SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 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
incorporation or organization) Identification No.)
475 17th Street, Suite 1400
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
(303) 293-9133
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No___
23,021,000 shares of common stock $.01 par value were outstanding as of May 5,
2003.
FORM 10-Q
3rd QTR.
FY 2003
INDEX
PART I FINANCIAL INFORMATION
PAGE NO.
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets - March 31, 2003 (unaudited)
and June 30, 2002............................................ 1
Consolidated Statements of Operations -
Three and Nine Months Ended
March 31, 2003 and 2002 (unaudited).......................... 3
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (loss)
Year Ended June 30, 2002 and
Nine Months Ended March 31, 2003 (unaudited)................. 5
Consolidated Statements of Cash Flows -
Nine Months Ended March 31, 2003 and 2002
(unaudited).................................................. 6
Notes to Consolidated Financial Statements (unaudited)....... 7
Item 2. Management's Discussion and Analysis
Or Plan of Operations........................................ 16
Item 3. Quantitative and Qualitative Disclosures About Market Risk... 25
Item 4. Controls and Procedures...................................... 25
PART II OTHER INFORMATION
Item 1. Legal Proceedings........................................... .26
Item 2. Changes in Securities........................................ 26
Item 3. Defaults upon Senior Securities.............................. 26
Item 4. Submission of Matters to a Vote of
Security Holders............................................. 26
Item 5. Other Information......................................... .. 26
Item 6. Exhibits and Reports on Form 8-K............................. 26
The terms "Delta", "Company", "we", "our", and "us" refer to Delta Petroleum
Corporation unless the context suggests otherwise.
i
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- -----------------------------------------------------------------------------
March 31 June 30,
2003 2002
------------ -----------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 1,714,000 $ 1,024,000
Marketable securities available for sale 435,000 485,000
Trade accounts receivable, net of
allowance for doubtful accounts of $50,000 at
March 31, 2003 and June 30, 2002 5,264,000 4,713,000
Prepaid assets 737,000 785,000
Other current assets 338,000 442,000
------------ -----------
Total current assets 8,488,000 7,449,000
------------ -----------
Property and equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting) 78,610,000 73,002,000
Less accumulated depreciation and depletion (11,232,000) (7,018,000)
------------ -----------
Net property and equipment 67,378,000 65,984,000
------------ -----------
Long-term assets:
Deferred financing costs 116,000 260,000
Partnership net assets 267,000 384,000
------------ -----------
Total long term assets 383,000 644,000
------------ -----------
$ 76,249,000 $74,077,000
============ ===========
1
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, CONTINUED
- -----------------------------------------------------------------------------
March 31, June 30,
2003 2002
------------ -----------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt $ 2,223,000 $ 3,498,000
Accounts payable 3,530,000 3,488,000
Derivative instruments 691,000 -
Current foreign tax payable 703,000 703,000
Other accrued liabilities 178,000 31,000
------------ -----------
Total current liabilities 7,325,000 7,720,000
------------ -----------
Long-term Liabilities:
Asset retirement obligation 665,000 -
Long-term debt, net 21,371,000 21,441,000
------------ -----------
Total long-term liabilities 22,036,000 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 22,987,000
shares at March 31, 2003 and 22,618,000
at June 30, 2002 230,000 226,000
Additional paid-in capital 77,371,000 76,514,000
Put option on Delta stock (2,886,000) (2,886,000)
Accumulated other comprehensive loss (826,000) (85,000)
Accumulated deficit (27,001,000) (28,853,000)
------------ -----------
Total stockholders' equity 46,888,000 4,916,000
------------ -----------
Commitments $ 76,249,000 $74,077,000
============ ===========
See accompanying notes to consolidated financial statements
2
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- -----------------------------------------------------------------------------
Three Months Ended
------------------
March 31, March 31,
2003 2002
---------- -----------
Revenue:
Oil and gas sales $7,717,000 $ 1,138,000
Realized loss on derivative instruments, net (971,000) -
Gain on sale of oil and gas properties 229,000 (107,000)
---------- -----------
Total revenue 6,975,000 1,031,000
Operating expenses:
Lease operating expense 2,556,000 865,000
Depreciation and depletion 1,428,000 587,000
Exploration expense 83,000 16,000
Dry hole costs 89,000 15,000
Professional fees 187,000 284,000
General and administrative 881,000 566,000
Stock option expense 36,000 20,000
---------- -----------
Total operating expense 5,260,000 2,353,000
---------- -----------
Income (loss)from operations 1,715,000 (1,322,000)
Other income and (expense):
Other income - 9,000
Interest and financing costs (408,000) (274,000)
---------- -----------
Total other expense (408,000) (265,000)
---------- -----------
Net income (loss) $1,307,000 $(1,587,000)
========== ===========
Net income (loss) per common share:
Basic $ 0.06 $ (0.13)
========== ===========
Diluted $ 0.05 $ (0.13)*
========== ===========
* Potentially dilutive securities outstanding were anti-dilutive
See accompanying notes to consolidated financial statements
3
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- ------------------------------------------------------------------------------
Nine Months Ended
-----------------
March 31, March 31,
2003 2002
----------- -----------
Revenue:
