compared to $12,277,000 for
the year ended June 30, 2001. The decrease in oil and gas sales during the
year ended June 30, 2002 resulted primarily from the sale of twenty producing
wells and five injection wells located 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.
Production volumes and average prices received for the years ended June
30, 2002 and 2001 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:
Oil (per barrel) $22.22 $14.36 $27.10 $18.49
Gas (per Mcf) $ 2.75 $ - $ 6.27 -
Hedge effect
(per barrel equivalent) $0.17 $ - $(0.11) $ -
47
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 $4,313,000 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.
Lease Operating Expenses. Lease operating expenses for the year ended
June 30, 2002 were $4,314,000 compared to $4,698,000 for the year ended June
30, 2001. Lease operating expense decreased slightly compared to 2001 as a
result of less non-capitalized workover costs incurred during fiscal 2002
compared to fiscal 2001. On a per Bbl equivalent basis, production expenses
and taxes were $5.68 for onshore properties and $11.64 for offshore properties
during the year ended June 30, 2002 compared to $3.88 for onshore properties
and $12.65 for offshore properties for the year ended June 30, 2001.
Depreciation and Depletion Expense. Depreciation and depletion expense
for the year ended June 30, 2002 was $3,347,000 compared to $2,533,000 for the
year ended June 30, 2001. On a per Bbl equivalent basis, the depletion rate
was $9.57 for onshore properties and $4.20 for offshore properties during the
year ended June 30, 2002 compared to $8.16 for onshore properties and $2.71
for offshore properties for the year ended June 30, 2001.
Exploration Expenses. Exploration expenses consist of geological and
geophysical costs and lease rentals. Exploration expenses were $155,000 for
the year ended June 30, 2002 compared to $89,000 for the year ended June 30,
2001.
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, 2002 of $1,480,000. 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 and
$174,000 for the years ended June 30, 2002 and 2001, 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 would
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, 2002
were $1,322,000 compared to $1,108,000 for the year ended June 30, 2001. The
increase in professional fees compared to fiscal 2001 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, 2002 were $2,060,000 compared to $1,773,000 for the
year ended June 30, 2001. The increase in general and administrative expenses
is primarily attributed to increased costs in anticipation of the acquisitions
completed in fiscal 2002 including office relocation and additional staff.
48
Interest and Financing Costs. Interest and financing costs for the year
ended June 30, 2002 were $1,325,000 compared to $1,861,000 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 $587,000 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.
Critical Accounting Policies and Estimates
------------------------------------------
The discussion and analysis of the Company's 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 Regarding Disclosure
About Critical Accounting Policies," we have identified certain of these
policies as being of particular importance to the portrayal of our financial
position and results of operations and which require the application of
significant judgment by management. We analyze our estimates, including those
related to oil and gas reserves, bad debts, oil and gas properties, marketable
securities, income taxes, derivatives, contingencies and litigation, and base
our estimates on historical experience and various other assumptions that we
believe reasonable under the circumstances. Actual results may differ from
these estimates under different assumptions or conditions. We believe the
following critical accounting policies affect our more significant judgments
and estimates used in the preparation of the Company's financial statements.
Successful Efforts Method of Accounting
---------------------------------------
We account for our natural gas and crude oil exploration and development
activities utilizing the successful efforts method of accounting. Under this
method, costs of productive exploratory wells, development dry holes and
productive wells and undeveloped leases are capitalized. 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
49
industry experience. Wells may be completed that are assumed to be productive
and actually deliver gas and oil in quantities insufficient to be economic,
which may result in the abandonment of the wells at a later date. Wells are
drilled that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly
account for the results. Delineation seismic incurred to select development
locations within an oil and gas field is typically considered a development
cost and capitalized, but often these seismic programs extend beyond the
reserve area considered proved and management must estimate the portion of the
seismic costs to expense. The evaluation of gas and oil leasehold acquisition
costs requires managerial judgment to estimate the fair value of these costs
with reference to drilling activity in a given area. Drilling activities in
an area by other companies may also effectively condemn leasehold positions.
The successful efforts method of accounting can have a significant impact
on the operational results reported when the Company is entering a new
exploratory area in hopes of finding a gas and oil field that will be the
focus of future development drilling activity. The initial exploratory wells
may be unsuccessful and will be expensed. Seismic costs can be substantial
which will result in additional exploration expenses when incurred.
Reserve Estimates
-----------------
Estimates of gas and oil reserves, by necessity, are projections based on
geologic and engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is
a subjective process of estimating underground accumulations of gas and oil
that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable gas and
oil reserves and future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future gas and
oil prices, future operating costs, severance taxes, development costs and
workover gas costs, all of which may in fact vary considerably from actual
results. The future drilling costs associated with reserves assigned to
proved undeveloped locations may ultimately increase to an extent that these
reserves may be later determined to be uneconomic. For these reasons,
estimates of the economically recoverable quantities of gas and oil
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected therefrom may vary substantially. Any significant variance in the
assumptions could materially affect the estimated quantity and value of the
reserves, which could affect the carrying value of our gas and oil properties
and/or the rate of depletion of the gas and oil properties. Actual
production, revenues and expenditures with respect to our reserves will likely
vary from estimates, and such variances may be material.
Impairment of Gas and Oil Properties
------------------------------------
We review our oil and gas properties for impairment whenever events and
circumstances indicate a decline in the recoverability of their carrying
50
value. We estimate the expected future cash flows of our proved properties
and compare such future cash flows to the carrying amount of the proved
properties to determine if the carrying amount is recoverable. If the
carrying amount exceeds the estimated undiscounted future cash flows, we will
adjust the carrying amount of the oil and gas properties to their fair value.
The factors used to determine fair value include, but are not limited to,
estimates of proved reserves, future commodity pricing, future production
estimates, anticipated capital expenditures, and a discount rate commensurate
with the risk associated with realizing the expected cash flows projected.
Given the complexities associated with gas and oil reserve estimates and
the history of price volatility in the gas and oil markets, events may arise
that would require the Company to recorded an impairment of the recorded book
values associated with gas and oil properties. As a result of its review, the
Company recognized an impairment of $1,480,000 and $798,000 for the years
ended June 30, 2002 and 2001, respectively. The Company did not record an
impairment during the year ended June 30, 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, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." Under SFAS No. 133 all derivative
instruments are recorded on the balance sheet at fair value. Changes in the
derivative's fair value are recognized currently in earnings unless specific
hedge accounting criteria are met. For qualifying cash flow hedges, the gain
or loss on the derivative is deferred in accumulated other comprehensive
income (loss) to the extent the hedge is effective. For qualifying fair value
hedges, the gain or loss on the derivative is offset by related results of the
hedged item in the income statement. Gains and losses on hedging instruments
included in accumulated other comprehensive income (loss) are reclassified to
oil and natural gas sales revenue in the period that the related production is
delivered. Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at market value in
the consolidated balance sheet, and the associated unrealized gains and losses
are recorded as current expense or income in the consolidated statement of
operations. While such derivative contracts do not qualify for hedge
accounting, management believes these contracts can be utilized as an
effective component of commodity price risk management (CPRM) activities.
We account for our asset retirement obligations under SFAS No. 143
"Accounting for Asset Retirement Obligations". SFAS No. 143 requires entities
to record the fair value of a liability for retirement obligations of acquired
assets. SFAS No. 143 is effective for fiscal years beginning after June 15,
2002. The Company adopted SFAS No. 143 on July 1, 2002 and recorded a
51
cumulative effect of a change in accounting principle on prior years related
to the depreciation and accretion expense that would have been reported had
the fair value of the asset retirement obligations, and corresponding increase
in the carrying amount of the related long-lived assets, been recorded when
incurred. The Company's asset retirement obligations arise from the plugging
and abandonment liabilities for its oil and gas wells.
Recently Issued or Proposed Accounting Standards and Pronouncements
-------------------------------------------------------------------
We have been made aware that an issue has arisen within the industry
regarding the application of provisions of SFAS No. 142 and SFAS No. 141,
"Business Combinations," to companies in the extractive industries, including
oil and gas companies. The issue is whether SFAS No. 142 requires companies to
reclassify costs associated with mineral rights, including both proved and
unproved leasehold acquisition costs, as intangible assets in the balance
sheet, apart from other capitalized oil and gas property costs. Historically,
we and other oil and gas companies have included the cost of these oil and gas
leasehold interests as part of oil and gas properties. Also under
consideration is whether SFAS No. 142 requires registrants to provide the
additional disclosures prescribed by SFAS No. 142 for intangible assets for
costs associated with mineral rights.