Oil and gas sales $19,275,000 $ 5,317,000
Realized loss on derivative instruments, net (1,391,000) -
Gain on sale of oil and gas properties 229,000 (107,000)
----------- -----------
Total revenue 18,113,000 5,210,000
Operating expenses:
Lease operating expense 7,192,000 2,679,000
Depreciation and depletion 4,305,000 2,249,000
Exploration expense 130,000 125,000
Abandoned and impaired properties - 162,000
Dry hole costs 132,000 396,000
Professional fees 506,000 954,000
General and administrative 2,567,000 1,151,000
Stock option expense 82,000 53,000
----------- -----------
Total operating expenses 14,914,000 7,769,000
----------- -----------
Income (loss)from operations 3,199,000 (2,559,000)
Other income and (expense)
Other income 21,000 13,000
Interest and financing costs (1,348,000) (947,000)
----------- -----------
Total other expense (1,327,000) (934,000)
----------- -----------
Income (loss) before cumulative effect of 1,872,000 (3,493,000)
change in accounting principle
Cumulative effect of change in accounting principle (20,000) -
----------- -----------
Net income (loss) $ 1,852,000 $(3,493,000)
=========== ===========
Net income (loss) per common share:
Basic $ 0.08 $ (0.30)
=========== ===========
Diluted $ 0.07 $ (0.30)*
=========== ===========
* Potentially dilutive securities outstanding were anti-dilutive
See accompanying notes to consolidated financial statements
4
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity and Comprehensive Income (Loss)
Year ended June 30, 2002 and Nine Months Ended March 31, 2003
(Unaudited)
- -----------------------------------------------------------------------------
Accumu-
lated
other
compre-
Additional Put Option hensive
Common Stock paid-in on income Comprehensive Accumulated
Shares Amount capital Delta stock (loss) income (loss) deficit Total
---------- -------- ----------- ------------ --------- -------------- ----------- ----------
Balance, July 1, 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 loss - - - - - (6,407,000) -
===========
Stock options granted as
compensation - - 143,000 - - - 143,000
Fair value of warrants issued
for common stock
investment agreement - - - - - - -
Warrant issued in exchange
for common stock
investment agreement - - - - - - -
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
Comprehensive loss:
Net income - - - - - 1,852,000 1,852,000 1,852,000
----------
Other comprehensive loss,
net of tax
Change in fair value of
derivative hedging
instruments - - - - (691,000) (691,000) - (691,000)
Unrealized gain on
equity securities - - - - (50,000) (50,000) - (50,000)
----------
Comprehensive income - - - - 1,111,000
==========
Stock options granted as
compensation - - 81,000 - - - 81,000
Shares issued for cash
upon exercise of options 369,000 4,000 776,000 - - - 780,000
---------- -------- ----------- ----------- --------- ------------ ----------
Balance, March 31, 2003 22,987,000 $230,000 $77,371,000 ($2,886,000) ($826,000) $(27,001,000) $46,888,000
========== ======== =========== =========== ========== ============ ===========
See accompanying notes to consolidated financial statements.
5
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- -----------------------------------------------------------------------------
Nine Months Ended
March 31, March 31,
2003 2002
----------- -----------
Cash flows operating activities:
Net income (loss) $ 1,852,000 $(3,493,000)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation and depletion 4,305,000 2,249,000
Stock option expense 82,000 53,000
Amortization of financing costs 341,000 417,000
Abandoned and impaired properties - 162,000
(Gain) loss on sale of oil and gas properties (229,000) 107,000
Shares issued for services - 48,000
Cumulative effect on change in accounting principle 20,000
Net changes in operating assets and operating
liabilities:
Increase (decrease) in trade accounts receivable (1,145,000) 897,000
Decrease in prepaid assets 48,000 32,000
Increase in other current assets (80,000) (7,000)
Increase (decrease) in accounts payable trade 42,000 (1,010,000)
Increase (decrease) in other accrued liabilities 147,000 (1,000)
----------- -----------
Net cash provided by (used in) operating activities $ 5,383,000 $ (546,000)
----------- -----------
Cash flows from investing activities:
Additions to property and equipment, net (4,956,000) (2,009,000)
Proceeds from sale of oil and gas properties 725,000 3,398,000
Increase in oil and gas properties available for sale - (22,000)
Merger with Piper - 74,000
Increase (decrease) in long term assets 117,000 (72,000)
----------- -----------
Net cash provided by (used in) investing activities (4,114,000) 1,369,000
----------- -----------
Cash flows from financing activities:
Stock issued for cash upon exercise of options 780,000 399,000
Issuance of common stock for cash - 225,000
Proceeds from borrowings - 1,633,000
Repayment of borrowings (1,359,000) (3,347,000)
Decrease (increase) in accounts receivable from
related parties - 23,000
----------- -----------
Net cash used in financing activities (579,000) (1,067,000)
----------- -----------
Net increase (decrease) in cash and cash equivalents 690,000 (244,000)
----------- -----------
Cash at beginning of period 1,024,000 518,000
----------- -----------
Cash at end of period $ 1,714,000 $ 274,000
=========== ===========
Supplemental cash flow information -
Cash paid for interest and financing costs $ 952,000 $ 530,000
=========== ===========
Non-cash financing activities:
Shares issued for all outstanding shares of
Piper Petroleum Company $ - $ 5,234,000
=========== ===========
Common stock issued for the purchase
of oil and gas properties, net of return of
deposited shares $ - $ 375,000
=========== ===========
Shares recquired and retired for
oil and gas properties and option exercise $ - $ 131,000
=========== ===========
Common stock issued note payable
and accrued interest or accounts payable $ - $ 157,000
See accompanying notes to consolidated financial statements.
6
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(1) Basis of Presentation
The accompanying unaudited consolidated financial statements have been
prepared in accordance with the instructions to Form 10-Q and, in accordance
with those rules, do not include all the information and notes required by
generally accepted accounting principles for complete financial statements.
As a result, these unaudited consolidated financial statements should be read
in conjunction with the Company's audited consolidated financial statements
and notes thereto filed with the Company's most recent annual report on Form
10-K. In the opinion of management, all adjustments, consisting only of
normal recurring accruals, considered necessary for a fair presentation of the
financial position of the Company and the results of its operations have been
included. Operating results for interim periods are not necessarily
indicative of the results that may be expected for the complete fiscal year.
For a more complete understanding of the Company's operations and financial
position, reference is made to the consolidated financial statements of the
Company, and related notes thereto, filed with the Company's annual report on
Form 10-K for the year ended June 30, 2002, previously filed with the
Securities and Exchange Commission.
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, marketable securities, income taxes,
derivatives, contingencies and litigation. Actual results could differ from
these estimates.
(2) 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.
7
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
Cumulative
Unrealized Estimated
Cost Gain (loss) Market Value
-------- ----------- ------------
March 31, 2003
Bion Environmental Technologies, Inc. $152,000 $(145,000) $ 7,000
Tipperary Oil & Gas Company $418,000 $ 10,000 $428,000
-------- --------- --------
$570,000 $(135,000) $435,000
======== ========= ========
Cumulative
Unrealized Estimated
Cost Gain (loss) Market Value
-------- ----------- ------------
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
======== ========= ========
(3) Recently Issued Accounting Standards and Pronouncements
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 December 2002, the Financial Accounting Standards Board issued SFAS
No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure an
amendment of FASB statement No. 123." SFAS No. 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
8
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
amends the disclosure requirement 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 reported results. The statement is effective for fiscal years
beginning after December 15, 2002, however earlier application is encouraged.
The Company is currently assessing the impact of SFAS No. 148.
In November 2002, the FASB issued FIN No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others," which requires that a guarantor disclose and
recognize in its financial statements its obligations relating to guarantees
that it has issued. Liability recognition is required at the inception of the
guarantee, whether or not payment is probable. The Company will apply the
recognition and measurement provisions of FIN No. 45 on a prospective basis
and, as such does not expect it to have an initial material impact on its
financial statements upon adoption.
(4) 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 following is a description of the changes and pro forma changes to the
Company's asset retirement obligations from July 1, 2002 to March 31, 2003.
Asset retirement obligation - July 1, 2002 $644,000
Accretion 21,000
Additions - *
Settlements - *
--------
Asset retirement obligation - March 31, 2003 665,000
Less: Current asset retirement obligation -
--------
Long-term asset retirement obligation $665,000
--------
* less than $1,000
9
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(4) Asset Retirement Obligations, Continued
The pro forma effects of the application of SFAS No. 143 would have an
immaterial effect on net income and no effect on earnings per share.
(5) 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 $10,127,000, at March 31, 2003. 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.
Based on indications of levels of hydrocarbons present from drilling
operations conducted in the past, the Company believes the fair values of its
property interests are in excess of their carrying values at March 31, 2003
and that no impairment in the carrying values have occurred. Pursuant to a
ruling in California v. Norton, later affirmed by the 9th Circuit Court of
Appeals, the U.S. Government is required to make a consistency determination
relating to our 1999 lease suspension requests under a 1990 amendment to the
Coastal Zone Management Act. In the event that there is some future adverse
ruling under the Coastal Zone Management Act that we decide not to appeal or
that we appeal without success, it is likely that some or all of our interests
in these leases would become impaired and written off at that time. It is
also possible that other events could occur during the Coastal Zone Management
Act review or appellate process that would cause our interests in the leases
to become impaired, and we will continuously evaluate those factors as they
occur.
(6) Long Term Debt
March 31, 2003 June 30, 2002
A $18,668,000 $18,918,000
B $ 4,926,000 $ 6,021,000
----------- -----------
$23,594,000 $24,939,000
Current Portion $ 2,223,000 $ 3,498,000
----------- -----------
Long-Term Portion $21,371,000 $21,441,000
=========== ===========
10
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2003 and 2002
- -----------------------------------------------------------------------------
A. On May 31, 2002, the Company obtained a $20 million credit facility with
Bank of Oklahoma and Local Oklahoma Bank (the "Banks"). The facility
has a variable interest rate component based on the total debt
outstanding, (4.75% at March 31, 2003) and a monthly commitment
reduction of $82,000 as of March 31, 2003. The proceeds from this
facility were used for the acquisition of Castle's properties and to pay
off the remaining US Bank debt. The loan 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 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, 2003 if the loan has not been retired prior
to this date. 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 remaining
oil and gas properties acquired with the loan proceeds.