If it is ultimately determined that SFAS No. 142 requires us to
reclassify costs associated with mineral rights from property and equipment to
intangible assets, the amounts that would be reclassified are as follows:
June 30,
2003 2002
----------- -----------
INTANGIBLE ASSETS:
Proved leasehold acquisition costs $68,966,000 $58,170,000
Unproved leasehold acquisition costs 10,164,000 9,722,000
----------- -----------
Total leasehold acquisition costs 79,130,000 67,892,000
Less: Accumulated depletion 10,858,000 6,349,000
----------- -----------
Net leasehold acquisition costs $68,272,000 $61,534,000
----------- -----------
The reclassification of these amounts would not affect the method in
which such costs are amortized or the manner in which we assess impairment of
capitalized costs. As a result, net income would not be affected by the
reclassification.
Statement 145, Rescission 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
52
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 January 1, 2003. We
do not believe this statement will have a material impact on our Financial
Statements.
In November 2002, the FASB issued Financial Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others - an interpretation of FASB
Statements Nos. 5, 57, and 107 and rescission of FASB Interpretation No. 34"
("FIN 45"). FIN 45 elaborates on the disclosures to be made by a guarantor in
its interim and annual financial statements about its obligations under
certain guarantees that it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of a guarantee, a liability for the
fair value of the obligation undertaken in issuing the guarantee. The initial
recognition and initial measurement provisions of FIN 45 are applicable on a
prospective basis to guarantees issued or modified after December 31, 2002,
irrespective of the guarantor's fiscal year-end. The disclosure requirements
are effective for financial statements of interim or annual periods ending
after December 15, 2002. The adoption of FIN 45 has not had any effect on our
financial position or results of operations.
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 making 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 date. It applies in the first fiscal year or interim period beginning
after June 15, 2003 to variable interest entities in which an enterprise holds
a variable interest that it acquired before February 1, 2003. At this time, we
do not have a VIE.
In April 2003, FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 149 is effective for contracts entered into
or modified after June 30, 2003 and for hedging relationships designated after
June 30, 2003. We adopted SFAS No. 149 on July 1, 2003 and do not expect it
to have a material impact on our financial condition and results of
operations.
53
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity."
SFAS No. 150 changes the accounting for certain financial instruments that,
under previous guidance, issuers could account for as equity. FASB No. 150
requires that those instruments be classified as liabilities in statements of
financial position. SFAS No. 150 is effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. SFAS No.
150 is not expected to have a material impact on our financial condition and
results of operations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the potential loss arising from adverse changes in market
rates and prices, such as foreign currency exchange and interest rates and
commodity prices. We do not use financial instruments to any degree to manage
foreign currency exchange and interest rate risks and do not hold or issue
financial instruments to any degree for trading purposes. All of our revenue
and related receivables are payable in U.S. dollars.
Market Rate and Price Risk
--------------------------
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 volatile oil and gas prices and to manage the exposure to
commodity price risk.
Interest Rate Risk
------------------
We were subject to interest rate risk on $32,214,000 of variable rate
debt obligations at June 30, 2003. The annual effect of a one percent change
in interest rates would be approximately $320,000. The interest rate on these
variable rate debt obligations approximates current market rates as of June
30, 2003.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial statements are included and begin on page F-1. There are no
financial statement schedules since they are either not applicable or the
information is included in the notes to the financial statements.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
54
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures:
We maintain disclosure controls and procedures that are designed to
ensure that information required to be disclosed in our Exchange Act reports
is recorded, processed, summarized and reported within the time periods
specified in the Securities and Exchange Commission's rules and forms, and
that such information is accumulated and communicated to management, including
the chief executive officer and chief financial officer, as appropriate, to
allow timely decisions regarding required disclosure. Management necessarily
applied its judgment in assessing the costs and benefits of such controls and
procedures, which, by their nature, can provide only reasonable assurance
regarding management's control objectives.
With the participation of management, our chief executive officer and
chief financial officer evaluated the effectiveness of the design and
operation of our disclosure controls and procedures at the conclusion of the
period ended June 30, 2003. 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 it files 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.
PART III
The information required by Part III, Item 10 "Directors and Executive
Officers of the Registrant," Item 11 "Executive Compensation," Item 12
"Security Ownership of Certain Beneficial Owners and Management," Item 13
"Certain Relationships and Related Transactions" and Item 14 "Principal
Accounting Fees and Services" is incorporated by reference to the Company's
definitive Proxy Statement which will be filed with the Securities and
Exchange Commission in connection with the Annual Meeting of Shareholders.
For information concerning Item 10 "Directors and Executive Officers of the
Registrant," see Part I; Item 4A.
55
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements.
Page No.
Independent Auditors' Report .................................... F-1
Consolidated Balance Sheets for the years ended
June 30, 2003 and 2002 .......................................... F-2
Consolidated Statements of Operations for the years
ended June 30, 2003, 2002 and 2001 .............................. F-3
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (Loss) for the
years ended June 30, 2003, 2002 and 2001 ........................ F-4
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (Loss) for the
years ended June 30, 2003, 2002 and 2001 ........................ F-5
Consolidated Statements of Cash Flows for the
years ended June 30, 2003, 2002 and 2001 ........................ F-6
Notes to Consolidated Financial Statements ...................... F-7
Financial Statement Schedules. None.
(b) Reports on Form 8-K. During the quarter ended June 30, 2003, the
Registrant filed Reports on Form 8-K as follows:
1. Form 8-K; May 12, 2003; Items 7 and 9
2. Form 8-K; June 20, 2003; Items 2 and 7
3. Form 8-K/A; June 20, 2003; Items 5 and 7
(c) Exhibits. The Exhibits listed in the Index to Exhibits appearing at
page 57 are filed as part of this report.
56
INDEX TO EXHIBITS
2. Plans of Acquisition, Reorganization, Arrangement, Liquidation, or
Succession. Not applicable.
3. Articles of Incorporation and By-laws. The Articles of Incorporation and
Articles of Amendment to Articles of Incorporation and By-laws of 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 Report on Form 8-K dated June
15, 1988. Statement 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.
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.
57
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 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.
10.12 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.
10.13 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.
10.14 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.
10.15 Delta Petroleum Corporation 2002 Incentive Plan incorporated by
reference from Exhibit A to the Company's definitive proxy statement
filed May 1, 2002.
10.16 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.
10.17 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.
10.18 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.
10.19 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.
58
10.20 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.
10.21 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.
10.22 Agreement with Arguello, Inc. Filed herewith electronically.
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.
59
Independent Auditors' Report
The Board of Directors and Stockholders
Delta Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Delta
Petroleum Corporation (the Company) and subsidiary as of June 30, 2003 and
2002 and the related consolidated statements of operations, stockholders'
equity and comprehensive income (loss), and cash flows for each of the years
in the three year period ended June 30, 2003. These financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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 statements 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, 2003 and 2002 and the
results of their operations and their cash flows for each of the years in the
three-year period ended June 30, 2003, in conformity with accounting
principles generally accepted in the United States of America.
As described in Note 1 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
August 22, 2003
F-1
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, June 30,
2003 2002
----------- ------------
ASSETS
Current Assets:
Cash and cash equivalents $ 2,271,000 $ 1,024,000
Marketable securities available for sale 662,000 485,000
Trade accounts receivable, net of
allowance for doubtful accounts of $50,000 at
June 30, 2003 and June 30, 2002 4,410,000 4,713,000
Prepaid assets 764,000 785,000
Other current assets 560,000 442,000
----------- ------------
Total current assets 8,667,000 7,449,000
----------- ------------
Property and Equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting): 90,487,000 73,002,000
Less accumulated depreciation and depletion (12,669,000) (7,018,000)
----------- -----------
Net property and equipment 77,818,000 65,984,000
----------- -----------
Long term assets:
Deferred financing costs 117,000 260,000
Partnership net assets 245,000 384,000
----------- -----------
Total long term assets 362,000 644,000
----------- -----------
$86,847,000 $74,077,000
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current portion of long-term debt $10,039,000 $ 3,498,000
Accounts payable 3,604,000 3,488,000
Derivative instruments 468,000 -
Current foreign tax payable 703,000 703,000
Other accrued liabilities 1,087,000 31,000
----------- -----------
Total current liabilities 15,901,000 7,720,000
----------- -----------
Long-term Liabilities:
Asset retirement obligation 868,000 -
Long-term debt, net 22,175,000 21,441,000
----------- -----------
Total long-term liabilities 23,043,000 21,441,000
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
23,286,000 shares at June 30, 2003
and 22,618,000 at June 30, 2002 233,000 226,000
Additional paid-in capital 75,642,000 76,514,000
Put option on Delta stock - (2,886,000)
Accumulated other comprehensive loss (376,000) (85,000)
Accumulated deficit (27,596,000) (28,853,000)
----------- -----------
Total stockholders' equity 47,903,000 44,916,000
----------- -----------
Commitments $86,847,000 $74,077,000
=========== ===========
See accompanying notes to consolidated financial statements.