11
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2003 and 2002
- -----------------------------------------------------------------------------
(7) Stockholder's Equity
Swartz Agreement
On July 21, 2000, the Company entered into an investment agreement with
Swartz Private Equity, LLC ("Swartz") and issued Swartz a warrant to purchase
500,000 shares of common stock exercisable at $3.00 per share until May 31,
2005. 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.
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.
(8) Commodity Derivative Instruments and Hedging Activities
The Company periodically enters into commodity price risk transactions to
manage its exposure to oil and gas price volatility. These transactions may
take the form of futures contracts, 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.
12
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2003 and 2002
- -----------------------------------------------------------------------------
As of March 31, 2003, the Company recorded a derivative liability of
approximately $691,000 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 $1,391,000 for
the nine months ended March 31, 2003.
As of March 31, 2003, the Company had approximately 18,000 Bbls of oil
and 382,000 Mcf of natural gas subject to commodity price risk contracts for
the remainder of fiscal 2003. The fiscal 2003 contracts have weighted average
floor prices of $25.02 per barrel and $3.00 per Mmbtu, with weighted average
ceiling prices of $25.02 per barrel and $4.50 per Mmbtu, respectively. The
Company has approximately 18,000 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 $25.02 per barrel and $3.00
per Mmbtu, with weighted average ceiling prices of $25.02 per barrel and $4.50
per Mmbtu, respectively.
(9) Comprehensive Income
Comprehensive income (loss) includes all changes in equity during a
period. The components of comprehensive income (loss) for the nine months
ended March 31, 2003 and 2002 are as follows:
Nine Months Ended Nine Months Ended
March 31, 2003 March 31, 2002
----------------- -----------------
Net Income (loss) $1,852,000 $(3,493,000)
Other comprehensive income
Change in fair value of derivative
hedging instruments (691,000) -
Unrealized gain (loss) on marketable
Securities $ (50,000) $ (109,000)
--------- -----------
Other comprehensive income
Comprehensive income (loss) $1,111,000 $(3,602,000)
========= ===========
13
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2003 and 2002
- -----------------------------------------------------------------------------
(10) Income Taxes
For income tax purposes, the Company has net operating loss carryforwards
expiring at various dates through 2022. As a result of the acquisitions and
other issuances of stock, the utilization of the net operating loss
carryforwards is subject to an annual limitation by the provisions of Section
382 of the Internal Revenue Code.
The Company recognized no tax expense in fiscal 2003 primarily due to
recognition of deferred tax assets for which a valuation allowance had
previously been provided and recognized no tax benefit in fiscal 2002 because
realization was not more likely than not. The remaining deferred tax asset at
March 31, 2003, for which a valuation allowance has been recorded, will be
recognized in the financial statements when its realization is more likely
than not.
(11) Earnings Per Share
The following table sets forth the computation of basic and diluted
earnings per share:
Three Months Ended
March 31,
2003 2002
---- ----
Numerator:
Numerator for basic and diluted
earnings (loss) per share - income (loss)
available to common stockholders $ 1,307,000 $(1,587,000)
----------- -----------
Denominator:
Denominator for basic earnings (loss)
per share-weighted average shares
outstanding 22,952,000 12,124,000
Effect of dilutive securities-
stock options and warrants 2,956,000 *
----------- -----------
Denominator for diluted
earnings per common share 25,908,000 12,124,000
=========== ===========
Basic earnings (loss) per common share $ .06 $ (.13)
=========== ===========
Diluted earnings (loss) per common share $ .05 $ (.13)*
=========== ===========
Anti-dilutive securities outstanding 1,809,000 5,564,000
=========== ===========
* Potentially dilutive securities outstanding were anti-dilutive.
14
The following table sets forth the computation of basic and diluted
earnings per share:
Nine Months Ended
March 31,
2003 2002
---- ----
Numerator:
Numerator for basic and diluted
earnings (loss) per share - income (loss)
available to common stockholders $ 1,852,000 $(3,493,000)
----------- -----------
Denominator:
Denominator for basic earnings (loss)
per share-weighted average shares
outstanding 22,756,000 11,513,000
Effect of dilutive securities-
stock options and warrants 2,905,000 *
----------- -----------
Denominator for diluted
earnings (loss) per common share 25,661,000 11,513,000
=========== ===========
Basic earnings (loss) per common share $ .08 $ (.30)*
=========== ==========
Diluted earnings (loss) per common share $ .07 $ (.30)*
=========== ===========
Anti-dilutive securities outstanding 1,860,000 5,564,000
=========== ===========
* Potentially dilutive securities outstanding were anti-dilutive.