F-2
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended June 30,
2003 2002 2001
----------- ----------- -----------
Revenue:
Oil and gas sales $25,561,000 $ 8,082,000 $12,277,000
Realized gain (loss) on derivative instruments, net (1,858,000) 39,000 (23,000)
Gain (loss) on sale of oil and gas properties 277,000 (88,000) 458,000
----------- ----------- -----------
Total revenue 23,980,000 8,033,000 12,712,000
Operating expenses:
Lease operating expenses 9,479,000 4,314,000 4,698,000
Depreciation and depletion 5,790,000 3,347,000 2,533,000
Exploration expenses 140,000 155,000 89,000
Abandoned and impaired properties - 1,480,000 798,000
Dry hole costs 537,000 396,000 94,000
Professional fees 842,000 1,322,000 1,108,000
General and administrative (includes stock option expense
of $124,000, $143,000 and $409,000 for the years ended
June 30, 2003, 2002 and 2001, respectively.) 4,179,000 2,060,000 1,773,000
----------- ----------- -----------
Total operating expenses 20,967,000 13,074,000 11,093,000
----------- ----------- -----------
Income (loss) from operations 3,013,000 (5,041,000) 1,619,000
Other income and (expense):
Other income 31,000 113,000 587,000
Interest and financing costs (1,767,000) (1,325,000) (1,861,000)
----------- ----------- -----------
Total other expense (1,736,000) (1,212,000) (1,274,000)
----------- ----------- -----------
Income (loss) before cumulative effect of
Change in accounting principle 1,277,000 $(6,253,000) $ 345,000
Cumulative effect of change in accounting principle (20,000) - -
----------- ----------- -----------
Net income (loss) $ 1,257,000 $(6,253,000) $ 345,000
=========== =========== ===========
Net income (loss) per common share:
Basic $ .05 $ (0.49) $ 0.03
=========== =========== ===========
Diluted $ .05 $ (0.49)* $ 0.03
=========== =========== ===========
* Potentially dilutive securities outstanding were anti-dilutive
See accompanying notes to consolidated financial statements.
F-3
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (Loss)
Years Ended June 30, 2003, 2002 and 2001
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, June 30, 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
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
F-4
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (Loss)
Years Ended June 30, 2003, 2002 and 2001
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 income:
Net income - - - - - 1,257,000 1,257,000 1,257,000
Other comprehensive
income, net of tax
Change in fair value
of derivative
hedging instruments - - - - (468,000) (468,000) - (468,000)
Unrealized gain on equity
securities, net - - - - 177,000 177,000 - 177,000
----------
Comprehensive income - - - - - 966,000
Stock options granted as
compensation 124,000 - - ========== - 124,000
Put option on Delta stock - - (2,886,000) 2,886,000 -
Shares issued for oil and
gas properties 200,000 2,000 920,000 - - - 922,000
Shares issued for cash
upon exercise of options 468,000 5,000 970,000 - - - 975,000
---------- -------- ----------- ---------- --------- ------------ -----------
Balance, June 30, 2003 23,286,000 $233,000 $75,642,000 $ - $(376,000) $(27,596,000) $47,903,000
========== -------- ----------- ========== ========= ============ ===========
See accompanying notes to consolidated financial statements.
F-5
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended June 30,
2003 2002 2001
------------ ------------ -----------
Cash flows operating activities:
Net income (loss) $ 1,257,000 $ (6,253,000) $ 345,000
Adjustments to reconcile net income (loss) to cash
used in operating activities:
Depreciation and depletion 5,790,000 3,347,000 2,533,000
Stock option expense 124,000 143,000 520,000
Amortization of financing costs 456,000 582,000 506,000
Abandoned and impaired properties - 1,480,000 798,000
(Gain) loss on sale of oil and gas properties (277,000) 88,000 (458,000)
Shares issued for services - 48,000 -
Cumulative effect of change in accounting principle 20,000 - -
Net changes in operating assets and operating
liabilities:
Increase in trade accounts receivable (101,000) (1,265,000) (1,204,000)
Decrease (increase) in prepaid assets 21,000 (191,000) (221,000)
Increase (decrease) in other current assets (78,000) (6,000) 66,000
Increase in accounts payable 116,000 172,000 222,000
Increase (decrease) in other accrued liabilities 671,000 (15,000) (328,000)
------------ ------------ -----------
Net cash provided by (used in) operating activities $ 7,999,000 $ (1,870,000) $ 2,779,000
------------ ------------ -----------
Cash flows from investing activities:
Additions to property and equipment, net (15,637,000) (17,959,000) (11,613,000)
Proceeds from sale of oil and gas properties 850,000 4,313,000 3,700,000
Merger with Piper Petroleum - 74,000 -
Increase (decrease) in long term assets 139,000 460,000 (169,000)
------------ ------------ -----------
Net cash used in investing activities (14,648,000) (13,112,000) (8,082,000)
------------ ------------ -----------
Cash flows from financing activities:
Stock issued for cash upon exercise of options 975,000 407,000 1,480,000
Issuance of common stock for cash - 225,000 2,422,000
Proceeds from borrowings 9,000,000 21,778,000 14,394,000
Repayment of borrowings (1,725,000) (6,673,000) (12,777,000)
Payment of financing fees (354,000) (249,000) -
------------ ------------ -----------
Net cash provided by financing activities 7,896,000 15,488,000 5,519,000
------------ ------------ -----------
Net increase in cash and cash equivalents 1,247,000 506,000 216,000
------------ ------------ -----------
Cash at beginning of period 1,024,000 518,000 302,000
------------ ------------ -----------
Cash at end of period $ 2,271,000 $ 1,024,000 $ 518,000
============ ============ ===========
Supplemental cash flow information -
Cash paid for interest $ 1,312,000 $ 779,000 $ 1,677,000
============ ============ ===========
Common stock issued for the purchase
of oil and gas properties, net of return of
deposited shares $ 922,000 $ 26,959,000 $ 2,954,000
============ ============ ===========
Non-cash financing activities:
Shares issued for all outstanding shares of
Piper Petroleum Company $ - $ 5,234,000 $ -
============ ============ ===========
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
============ ============ ===========
See accompanying notes to consolidated financial statements.
F-6
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies
Organization and Principles of Consolidation
Delta Petroleum Corporation ("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, 2003 the Company owned 4,277,977 shares of the common stock
of Amber Resources Company ("Amber"), representing 91.68% of the outstanding
common stock of Amber. Amber is a public company also engaged in acquiring,
exploring, developing and producing oil and gas properties.
On February 19, 2002, the Company acquired 100% of the outstanding
shares of Piper Petroleum Company ("Piper"), a privately owned oil and gas
company headquartered in Fort Worth, Texas. Piper was merged into a
subsidiary wholly owned by Delta.
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' deficit position for the periods presented, the Company has
recognized 100% of Amber's earnings/losses for all periods.
Cash Equivalents
Cash equivalents consist of money market funds. For purposes of the
statements of cash flows, the Company considers all highly liquid investments
with maturities at date of acquisition of three months or less to be cash
equivalents.
Marketable Securities
The Company classifies its investment securities as available-for-sale
securities. Pursuant to Statement of Financial Accounting Standards 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.