15
Item 2. Management's Discussion and Analysis or Plan of Operations
Forward Looking Statement
-------------------------
The statements contained in this report which are not historical fact are
"forward looking statements" that involve various important risks,
uncertainties and other factors which could cause our actual results to differ
materially from those expressed in such forward looking statements. These
factors include, without limitation, the risks and factors included in the
following text as well as other risks previously discussed in our annual
report on Form 10-K.
Critical Accounting Policies and Estimates
------------------------------------------
The discussion and analysis of our financial condition and results of
operations were based upon the consolidated financial statements, which have
been prepared in accordance with accounting principles generally accepted in
the United States. The preparation of these financial statements requires us
to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses. Our significant accounting policies are
described in Note 1 to our consolidated financial statements. In response to
SEC Release No. 33-8040, "Cautionary 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 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.
16
The application of the successful efforts method of accounting requires
managerial judgment to determine that proper classification of wells
designated as developmental or exploratory which will ultimately determine the
proper accounting treatment of the costs incurred. The results from a
drilling operation can take considerable time to analyze and the determination
that commercial reserves have been discovered requires both judgment and
industry experience. Wells may be completed that are assumed to be productive
and actually deliver gas and oil in quantities insufficient to be economic,
which may result in the abandonment of the wells at a later date. Wells are
drilled that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly
account for the results. Delineation seismic incurred to select development
locations within an oil and gas field is typically considered a development
costs 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 very considerable from actual
results. The future drilling costs associated with reserves assigned to
proved undeveloped location may ultimately increase to an extent that these
reserves may be later determined to be uneconomic. For these reasons,
estimates of the economically recoverable quantities of gas and oil
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected therefrom may vary substantially. Any significant variance in the
assumptions could materially affect the estimated quantity and value of the
reserves, which could affect the carrying value of the our gas and oil
properties and/or the rate of depletion of the gas and oil properties. Actual
production, revenues and expenditures with respect to our reserves will likely
vary from estimates, and such variances may be material.
17
Impairment of Gas and Oil Properties
------------------------------------
We review our gas and oil properties for impairment whenever events and
circumstances indicate a decline in the recoverability of their carrying
value. We estimate the expected future cash flows of its gas and oil
properties and compares such future cash flows to the carrying amount of the
gas and oil 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 gas and oil properties to their fair
value. The factors used to determine fair value include, but are not limited
to, estimates of proved reserves, future commodity pricing, future production
estimates, anticipated capital expenditures, and a discount rate commensurate
with the risk associated with realizing the expected cash flows projected.
Given the complexities associated with gas and oil reserve estimates and
the history of price volatility in the gas and oil markers, events may arise
that would require us to record an impairment of the recorded book values
associated with gas and oil properties. As a result of our review, we
recognized an impairment of $162,000 for the nine months ended March 31, 2002.
We did not record an impairment during the nine months ended March 31, 2003.
Recently Issued Accounting Standards and Pronouncements
-------------------------------------------------------
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. We
do not believe this statement will have a material impact to our financial
statements.
In December 2002, the Financial Accounting Standards Board issued SFAS
No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure an
amendment of FASB statement No. 123." SFAS No. 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 requirement 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 reported results. The statement is effective for fiscal years
beginning after December 15, 2002, however earlier application is encouraged.
We are currently assessing the impact of SFAS No. 148.
In November 2002, the FASB issued FIN No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others," which requires that a guarantor disclose and
recognize in its financial statements its obligations relating to guarantees
that it has issued. Liability recognition is required at the inception of the
18
guarantee, whether or not payment is probable. We will apply the recognition
and measurement provisions of FIN No. 45 on a prospective basis and, as such,
do not expect it to have an initial material impact on our financial
statements upon adoption.
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 a 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. We continue to examine
alternative sources of long-term capital, including bank borrowings, the
issuance of debt instruments, the sale of common stock, sales of non-strategic
assets, and joint venture financing. Availability of these alternative
sources of capital will depend upon a number of factors, some of which are
beyond our control.
Working Capital
---------------
At March 31, 2003, we had working capital of $1,163,000 compared to a
working capital deficit of $271,000 at June 30, 2002. Our current assets
include trade accounts receivable of $5,264,000. Our current liabilities
include the current portion of long-term debt of $2,223,000 at March 31, 2003.
The decrease in the current portion of long-term debt and increase in working
capital from March 31, 2003 is primarily attributable to the reduction of our
monthly commitment under our current bank facility. Our increase in working
capital is primarily attributable to the net income derived from our recent
acquisitions.
Cash Provided by (Used in) Operating Activities
-----------------------------------------------
During the nine months ended March 31, 2003, we had cash provided by
operating activities of $5,383,000 compared to cash used in operating
activities of $546,000 during the same period ended March 31, 2002. This
increase in operating activities is a result of increased cash flow from the
properties acquired from Castle Energy Corporation ("Castle") and Piper
Petroleum Company ("Piper") during fiscal year 2002.
Offshore Undeveloped Properties
-------------------------------
On January 9, 2002, we and several other plaintiffs filed a lawsuit in
the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government has materially breached the terms of forty undeveloped
federal leases, some of which are part of our Offshore California properties.
The suit seeks compensation for the lease bonuses and rentals paid to the
Federal Government, exploration costs and related expenses, or alternatively,
for the amount the lessees would have received if the leases had not been
19
breached. The total amount claimed by all lessees for bonuses and rentals
exceeds $1.2 billion, with additional amounts for exploration costs and
related expenses. Our claim (including the claim of our subsidiary Amber
Resources Company) for lease bonuses and rentals paid by us and our
predecessors is in excess of $152,000,000. In addition, our claim for
exploration costs and related expenses will also be substantial.
The Complaint is 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.
As noted, our pending litigation against the United States is in part
predicated on the ruling in California v. Norton 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, a ruling
which the United States appealed to the 9th Circuit Court of Appeals. The 9th
Circuit has affirmed the lower court's decision and made legal findings
consistent with our claims in our pending litigation against the United
States.
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 our
interests in these leases is currently impaired, but in the event that there
is some future adverse ruling under the Coastal Zone Management Act that we
decide not to appeal or that we appeal without success, it is likely that some
or all of our interests in these leases would become impaired and written off
at that time, although we would undoubtedly proceed with our litigation. It is
also possible that other events could occur during the Coastal Zone Management
Act review or appellate process that would cause our interests in the leases
to become impaired, and we will continuously evaluate those factors as they
occur, although once again we would undoubtedly proceed with our litigation.
Offshore Producing Properties
-----------------------------
Point Arguello Unit. Pursuant to a financial arrangement between Whiting
and us, we hold what is essentially the economic equivalent of a 6.07% working
interest, which we call a "net operating interest", in the Point Arguello Unit
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 attributable 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
20
subsidiary of Plains Resources, Inc. In an agreement between Whiting and
Delta, Whiting agreed to retain all of the abandonment costs associated with
our interest in the Point Arguello Unit and the related facilities.
We anticipate that we will participate in the drilling of four wells
in fiscal 2003. Each well will cost approximately $2.8 million ($170,000 to
our interest). We anticipate the drilling costs to be paid through current
operations or additional financing.
Onshore Producing Properties
----------------------------
We estimate our capital expenditures for onshore properties to be
approximately $6,000,000 for the year ending June 30, 2003. However, we are
not obligated to participate in future drilling programs and will not enter
into future commitments to do so unless management believes we have the
ability to fund such projects.
Agreement with Swartz
---------------------
On July 21, 2000, we entered into an investment agreement with Swartz
Private Equity, LLC ("Swartz") and issued Swartz a warrant to purchase 500,000
shares of common stock exercisable at $3.00 per share until May 31, 2005. 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 has been recorded as an adjustment to
equity. On December 20, 2002 the parties entered into an agreement which
terminated the July 21, 2000 agreement as amended and as a result, the Company
will not have the ability to issue and sell ("Put") its common stock to
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.
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.
Options
-------
We received the proceeds from the exercise of options to purchase shares
of our common stock of $780,000 and $407,000 during the nine months ended
March 31, 2003 and year ended June 30, 2002, respectively.
Credit Facility
---------------
We entered into our credit facility with Bank of Oklahoma and Local
Oklahoma Bank ("Credit Facility") upon closing the Castle acquisition, which
was subsequently amended. The Credit Facility, as amended, provides for a
maximum borrowing base of $20 Million and a monthly commitment reduction of
$82,000. The Credit Facility has a variable interest rate component of prime
+1.5%/-.5% based on the total debt outstanding, (currently at prime +.5%).
21
As of March 31, 2003, we had outstanding borrowings of approximately
$18,668,000, letters of credit for Operator's Bonds outstanding of $525,000
and a reduction in borrowing base of $492,000 representing 6 months of
commitment reductions. As of March 31, 2003, we had approximately $315,000
available under the Credit Facility.
Our borrowing base and monthly commitment reduction will be redetermined
at least semi-annually. This determination will be based on our "Engineered
Value". This value is determined by our future net revenues discounted at the
discount rate used by the Bank of Oklahoma as of the date that the
redetermination is made using the pricing parameters used in the engineering
report that is furnished to the Bank of Oklahoma. The most recent
redetermination was effective October 1, 2002.
The foregoing does not purport to be a complete summary of the Credit
Agreement and other loan documents. Complete copies of the original credit
facility documents are filed as exhibits to our Report on Form 8-K dated May
24, 2002.
Income Taxes
------------
The Company recognized tax expense in 2003 primarily due to recognition
of deferred tax assets for which a valuation allowance had previously been
provided and recognized no tax benefit in 2002 because realization was not
more likely than not. The remaining deferred tax asset at March 31, 2003, for
which a valuation allowance has been recorded, will be recognized in the
financial statements when its realization is more likely than not.
Results of Operations for the Three and Nine Months Ended March 31, 2003
Compared to the Three and Nine Months Ended March 31, 2002.
- --------------------------------------------------------------------------
Net Earnings (Loss). Our net income for the three and nine months ended
March 31, 2003 were $1,307,000 and $1,852,000 compared to a net loss of
$1,587,000 and $3,493,000 for the three and nine months ended March 31, 2002.