F-7
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies, Continued
Unrealized Estimated
Cost Gain (loss) Market Value
--------- ---------- ------------
June 30, 2003
Bion Environmental Technologies, Inc. $ 152,000 $(140,000) $ 12,000
Tipperary Oil & Gas Company $ 418,000 $ 232,000 $ 650,000
--------- --------- ---------
$ 570,000 $ 92,000 $ 662,000
========= ========= =========
June 30, 2002
Bion Environmental Technologies, Inc. $ 152,000 $ (92,000) $ 60,000
Tipperary Oil & Gas Company $ 418,000 $ 7,000 $ 425,000
--------- --------- ---------
$ 570,000 $ (85,000) $ 485,000
========= ========= =========
June 30, 2001
Bion Environmental Technologies, Inc. $ 152,000 $ 69,000 $ 221,000
========= ========= =========
Revenue Recognition
The Company uses the sales method of accounting for oil and gas
revenues. Under this method, revenues are recognized based on actual volumes
of oil and gas sold to purchasers.
Property and Equipment
The Company follows the successful efforts method of accounting for its
oil and gas activities. Accordingly, costs associated with the acquisition,
drilling, and equipping of successful exploratory wells are capitalized.
Geological and geophysical costs, delay and surface rentals and drilling
costs of unsuccessful exploratory wells are charged to expense as incurred.
Costs of drilling development wells, both successful and unsuccessful, are
capitalized.
Upon the sale or retirement of oil and gas properties, other than
partial interests in proved properties, the cost thereof and the accumulated
depreciation and depletion are removed from the accounts and any gain or loss
is credited or charged to operations.
F-8
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies, Continued
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 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.
Furniture and equipment are depreciated using the straight-line method
over estimated lives ranging from three to five years.
Certain of the Company's oil and gas activities are conducted through
partnerships and joint ventures. The Company includes its proportionate share
of assets, liabilities, revenues and expenses from these entities in its
consolidated financial statements. Partnership net assets represent the
Company's share of net working capital in such entities.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"
(SFAS No. 121) requires that long-lived assets be reviewed for impairment when
events or changes in circumstances indicate that the carrying value of such
assets may not be recoverable.
Estimates of expected future cash flows represent management's best
estimate based on reasonable and supportable assumptions and projections. If
the expected future cash flows exceed the carrying value of the asset, no
impairment is recognized. If the carrying value of the asset exceeds the
expected future cash flows, an impairment exists and is measured by the excess
of the carrying value over the estimated fair value of the asset. Any
impairment provisions recognized in accordance with SFAS No. 121 are permanent
and may not be restored in the future.
The Company assesses developed properties on an individual field basis
for impairment on at least an annual basis. For developed properties, the
review consists of a comparison of the carrying value of the asset with the
asset's expected future undiscounted cash flows without interest costs. As a
result of such assessment, the Company recorded an $878,000 impairment
provision attributable to certain producing properties for the year ended June
30, 2002 and $6,000 for the year ended June 30, 2001, and had no impairment
for the year ended June 30, 2003.
For undeveloped properties, the need for an impairment reserve is based
on the Company's plans for future development and other activities impacting
the life of the property and the ability of the Company to recover its
investment. When the Company believes the costs of the undeveloped property
F-9
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies, Continued
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 an impairment provision attributable to certain undeveloped
properties of $602,000 for the year ended June 30, 2002, $168,000 for the year
ended June 30, 2001, and had no similar foreign impairment for the year ended
June 30, 2003.
In addition, the Company recorded an impairment provision attributed to
certain undeveloped foreign properties of $624,000 for the year ended June 30,
2001 and had no similar foreign impairment for the other periods presented.
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 adopted SFAS No. 143
on July 1, 2002 and recorded a cumulative effect of a change in accounting
principle on prior years of $20,000, net of tax effects, related to the
depreciation and accretion expense that would have been reported had the fair
value of the asset retirement obligations, and corresponding increase in the
carrying amount of the related long-lived assets, been recorded when incurred.
The Company's asset retirement obligations arise from the plugging and
abandonment liabilities for its oil and gas wells. On July 1, 2002 the
Company also recorded $644,000 of asset retirement obligations (using an 8%
discount rate), an increase in the carrying amount of its oil and gas
properties of $664,000 and a decrease to accumulated depreciation of $20,000.
The Company has no obligation to provide for the retirement of its offshore
properties as the obligations remained with the seller. The following is a
description of the changes and pro forma changes to the Company's asset
retirement obligations from July 1, 2002 to June 30, 2003.
Asset retirement obligation - July 1, 2002 $644,000
Accretion 57,000
Additions 181,000
Settlements (14,000)
--------
Asset retirement obligation - June 30, 2003 868,000
Less: Current asset retirement obligation -
--------
Long-term asset retirement obligation $868,000
========
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.
F-10
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies, Continued
Derivative Financial Instruments
The Company periodically enters into commodity derivative contracts and
fixed-price physical contracts to manage its exposure to oil and 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
derivitives contracts are based upon crude oil and natural futures which have
a high degree of historical correlation with actual prices received by the
Company
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS 133 establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded on the balance sheet as either an asset or liability measured at its
fair value. It also requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows
that the effective portion of the gain or loss on a derivative instrument
designated and qualifying as a cash flow hedging instrument be reported as a
component of Other Comprehensive Income and be reclassified into earnings in
the same period or periods during which the hedged forecasted transaction
affects earnings.
Stock Option Plans
The Company accounts for its stock option plans in accordance with the
provisions of Accounting Principles Board ("APB") Opinion No. 25, Accounting
for Stock Issued to Employees, and related interpretations. As such,
compensation expense was recorded on the date of grant only if the current
market price of the underlying stock exceeded the exercise price. In
December, 2002 the FASB issued SFAS No. 148, "Accounting for Stock-based
Compensation-Transition and Disclosure." SFAS 148 amends FASB Statement No.
123, "Accounting for Stock-Based Compensation" to provide alternative methods
of transition for a voluntary change to the fair-value based method of
accounting for stock-based employee compensation. In addition, this Statement
amends the disclosure requirements of Statement 123 to require prominent
disclosures in both annual and interim financial statements about the method
of accounting for stock-based employee compensation and the effect of the
method used on the reported results. The provisions of SFAS 148 has no
material impact on the Company, as we do not plan to adopt the fair-value
method of accounting for stock options at the current time. Accordingly, no
compensation cost is recognized for options granted at a price equal to or
greater than the fair market value of the common stock. Had compensation cost
for the Company's stock-based compensation plan been determined using the
fair value of the options at the grant date, the Company's net income (loss)
for the years ended June 30, 2003, 2002 and 2001 would have been as follows:
F-11
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies, Continued
June 30,
-------------------------------------------
2003 2002 2001
---------- ----------- -----------
Net Income (loss) $1,257,000 $(6,253,000) $ 345,000
FAS 123 compensation effect (209,000) (790,000) (3,235,000)
---------- ----------- -----------
Net Income (loss) after FAS 123
compensation effect $1,048,000 $(7,043,000) $(2,890,000)
========== =========== ===========
Income per common share: $ .05 $ (0.55) $ (0.28)
========== =========== ===========
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 year ended June 30,
2002.
F-12
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies, Continued
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
The Company has been made aware that an issue has arisen within the
industry regarding the application of provisions of SFAS No. 142 and SFAS No.
141, "Business Combinations," to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 142 requires
registrants to reclassify costs associated with mineral rights, including both
proved and unproved leasehold acquisition costs, as intangible assets in the
balance sheet, apart from other capitalized oil and gas property costs.
Historically, the Company and other oil and gas companies have included the
cost of these oil and gas leasehold interests as part of oil and gas
properties. Also under consideration is whether SFAS No. 142 requires
registrants to provide the additional disclosures prescribed by SFAS No. 142
for intangible assets for costs associated with mineral rights.
If it is ultimately determined that SFAS No. 142 requires the Company to
reclassify costs associated with mineral rights from property and equipment to
intangible assets, the amounts that would be reclassified are as follows:
June 30,
2003 2002
----------- -----------
INTANGIBLE ASSETS:
Proved leasehold acquisition costs $68,966,000 $58,170,000
Unproved leasehold acquisition costs 10,164,000 9,722,000
----------- -----------
Total leasehold acquisition costs 79,130,000 67,892,000
Less: Accumulated depletion 10,858,000 6,349,000
----------- -----------
Net leasehold acquisition costs $68,272,000 $61,543,000
----------- -----------
F-13
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies, Continued
The reclassification of these amounts would not effect the method in
which such costs are amortized or the manner in which the Company assesses
impairment of capitalized costs. As a result, net income would not be affected
by the reclassification.