The results for the three and nine months ended March 31, 2003 and 2002 were
effected by the items described in detail below.
Revenue. Total revenue for the three and nine months ended March 31,
2003 were $6,975,000 and $18,113,000 compared to $1,031,000 and $5,210,000 for
the three and nine months ended March 31, 2002. Oil and gas sales for the
nine months ended March 31, 2003 were $7,717,000 and $19,275,000 compared to
$1,138,000 and $5,317,000 for the three and nine months ended March 31, 2002.
The increase in oil and gas sales during the three and nine months ended March
31, 2003 resulted from the acquisitions completed during fiscal 2002 and an
increase in oil and gas prices. Offshore revenue increased by approximately
$381,000 and $753,000 while experiencing a decline in production of 15% and
15% for the three and nine months ended March 31, 2003, respectively, compared
to the same period a year ago.
Production volumes and average prices received for the three months ended
March 31, 2003 and 2002 are as follows:
22
Three Months Ended
March 31,
2003 2002
Onshore Offshore Onshore Offshore
------- -------- ------- --------
Production:
Oil (barrels) 63,000 53,000 5,000 62,000
Gas (Mcf) 748,000 - 154,000 -
Average Price:
Net of forward contract sales and derivative activity
Oil (per barrel) $30.11 $22.82 $17.26 $13.24
Gas (per Mcf) $ 4.87 $ - $ 1.43 $ -
Gross of forward contract sales and derivative activity
Oil (per barrel) $32.32 $25.55 $17.26 $13.24
Gas (per Mcf) $ 5.98 $ - $ 1.43 $ -
Revenues for the three months ended March 31, 2003 include impact of
derivative loss of $971,000. Production volumes and average prices received
for the nine months ended March 31, 2003 and 2002 are as follows:
Nine Months Ended
March 31,
2003 2002
Onshore Offshore Onshore Offshore
------- -------- ------- --------
Production:
Oil (barrels) 189,000 175,000 61,100 207,000
Gas (Mcf) 2,288,000 - 471,000 -
Average Price:
Net of forward contract sales and derivative activity
Oil (per barrel) $27.52 $20.61 $21.70 $13.81
Gas (per Mcf) $ 3.97 $ - $ 2.41 $ -
Gross of forward contract sales and derivative activity
Oil (per barrel) $28.57 $21.75 $21.84 $13.81
Gas (per Mcf) $ 4.49 $ - $ 2.41 $ -
Revenues for nine months ended March 31, 2003 include impact of
derivative loss of $1,391,000.
Gain on sale of oil and gas properties. During the quarter ended March
31, 2003, the Company sold some immaterial non-strategic properties primarily
acquired in the Piper acquisition. As a result of the sale, the Company
recorded a gain on sale of $229,000.
Lease Operating Expenses. Lease operating expenses for the three and
nine months ended March 31, 2003 were $2,556,000 and $7,192,000, respectively
compared to $865,000 and $2,679,000 for the three and nine months ended March
31, 2002, respectively. Lease operating expense increased compared to 2002 as
a result of the acquisitions completed during fiscal 2003. On a per Bbl
equivalent basis, production expenses and taxes were $9.47 and $8.25 for
onshore properties and $14.71 and $14.21 for offshore properties during the
three and nine months ended March 31, 2003, respectively compared to $4.06 and
$4.12 for onshore properties and $11.82 and $10.17 for offshore properties for
the three and nine months ended March 31, 2002, respectively. The properties
23
acquired during fiscal 2002 have more typical operating costs than those
previously owned by the Company, and as such, lease operating costs per
equivalent Bbl increased during 2003 compared to the prior year. Offshore
lease operating expenses increased slightly for the three and nine months
ended March 31, 2003 and the costs per Bbl equivalent increased as
production declined 14% and 15%, respectively.
Depreciation and Depletion Expense. Depreciation and depletion expense
for the three and nine months ended March 31, 2003 was $1,428,000 and
$4,305,000, respectively compared to $587,000 and $2,249,000, for the three
and nine months ended March 31, 2002. On a per Bbl equivalent basis, the
depletion rate was $6.18 and $5.98 for onshore properties and $4.81 and $4.90
for offshore properties during the three and nine months ended March 31, 2003,
respectively compared to $9.34 and $10.08 for onshore properties and $4.05 and
$4.77 for offshore properties for the three and nine months ended March 31,
2002, respectively. Depreciation and depletion expense increased during the
three and nine months relating to the acquisitions completed during fiscal
2003. The fluctuation in oil and gas prices either extends on curtails the
lives of our properties resulting in either lower or higher depletion expense.
Exploration Expenses. Exploration expenses consist of geological,
geophysical costs and lease rentals. Exploration expenses were $83,000 and
$130,000 respectively for the three and nine months ended March 31, 2003
compared to $16,000 and $125,000 for the three and nine months ended March 31,
2002, respectively.