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 January 1, 2003. The
Company does not believe this statement will have a material impact to the
Financial Statements.
In November 2002, the FASB issued Financial Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others - an interpretation of FASB
Statements Nos. 5, 57, and 107 and rescission of FASB Interpretation No. 34"
("FIN 45"). FIN 45 elaborates on the disclosures to be made by a guarantor in
its interim and annual financial statements about its obligations under
certain guarantees that it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of a guarantee, a liability for the
fair value of the obligation undertaken in issuing the guarantee. The initial
recognition and initial measurement provisions of FIN 45 are applicable on a
prospective basis to guarantees issued or modified after December 31, 2002,
irrespective of the guarantor's fiscal year-end. The disclosure requirements
are effective for financial statements of interim or annual periods ending
after December 15, 2002. The adoption of FIN 45 has not had any effect on the
Company's financial position or results of operations.
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.
F-14
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(1) Summary of Significant Accounting Policies, Continued
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 variable
interest entities in which an enterprise obtains an interest after that date.
It applies in the first fiscal year or interim period beginning after June 15,
2003, to variable interest entities in which an enterprise holds a variable
interest that it acquired before February 1, 2003. At this time, the Company
does not have a VIE.
In April 2003, FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 149 is effective for contracts entered into
or modified after June 30, 2003 and for hedging relationships designated after
June 30, 2003. The Company adopted SFAS No. 149 on July 1, 2004 and does not
expect to have a material impact on the Company's financial condition and
results of operations.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity."
SFAS No. 150 changes the accounting for certain financial instruments that,
under previous guidance, issuers could account for as equity. FASB No. 150
requires that those instruments be classified as liabilities in statements of
financial position. SFAS No. 150 is effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. SFAS No.
150 is not expected to have a material impact on the Company's financial
condition or results of operation.
Reclassification
Certain amounts in the 2002 and 2001 financial statements have been
reclassified to conform to the 2003 financial statement presentation.
F-15
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(2) Oil and Gas Properties
Unproved Undeveloped Offshore California Properties
The Company has ownership interests ranging from 2.49% to 75% in five
unproved undeveloped offshore California oil and gas properties with aggregate
carrying values of $10,164,000 and $9,722,000 at June 30, 2003 and 2002,
respectively. These property interests are located in proximity to existing
producing federal offshore units near Santa Barbara, California and represent
the right to explore for, develop and produce oil and gas from offshore
federal lease units. Preliminary exploration efforts on these properties have
occurred and the existence of substantial quantities of hydrocarbons has been
indicated. The recovery of the Company's investment in these properties will
require extensive exploration and development activities (and costs) that
cannot proceed without certain regulatory approvals that have been delayed and
is subject to other substantial risks and uncertainties as discussed herein.
The Company is not the designated operator of any of these properties
but is an active participant in the ongoing activities of each property along
with the designated operator and other interest owners. If the designated
operator elected not to or was unable to continue as the operator, the other
property interest owners would have the right to designate a new operator as
well as share in additional property returns prior to the replaced operator
being able to receive returns. Based on the Company's size, it would be
difficult for the Company to proceed with exploration and development plans
should other substantial interest owners elect not to proceed. However, to
the best of its knowledge, the Company believes the designated operators and
other major property interest owners intend to proceed with exploration and
development plans under the terms and conditions of the operating agreement.
The ownership rights in each of these properties have been retained under
various suspension notices issued by the Mineral Management Service (MMS) of
the U.S. Federal Government whereby as long as the owners of each property
were progressing toward defined milestone objectives, the owners' rights with
respect to the properties continue to be maintained. The issuance of the
suspension notices has been necessitated by the numerous delays in the
exploration and development process resulting from regulatory requirements
imposed on the property owners by federal, state and local agencies.
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) 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.
F-16
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(2) 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,
2003 and June 30, 2002 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 are 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.
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 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 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 that would cause the leases to become impaired, and we will continuously
evaluate those factors as they occur.
On January 9, 2002, we and several other plaintiffs filed a lawsuit in
the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government has materially breached the terms of 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.
F-17
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(2) Oil and Gas Properties, Continued
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. 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.
Acquisitions - 2003
On June 20, 2003, the Company acquired producing oil and gas interests
and related undeveloped acreage in Kansas from JAED Production Company "JAED",
an unrelated entity. The Company paid $9,000,000 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 announcement of the
transaction. The Company recorded a purchase price adjustment of
approximately $291,000 which reflects the net reserves after operating costs
and acquisition related costs from the effective date of June 1, 2003 through
the closing date of June 20, 2003. The total acquisition cost of $9,631,000
was allocated between proved developed producing of $7,635,000 and proved
undeveloped of $1,996,000.
Acquisitions - 2002
On February 19, 2002, Delta completed the acquisition of Piper Petroleum
Company ("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
were valued at approximately $5,234,000 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'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, 2002 the Company
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. 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 was allocated between proved
developed producing of $3,882,000, proved developed non-producing of $336,000,
and proved undeveloped of $585,000. Net daily production from the West Buna
Field approximates 900,000 cubic feet equivalent.
F-18
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(2) Oil and Gas Properties, Continued
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's stock obtained from Snyder & Company, an
independent evaluation expert.
The Company was 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 (May
31, 2003). The Company did not repurchase its shares on May 31, 2003. This
right is reflected in stockholders' equity at its fair value as a put option
on Delta stock until expiration. The Company'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"), 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 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 was allocated between proved developed producing of
$32,614,000 and proved undeveloped of $8,153,000. The Company recorded oil
and gas revenues of $1,148,000 and operating expenses of $485,000 for the
month of June 2002 relating to these properties.
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's restricted common stock with a fair value of
$375,000 based on the market price on the date of closing.
Acquisitions 2001
On July 10, 2000, the Company paid $3,745,000, during fiscal 2000,
issued 90,000 shares of the Company's common stock valued at approximately
$273,000, the amount previously recorded as a deposit on 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
F-19
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(2) Oil and Gas Properties, Continued
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 from the effective date 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 in oil and gas properties.
In addition to the North Dakota acquisition, the Company acquired
additional oil and gas properties during fiscal 2001 in New Mexico and South
Dakota. The consideration for these acquisitions, which included stock
commissions relating to the acquisitions, was $2,567,000 and 751,238 shares of
the Company's common stock valued at $2,504,000.
The Company committed to sell 25,000 barrels per month from July 2000 to
December 2000 at $14.65. If the Company would not have committed to sell its
proportionate shares of its barrels, the Company would have realized an
increase in income of $1,242,000 for the year ended June 30, 2001.
Dispositions
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 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 of the proceeds from
the sale were used to pay existing debt.
During the years ended June 30, 2003, 2002 and 2001, the Company
disposed of certain oil and gas properties and related equipment to
unaffiliated entities in addition to the North Dakota disposition described
above. The Company has received proceeds from these sales of $850,000
$1,667,000 and $3,700,000 and such sales resulted in a net gain (loss) on sale
of oil and gas properties of $277,000, $(87,000) and $458,000 for the years
ended June 30, 2003, 2002 and 2001, respectively.
F-20
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(3) Long Term Debt
June 30,
2003 2002
----------- -----------
A $27,668,000 $18,918,000
B 4,546,000 6,021,000
----------- -----------
$32,214,000 $24,939,000
Current Portion 10,039,000 3,498,000
----------- -----------
Long-Term Portion $22,175,000 $21,441,000
=========== ===========
A. On June 20, 2003, the Company increased its credit facility from
$20 million to $29.3 million with Bank of Oklahoma and Local Oklahoma Bank
(the "Banks). The facility has a variable interest rate component of
prime + 1.5%/-.5% based on the total debt outstanding and a monthly commitment
reduction of $600,000. The proceeds from this facility were used for the
acquisitions of Castle and JAED 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, 2005 and is collateralized by substantially
all of Delta's oil and gas properties excluding the oil and gas properties
collateralized under the Kaiser-Francis Oil Company ("KFOC") note discussed
below. The Company's borrowing base and monthly commitment amount will be
redetermined at least semi-annually.
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 exceeds the amount of the revolving commitment then in effect, then
within 30 days after we are notified by the Bank of Oklahoma, we must make a
mandatory prepayment of principal that is sufficient to cause our total
outstanding indebtedness to not exceed our borrowing base. The Company is
required to meet quarterly debt covenants and restrictions. At June 30, 2003,
the Company was in compliance with its quarterly debt covenants and
restrictions.