Abandoned and Impaired Properties. For the nine months ended March 31,
2002 we impaired $60,000 relating to undeveloped properties in onshore
California and $102,000 relating to our Eland and Stadium fields in Stark
County, North Dakota, which were sold on February 1,2002. There were no
abandonments or impairments for the nine months ended March 31, 2002.
Dry Hole Costs. Dry hole costs for the three and nine months ended March
31, 2003 were $89,000 and $132,000, respectively compared to $15,000 and
$396,000 for the three and nine months ended March 31, 2002, respectively.
The costs incurred in fiscal 2003 represent one operated drilling location in
Louisiana and two non-operated drilling locations, one in Texas and one in
Montana. The costs incurred during fiscal 2002 related to an unsuccessful
drilling program in South Dakota.
Professional Fees. Professional fees for the three and nine months ended
March 31, 2003 were $187,000 and $506,000, respectively compared to $284,000
and $954,000 for the three and nine months ended March 31, 2002, respectively.
Professional fees consist of corporate, legal and accounting costs related to
investor relations 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 three and nine months ended March 31, 2003 were $881,000 and $2,567,000,
respectively compared to $566,000 and $1,151,000 for the three and nine months
ended March 31, 2002, respectively. The increase in general and
administrative expenses is primarily attributed to increased costs associated
with the acquisitions completed in fiscal 2003 including office relocation and
additional staff.
Stock Option Expense. Stock option expense has been recorded for the
three and nine months ended March 31, 2003 in the amount of $36,000 and
24
$82,000, respectively and $20,000 and $53,000, respectively, for the three and
nine months ended March 31, 2002. This expense is for options granted to
certain directors and consultants at option prices below the market price at
the date of grant. The stock option expense for fiscal 2003 and 2002 can
primarily be attributed to options to certain consultants that provide us with
shareholder relations services and options to our directors.
Interest and Financing Costs. Interest and financing costs for the three
and nine months ended March 31, 2003 were $408,000 and $1,348,000,
respectively compared to $274,000 and $947,000 for the three and nine months
ended March 31, 2002, respectively. The increase in interest and financing
costs can be attributed to the Castle acquisition which closed on May 31,
2002.
ITEM 3. 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 $23,593,000 of variable rate
debt obligations at March 31, 2003. The annual effect of a one percent change
in interest rates would be approximately $235,930. The interest rate on these
variable rate debt obligations approximates current market rates as of March
31, 2003.
Item 4. Controls and Procedures
Under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, we
have evaluated the effectiveness of the design and operation and our
disclosure controls and procedures within 90 days of the filing date of this
quarterly report, and, based upon their evaluation, our principal executive
officer and principal financial officer have concluded that these controls and
procedures are effective. There were no significant changes in our internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation.
25
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
On January 9, 2002, we filed a lawsuit along with several other companies
in the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government materially breached the terms of forty undeveloped federal
leases, some of which are part of our Offshore California properties. The
Complaint is based on our collective claims that post-leasing amendments to a
federal statute governing offshore activities have now been interpreted to
alter significantly our rights and abilities to move forward with further
exploration and development activities, and that the Government has failed to
carry out its own obligations under the leases which has resulted in
substantial delays and interference in our exploration and development
efforts. The forty undeveloped leases are located in the Offshore Santa Maria
Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the
Santa Barbara Channel off Santa Barbara and Ventura counties.
The 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 of the collective plaintiffs for bonuses and rentals exceeds
$1.2 billion, with additional amounts for exploration costs and related
expenses. Our claim (including the claim of our subsidiary Amber Resources
Company) for lease bonuses and rentals paid by us and our predecessors is in
excess of $152,000,000. In addition, we have asserted a claim for exploration
costs and related expenses. The U.S. Government has not yet filed an answer
to our Complaint.
Item 2. Changes in Securities.
During the quarter ended March 31, 2003, Delta did not issue any
securities in transactions that were not registered under the Securities Act
of 1933.
Item 3. Defaults Upon Senior Securities. None.
Item 4. Submission of Matters to a Vote of Security Holders. None
Item 5. Other Information. None.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit No. Description
99.1 Certification of Chief Executive Officer Pursuant
to 18 U.S.C. Section 1350
99.2 Certification of Chief Financial Officer Pursuant
to 18 U.S.C. Section 1350
(b) Reports on Form 8-K. During the quarter ended March 31, 2003,
Delta filed Reports on Form 8-K as follows: None.
26
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this Amended Report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Date: May 13, 2003 DELTA PETROLEUM CORPORATION
(Registrant)
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
27
CERTIFICATIONS PURSUANT TO RULE 13a-14 AND 15d-14 UNDER
THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Roger A. Parker, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Delta Petroleum
Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified for
the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 13, 2003 /s/ Roger A. Parker
-----------------------------------------
Name: Roger A. Parker
Title: Chief Executive Officer
28
CERTIFICATIONS PURSUANT TO RULE 13a-14 AND 15d-14 UNDER
THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Kevin K. Nanke, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Delta Petroleum
Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified for
the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 13, 2003 /s/ Kevin K. Nanke
-------------------------------------
Name: Kevin K. Nanke
Title: Chief Financial Officer
29