B. On December 1, 1999, the Company borrowed $8,000,000 (at prime plus
1-1/2% from KFOC). In addition, the Company will be required to pay a fee of
$250,000 on June 1, 2004 as the note was not retired prior to June 1, 2003.
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 payments 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.
F-21
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(3) Long Term Debt, Continued
Maturities of long-term debt, based on current arrangements, for each of the
five years following June 30, 2003 are as follows:
YEAR ENDING DECEMBER 31,
2004................................ $10,039,000
2005................................ 7,200,000
2006................................ 7,200,000
2007................................ 7,200,000
2008................................ 575,000
-----------
$32,214,000
===========
(4) 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, 2003, 2002 and 2001, no preferred stock was issued.
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 and $2,422,000 during the years
ended June 30, 2002 and 2001, respectively. Commissions consisted of cash
and/or warrants to purchase shares of the Company's common stock and were
accounted for as an adjustment to stockholders' equity. The warrants were
issued with exercise prices at market or at a discount of 10% or less.
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. The Investment Agreement was amended and restated on April 10, 2002. 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. On December 20, 2002 the parties entered into an
agreement which terminated the investment agreement with Swartz.
On September 4, 2002, Swartz exercised 100,000 warrants in a cashless
exercise transaction, which was permitted by the terms of the warrant. As a
result of this exercise, Swartz received 20,761 shares of the Company's common
stock.
F-22
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(4) Stockholders' Equity, Continued
On December 20, 2002, the Company entered into a one year consulting
agreement with Swartz in the amount of $100,000, whereby Swartz will provide
business and financial planning and assist with the identification and review
of potential merger and acquisition possibilities.
Non-Qualified Stock Options-Directors and Employees
On May 31, 2002 at the annual meeting of the shareholders, the
shareholders ratified the Company's 2002 Incentive Plan (the "Incentive Plan")
under which it reserved up to an additional 2,000,000 shares of common stock.
This plan supercedes the Company's 1993 and 2001 Incentive Plans.
Incentive awards under the Incentive Plan may include non-qualified or
incentive stock options, limited appreciation rights, tandem stock
appreciation rights, phantom stock, stock bonuses or cash bonuses. Options
issued to date under 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's various plans
and related information for the years ended June 30, 2003, 2002 and 2001
follows:
2003 2002 2001
Weighted-Average Weighted-Average Weighted-Average
Exercise Exercise Exercise
Options Price Options Price Options Price
--------- ------ --------- ------ --------- ------
Outstanding-beginning of year 3,378,487 $ 3.07 2,956,215 $ 3.14 1,635,886 $ 1.36
Granted 255,000 $ 2.79 547,500 $ 2.32 1,882,500 $ 4.00
Exercised (217,500) $(1.59) (95,228) $(0.62) (562,171) $(0.81)
Expired (5,000) $ 3.20 (30,000) $(4.56) - -
--------- ------ --------- ------ --------- ------
Outstanding-end of year 3,410,987 $ 3.15 3,378,487 $ 3.07 2,956,215 $ 3.14
========= ====== ========= ====== ========= ======
Exercisable at end of year 3,240,989 $ 3.15 3,358,487 $ 3.06 2,896,215 $ 3.12
========= ====== ========= ====== ========= ======
F-23
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(4) Stockholders' Equity, Continued
The Company issued options to its Non-employee Directors. Accordingly,
the Company recorded stock option expense in the amount of $114,000, $113,000
and $110,000 for options issued to its Directors for the years ended June 30,
2003, 2002 and 2001, respectively, for options issued below market.
Exercise prices for options outstanding under our various plans as of
June 30, 2003 ranged from $0.05 to $9.75 per share. The weighted-average
remaining contractual life of those unvested options is 7.96 years. All but
170,000 options are fully vested at June 30, 2003. A summary of the
outstanding and exercisable options at June 30, 2003, 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
- ----------- ----------- -------- ----------- ----------- --------
$0.05-$1.12 314,590 $0.05 5.25 314,590 $0.05
$1.13-$3.25 916,397 2.56 8.18 776,397 2.44
$3.26-$9.75 2,180,000 3.85 6.53 2,150,000 3.86
--------- ----- ----- --------- -----
3,410,987 $3.15 6.86 3,240,987 $3.15
========= ===== ===== ========= =====
The fair value for these options was estimated at the date of grant
using a Black-Scholes option pricing model with the following Weighted-average
assumptions for the years ended June 30, 2003, 2002 and 2001, respectively,
risk-free interest rate of 2.84%, 4.73% and 5.1%, dividend yields of 0%, 0%
and 0%, volatility factors of the expected market price of the Company's
common stock of 65.32%, 65.68% and 64.03% and a weighted-average expected life
of the options of 4.16, 6.37 and 6.15 years.
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 $10,000 $30,000 and
$299,000 to non-employees for the years ended June 30, 2003, 2002 and 2001,
respectively.
A summary of the stock option and warrant activity and related
information for the years ended June 30, 2003, 2002 and 2001 is as follows:
F-24
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(4) Stockholders' Equity, Continued
2003 2002 2001
Weighted-Average Weighted-Average Weighted-Average
Exercise Exercise Exercise
Options Price Options Price Options Price
--------- ------ --------- ------ --------- ------
Outstanding-beginning of year 1,954,000 $ 3.62 2,140,000 $ 3.56 1,562,500 $ 3.33
Granted - - 35,000 $ 3.25 1,250,000 $ 3.46
Exercised (250,761) $(2.51) (171,000) $(2.04) (360,000) $(2.85)
Purchased from Kaiser-Francis
Oil Co - - - - (250,000) $(2.00)
Expired (448,239) $(4.76) (50,000) $(6.00) (62,500) $(6.125)
--------- ------ --------- ------ --------- -------
Outstanding end of year 1,255,000 $ 3.38 1,954,000 $ 3.62 2,140,000 $ 3.56
========= ====== ========= ====== ========= ======
Exercisable at end of
year 1,255,000 $ 3.38 1,954,000 $ 3.62 2,140,000 $ 3.56
========= ====== ========= ====== ========= ======
Exercise prices for options outstanding as of June 30, 2003 ranged from
$2.00 to $6.00 per share. All options are fully vested at June 30, 2003. The
weighted-average remaining contractual life of those options is 1.71 years. A
summary of the outstanding and exercisable options at June 30, 2003,
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
- ----------- ----------- -------- ----------- ----------- --------
$3.00-$3.25 785,000 $3.03 1.90 785,000 $3.03
$3.26-$6.00 470,000 3.98 0.25 470,000 3.98
--------- ----- ---- --------- -----
1,255,000 $3.38 1.19 1,255,000 $3.38
========= ===== ==== ========= =====
F-25
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(5) 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") IRA plan available to companies with fewer than
100 employees. Under the SIMPLE plan, the Company's employees made annual
salary reduction contributions of up to 3% of an employee'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, 2003, 2002 and 2001 the Company contributed
$147,000, $68,000 and $18,000, respectively under the plans.
(6) 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, 2003, the Company recorded a derivative liability of
approximately $468,000 for the fair market value of its derivative instruments
designated as cash flow hedges and a corresponding loss in other comprehensive
income. The realized net losses from hedging activities were $1,858,000 for
the year ended June 30, 2003.
F-26
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(6) Commodity Derivative Instruments and Hedging Activities, Continued
Beginning in fiscal 2003, the Company 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. At June 30, 2003, the Company had agreements to hedge
approximately 40% of its offshore oil production for production months July
2003 through December 2003. In addition, the Company has entered into
agreements to hedge approximately 30% of its onshore oil production for
production months July 2003 through October 2003 and 45% of its onshore gas
production for production months July 2003 through September 2003. As of June
30, 2003, the Company has approximately 72,000 Bbls of oil and 386,000 Mcf of
natural gas subject to commodity price risk contracts for fiscal 2004. The
fiscal 2004 contracts have weighted average floor prices of $27.32 per barrel
and $3.00 per Mmbtu, with weighted average ceiling prices of $27.32 per barrel
and $4.50 per Mmbtu, respectively.
(7) Income Taxes
At June 30, 2003, 2002 and 2001, the Company's significant deferred tax
assets and liabilities are summarized as follows:
2003 2002 2001
------------ ------------ ------------
Deferred tax assets:
Net operating loss/depletion
carryforwards $ 13,927,000 $ 11,534,000 $ 9,378,000
Other 255,000 87,000 19,000
Oil and gas properties,
principally due to
differences in basis resulting
from depreciation and depletion - - -
------------ ------------ ------------
Gross deferred tax assets 14,182,000 11,621,000 9,397,000
Less valuation allowance (10,279,000) (10,549,000) (8,144,000)
Deferred tax liability:
Oil and gas properties,
principally due to
differences in basis resulting
from depreciation and depletion (3,903,000) (1,072,000) (1,253,000)
------------ ------------ ------------
Net deferred tax asset: $ - $ - $ -
============ ============ ============
F-27
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(7) Income Taxes, Continued
The current income tax liability of $703,000 is due to estimate foreign
taxes due as a result of the sale of Australian property acquired in the Piper
Petroleum Company acquisition.
No income tax benefit has been recorded for the years ended June 30,
2003, 2002 or 2001 since the benefit of the net operating loss carryforward
and other net deferred tax assets arising in those periods has been offset by
the valuation allowance for such net deferred tax assets.
At June 30, 2002, the Company had net operating loss carryforwards for
regular and alternative minimum tax purposes of approximately $35,240,000 and
$33,000,000, respectively. If not utilized, the tax net operating loss
carryforwards will expire during the period from 2003 through 2023. If not
utilized, approximately $3.3 million of net operating losses will expire over
the next five years. Net operating loss carryforwards attributable to Amber
prior to 1993 of approximately $846,000, included in the above amounts, are
available only to offset future taxable income of Amber.
In addition, Delta Petroleum and its subsidiaries experienced a change
in ownership in May 2002 with the acquisition of Castle's oil and gas
properties and as a result, its annual net operating loss carry-forward usage
is limited. The annual limitation due to the ownership change is estimated to
be approximately $3,000,000.
(8) Related Party Transactions
Transactions with Officers
Until March 12, 2003, the Company's Board of Directors had granted each
of our officers the right to participate in the drilling on the same terms as
the Company in up to a five percent (5%) working interest in any well drilled,
re-entered, completed or recompleted by us on our acreage (provided that any
well to be re-entered or recompleted was then producing economic quantities of
hydrocarbons). On March 12, 2003, the Board of Directors rescinded this
right. The officers did not participate in any Company wells during fiscal
2003.
On February 12, 2001, 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 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. These officers were authorized to purchase these
F-28
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(8) Related Party Transactions, Continued
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 to participate in the drilling of the Austin
State #1 well in Eddy County, New Mexico by their 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 to Delta in common
stock at $5.125 per share, the market closing price on this date. All of
these officers committed to participate in the well.
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's engineer and verified by an independent engineer.
During fiscal 2001 and 2000, Mr. Larson and Mr. Parker guaranteed
certain borrowings which have subsequently been paid in full. As
consideration for the guarantee of the Company's indebtedness, each officer
was assigned a 1% overriding royalty interest ("ORRI") in the properties
acquired with the proceeds of the borrowings. Each officer earned
approximately $108,000, $71,000 and $83,000 for their respective 1% ORRI
during fiscal 2003, 2002 and 2001, respectively.
Accounts Receivable Related Parties
At June 30, 2003, the Company had $72,000 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. The amounts
are due on open account and are non-interest bearing.
F-29
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(8) Related Party Transactions, Continued
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% discount 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.
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,
2003, the Company has paid a total of $2,950,000 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-30
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(9) Earnings Per Share
The following table sets forth the computation of basic and diluted
earnings per share:
Year Ended June 30,
--------------------------------------------
2003 2002 2001
----------- ----------- -----------
Numerator:
Numerator for basic and diluted
earnings per share - income available
to common stockholders $ 1,257,000 $(6,253,000) $ 345,000
----------- ----------- -----------
Denominator:
Denominator for basic earnings
per share-weighted average shares
outstanding 22,865,000 12,682,000 10,289,000
Effect of dilutive securities-
stock options and warrants 954,000 * 1,464,000
----------- ----------- -----------
Denominator for diluted
earnings per common shares 23,819,000 $12,682,000 11,753,000
=========== =========== ===========
Basic earnings per common share $ .05 $ (.49) $ .03
=========== =========== ===========
Diluted earnings per common share $ .05 $ (.49) $ .03
=========== =========== ===========
*Potentially dilutive securities outstanding of 5,332,000 in 2002 were anti-dilutive.
F-31
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(10) Commitments
The Company rents an office in Denver under an operating lease which
expires in September 2008. Rent expense, net of sublease rental income, for
the years ended June 30, 2003, 2002 and 2001 was approximately $210,000,
$109,000 and $82,000, respectively. Future minimum payments under non-
cancelable operating leases are as follows:
2004 $ 248,000
2005 $ 234,000
2006 $ 212,000
2007 $ 211,000
2008 $ 207,000
Thereafter $ 52,000
(11) Selected Quarterly Financial Data (Unaudited)
Fiscal 2003 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
- ----------- ----------- ----------- ----------- -----------
Revenue $5,648,000 $5,704,000 $6,975,000 $5,653,000
Income (loss) from operations 634,000 850,000 1,715,000 (186,000)
Net Income (loss) 117,000 428,000 1,307,000 (595,000)
Basic Earnings (loss) per share $ .01 $ .02 $ .06 $ (.03)
Diluted earnings (loss) per share $ ** $ .02 $ .05 $ *
Fiscal 2003 4th Quarter includes bonuses of $676,000 and dry hole costs of $405,000.
*Potentially dilutive securities outstanding were anti-dilutive
**less than $.01 per share
Fiscal 2002 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
- ----------- ----------- ----------- ----------- -----------
Revenue $2,443,000 $ 1,789,000 $ 1,058,000 $ 2,920,000
Income (loss) from operations 105,000 (1,342,000) (1,322,000) (2,482,000)
Net Income (loss) (244,000) (1,662,000) (1,587,000) (2,760,000)
Basic Earnings (loss) per share $ (.02) $ (.15) $ (.13) $ (.17)
Diluted earnings (loss) per
share $ (.02)* $ (.15)* $ (.13)* $ (.17)*
*Potentially dilutive securities outstanding were anti-dilutive
F-32
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(12) Disclosures About Capitalized Costs, Cost Incurred and Major Customers
Capitalized costs related to oil and gas producing activities are as
follows:
June 30,
2003 2002
------------ ------------
Unproved undeveloped offshore
California properties $ 10,164,000 $ 9,722,000
Proved undeveloped offshore
California properties 843,000 843,000
Undeveloped onshore
domestic properties 11,675,000 10,114,000
Developed offshore California
properties 7,190,000 6,204,000
Developed onshore domestic
properties 60,278,000 45,893,000
------------ ------------
90,150,000 72,776,000
Accumulated depreciation
and depletion (12,509,000) (6,925,000)
------------ ------------
$ 77,641,000 $ 65,851,000
============ ============
Costs incurred in oil and gas producing activities are as follows:
June 30,
---------------------------------------------------------------------------------
2003 2002 2001
Onshore Offshore Onshore Offshore Onshore Offshore
------------ ----------- ----------- ---------- ---------- ----------
Unproved property
acquisition costs $ 694,000 $ 442,000 $ 9,115,000 $ 363,000 $1,332,000 $ 350,000
Proved property
acquisition costs $ 10,784,000 $ - $38,290,000 $ - $7,480,000 $2,931,000
Development cost incurred
on undeveloped reserves $ 815,000 $ 986,000 $ 418,000 $ 678,000 $ - $ 686,000
Development costs-other $ 4,335,000 $ - $ 569,000 $ 521,000 $ 592,000 $ 375,000
Exploration costs $ 140,000 $ - $ 108,000 $ 47,000 $ 32,000 $ 57,000
------------ ----------- ----------- ---------- ---------- ----------
$ 16,768,000 $ 1,428,000 $48,500,000 $1,609,000 $9,436,000 $4,399,000
------------ ----------- ----------- ---------- ---------- ----------
Transferred amounts
from undeveloped
to developed properties $ 168,000 $ - $ - $ 306,000 $ - $ 510,000
Transferred from oil and gas
properties to deferred
financing costs $ - $ - $ - $ - $ - $ 330,000
F-33
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(12) 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,
----------------------------------------------------------------------------------
2003 2002 2001
Onshore Offshore Onshore Offshore Onshore Offshore
------------ ----------- ----------- ---------- ---------- ----------
Revenue:
Oil and gas
revenues $20,972,000 $4,589,000 $ 4,365,000 $3,756,000 $6,564,000 $5,690,000
Gain (loss) on
sale of oil and
gas properties $ 277,000 $ - $ (88,000) $ - $ (1,000) $ 459,000
Expenses:
Lease operating $ 6,209,000 $3,270,000 $ 1,328,000 $3,044,000 $ 805,000 $3,893,000
Depletion $ 4,651,000 $1,075,000 $ 2,237,000 $1,099,000 $1,691,000 $ 839,000
Exploration $ 140,000 $ - $ 108,000 $ 47,000 $ 32,000 $ 57,000
Abandonment and
impaired
properties $ - $ - $ 1,480,000 $ - $ 798,000 $ -
Dry hole costs $ 537,000 $ - $ 396,000 $ - $ 94,000 $ -
----------- ---------- ----------- ---------- ----------- ----------
Results of
operations of
oil and gas
producing
activities $ 9,712,000 $ 244,000 $(1,272,000) $ (434,000) $3,143,000 $1,360,000
=========== ========== ========== =========== ========== ==========
Statement of Financial Accounting Standards 131 "Disclosures about
segments of an enterprises and Related Information" (SFAS 131) establishes
standards for reporting information about operating segments in annual and
interim financial statements. SFAS 131 also establishes standards for related
disclosures about products and services, geographic areas and major customers.
The Company's business segment includes its onshore and offshore properties
described above.
F-34
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(12) Disclosures About Capitalized Costs, Cost Incurred and Major Customers,
Continued
The Company's sales of oil and gas to individual customers which
exceeded 10% of the Company's total oil and gas sales for the years ended June
30, 2003, 2002 and 2001 were:
2003 2002 2001
---- ---- ----
A 18% 73% 59%
B 17% 2% -%
C 13% 3% -%
D -% 10% 19%
(13) Information Regarding Proved Oil and Gas Reserves (Unaudited)
Proved Oil and Gas Reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices provided only
by contractual arrangements, but not on escalations based upon future
conditions. For the purposes of this disclosure, the Company has included
reserves it is committed to and anticipates drilling.
(i) Reservoirs are considered proved if economic producability is
supported by either actual production or conclusive formation test. The area
of a reservoir considered proved includes (A) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the
immediately adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available geological and
engineering data. In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower proved limit of
the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified separately
as "indicated additional reserves"; (B) crude oil, natural gas, and natural
gas liquids, the recovery of which is subject to reasonable doubt because of
F-35
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(13) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in underlaid
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may
be recovered from oil shales, coal, gilsonite and other such sources.
Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the
application of fluid injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary recovery should be
included as "proved developed reserves" only after testing by a pilot project
or after the operation of an installed program has confirmed through
production response that increased recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled.
Proved reserves for other 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.
A summary of changes in estimated quantities of proved reserves for the
years ended June 30, 2003, 2002 and 2001 are as follows:
F-36
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(13) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
Onshore Offshore
GAS OIL GAS OIL
(MCF) (BBLS) (MCF) (BBLS)
---------- --------- ----- ---------
Balance at July 1, 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)
---------- --------- ----- ---------
Balance at June 30, 2002 43,953,000 3,919,000 - 902,000
Revisions of quantity
estimate 13,719,000 (927,000) - 244,000
Extensions and discoveries 687,000 - - 1,132,000
Purchase of properties 236,000 1,024,000 - -
Sales of properties (457,000) (66,000) - -
Production (2,938,000) (252,000) - (227,000)
---------- --------- ----- ---------
Balance at June 30, 2003 55,200,000 3,698,000 - 2,051,000
========== ========= ===== =========
F-37
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(13) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
Proved developed reserves:
June 30, 2001 4,474,000 342,000 - 906,000
June 30, 2002 25,100,000 1,651,000 - 849,000
June 30, 2003 28,611,000 2,608,000 - 919,000
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
------------ ----------- ------------
June 30, 2001
Future cash inflows $ 24,570,000 22,098,000 $ 46,668,000
Future costs:
Production 7,971,000 11,969,000 19,940,000
Development 382,000 2,010,000 2,392,000
Income taxes - - -
------------ ----------- ------------
Future net cash flows 16,217,000 8,119,000 24,336,000
10% discount factor 6,267,000 2,095,000 8,362,000
------------ ----------- ------------
Standardized measure of discounted
future net cash flows $ 9,950,000 $ 6,024,000 $ 15,974,000
============ =========== ============
June 30, 2002
Future cash inflows
Future costs: $247,611,000 16,600,000 $264,211,000
Production 84,109,000 10,067,000 94,176,000
Development 15,056,000 1,089,000 16,145,000
Income taxes 28,078,000 - 28,078,000
------------ ----------- ------------
Future net cash flows $120,368,000 5,444,000 $125,812,000
10% discount factor 62,217,000 1,211,000 63,428,000
------------ ----------- ------------
Standardized measure of discounted
future net cash flows $ 58,151,000 4,233,000 $ 62,384,000
============ =========== ============
Standardized measure of discounted
future net cash flows before tax $ 72,073,000 $ 4,233,000 $ 76,306,000
============ =========== ============
F-38
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(13) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
June 30, 2003
Future cash inflows $377,458,000 $46,898,000 $424,356,000
Future costs:
Production 99,243,000 24,787,000 124,030,000
Development 20,104,000 13,137,000 33,241,000
Income taxes 62,390,000 - 62,390,000
------------ ----------- ------------
Future net cash flows 195,721,000 8,974,000 204,695,000
10% discount factor 93,734,000 3,750,000 97,484,000
------------ ----------- ------------
Standardized measure of discounted
future net cash flows $101,987,000 $ 5,224,000 $107,211,000
============ =========== ============
Standardized measure of discounted
future net cash flows before tax $134,667,000 $ 5,224,000 $139,891,000
============ =========== ============
Estimated future development cost
anticipated for fiscal
2004 and 2005 on existing
properties $ 18,400,000 5,538,000 $ 23,988,000
============ =========== ============
F-39
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
(13) 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, 2003, 2002 and 2001 are as follows:
2003 2002 2001
------------ ------------ -----------
Beginning of year $ 62,384,000 $ 15,974,000 $27,127,000
Sales of oil and gas produced during the
period, net of production costs (16,082,000) (3,807,000) (7,556,000)
Purchase of reserves in place 14,335,000 70,097,000 9,082,000
Net change in prices and production costs 37,957,000 (1,879,000) (2,634,000)
Changes in estimated future development
costs (8,251,000) (233,000) (371,000)
Extensions, discoveries and improved
recovery 3,032,000 96,000 242,000
Revisions of previous quantity estimates,
estimated timing of development and
other 25,675,000 (398,000) (9,739,000)
Previously estimated development costs
incurred during the period 1,801,000 1,869,000 686,000
Sales of reserves in place (1,122,000) (7,011,000) (3,576,000)
Change in future income tax (18,756,000) (13,921,000) -
Accretion of discount 6,238,000 1,597,000 2,713,000
------------ ------------ -----------
End of year $107,211,000 $ 62,384,000 $15,974,000
============ ============ ===========
(14) Subsequent Events.
Subsequent to June 30, 2003, we completed the acquisition of certain oil
and gas properties for a purchase price of approximately $13,000,000, which
consisted of one million shares of our common stock valued at approximately
$5,000,000, $2 million in cash and $6 million in notes payable due October 3,
2003.
F-40
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 19th day of September 2003.
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
- ------------------- ----
/s/ Aleron H. Larson, Jr. September 19, 2003
- ----------------------------------
Aleron H. Larson, Jr., Director
/s/ Roger A. Parker September 19, 2003
- ----------------------------------
Roger A. Parker, Director
- ----------------------------------
James B. Wallace, Director
/s/ Jerrie F. Eckelberger September 19, 2003
- ----------------------------------
Jerrie F. Eckelberger, Director
- ----------------------------------
John P. Keller
/s/ Joseph L. Castle II September 19, 2003
- ----------------------------------
Joseph L. Castle II
- ----------------------------------
Russell S. Lewis