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 December 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___
25,491,000 shares of common stock $.01 par value were outstanding as of
January 27, 2004.
FORM 10-Q
2nd QTR.
FY 2004
INDEX
PART I FINANCIAL INFORMATION
PAGE NO.
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets - December 31, 2003
(unaudited) and June 30, 2003 ........................... 3
Consolidated Statements of Operations - Three and
Six Months Ended December 31, 2003 and 2002
(unaudited) ............................................. 4-5
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (loss) - Year Ended June 30,
2003 and Six Months Ended December 31, 2003
(unaudited) ............................................. 6
Consolidated Statements of Cash Flows -
Six Months Ended December 31, 2003 and 2002
(unaudited) ............................................. 7
Notes to Consolidated Financial Statements
(unaudited) ............................................. 8-19
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations ..................... 20-28
Item 3. Quantitative and Qualitative Disclosures About
Market Risk ............................................. 29
Item 4. Controls and Procedures ................................. 29
PART II OTHER INFORMATION
Item 1. Legal Proceedings ....................................... 30
Item 2. Changes in Securities, Use of Proceeds and
Issuer Purchases of Equity Securities ................... 30
Item 3. Defaults upon Senior Securities ......................... 31
Item 4. Submission of Matters to a Vote of
Security Holders ........................................ 31
Item 5. Other Information ...................................... 31
Item 6. Exhibits and Reports on Form 8-K ........................ 31
The terms "Delta", "Company", "we", "our", and "us" refer to Delta Petroleum
Corporation unless the context suggests otherwise.
2
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- -----------------------------------------------------------------------------
December 31, June 30,
2003 2003
------------ -----------
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 711,000 $ 2,271,000
Marketable securities available for sale 768,000 662,000
Trade accounts receivable, net of allowance for doubtful
accounts of $50,000 at December 31, 2003 and June 30, 2003 4,629,000 4,410,000
Prepaid assets 1,438,000 764,000
Other current assets 475,000 560,000
------------ -----------
Total current assets 8,021,000 8,667,000
------------ -----------
Property and Equipment:
Oil and gas properties, at cost (using the successful efforts
method of accounting) 112,605,000 90,487,000
Less accumulated depreciation and depletion (16,226,000) (12,669,000)
------------ -----------
Net property and equipment 96,379,000 77,818,000
------------ -----------
Long term assets:
Investment in LNG project 1,015,000 -
Deferred financing costs 141,000 117,000
Partnership net assets 198,000 245,000
------------ -----------
Total long term assets 1,354,000 362,000
$105,754,000 $86,847,000
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current portion of long-term debt $ 7,945,000 $10,039,000
Accounts payable 6,428,000 3,604,000
Derivative instruments 143,000 468,000
Current foreign tax payable 703,000 703,000
Other accrued liabilities 546,000 1,087,000
------------ -----------
Total current liabilities 15,765,000 15,901,000
------------ -----------
Long-term Liabilities:
Asset retirement obligation 1,060,000 868,000
Long-term debt, net 28,000,000 22,175,000
------------ -----------
Total long-term liabilities 29,060,000 23,043,000
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 25,412,000 shares at December 31, 2003 and 23,286,000
at June 30, 2003 254,000 233,000
Additional paid-in capital 86,200,000 75,642,000
Accumulated other comprehensive loss 55,000 (376,000)
Accumulated deficit (25,580,000) (27,596,000)
------------ -----------
Total stockholders' equity 60,929,000 47,903,000
------------ -----------
Commitments $105,754,000 $86,847,000
============ ===========
See accompanying notes to consolidated financial statements.
3
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- -----------------------------------------------------------------------------
Three Months Ended
December 31, December 31,
2003 2002
------------ ------------
Revenue:
Oil and gas sales $ 8,074,000 $ 5,808,000
Realized loss on derivative instruments, net (68,000) (387,000)
----------- -----------
Total revenue 8,006,000 5,421,000
Operating expenses:
Lease operating expense 2,341,000 2,303,000
Depreciation and depletion 2,306,000 1,101,000
Exploration expense 138,000 40,000
Dry hole costs 177,000 43,000
Professional fees 308,000 142,000
General and administrative (includes stock option expense
of $3,000 and $11,000 for the three months ended
December 31, 2003 and 2002, respectively) 1,528,000 871,000
----------- -----------
Total operating expenses 6,798,000 4,500,000
----------- -----------
Income from continuing operations 1,208,000 921,000
Other income and (expense):
Other income 15,000 10,000
Interest and financing costs (576,000) (432,000)
----------- -----------
Total other expense (561,000) (422,000)
Income before discontinued operations 647,000 499,000
Discontinued operations:
Income from operations of properties sold, net 33,000 (71,000)
Loss on sale of properties (28,000) -
----------- -----------
Net income $ 652,000 $ 428,000
=========== ===========
Basic income per common share:
Income before discontinued operations $ 0.03 $ 0.02
Discontinued operations - * - *
----------- -----------
Net Income $ 0.03 $ 0.02
=========== ===========
Diluted income per common share:
Income before discontinued operations $ 0.03 $ 0.02
Discontinued operations - * - *
----------- -----------
Net Income $ 0.03 $ 0.02
=========== ===========
* less than $.01 per common share
See accompanying notes to consolidated financial statements.
4
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- -----------------------------------------------------------------------------
Six Months Ended
December 31, December 31,
2003 2002
------------ ------------
Revenue:
Oil and gas sales $15,572,000 $11,062,000
Realized loss on derivative instruments, net (380,000) (420,000)
----------- -----------
Total revenue 15,192,000 10,642,000
Operating expenses:
Lease operating expense 4,550,000 4,273,000
Depreciation and depletion 3,948,000 2,706,000
Exploration expense 268,000 47,000
Dry hole costs 177,000 43,000
Professional fees 612,000 319,000
General and administrative (includes stock option expense
of $108,000 and $46,000 for the six months ended
December 31, 2003 and 2002, respectively) 2,667,000 1,734,000
----------- -----------
Total operating expenses 12,222,000 9,122,000
----------- -----------
Income from continuing operations 2,970,000 1,520,000
----------- -----------
Other income and (expense):
Other income 35,000 21,000
Interest and financing costs (1,085,000) (940,000)
----------- -----------
Total other expense (1,050,000) (919,000)
----------- -----------
Income before discontinued operations and
cumulative effect on change in accounting principle 1,920,000 601,000
Discontinued operations:
Income from operations of properties sold, net 124,000 (36,000)
Loss on sale of properties (28,000) -
----------- -----------
Income before cumulative effect of change in accounting
principle 2,016,000 565,000
Cumulative effect of change in accounting principle - (20,000)
----------- -----------
Net income $ 2,016,000 $ 545,000
=========== ===========
Basic income per common share:
Income before discontinued operations and cumulative
effect on change in accounting principle $ 0.08 $ 0.02
Discontinued operations - * - *
----------- -----------
Income before cumulative effect of change in accounting
principle 0.08 0.02
Cumulative effect of change in accounting principle - * - *
----------- -----------
Net income $ 0.08 $ 0.02
=========== ===========
Diluted income per common share:
Income before discontinued operations and cumulative
effect on change in accounting principle $ 0.07 $ 0.02
Discontinued operations 0.01 - *
----------- -----------
Income before cumulative effect of change in
accounting principle 0.08 0.02
Cumulative effect of change in accounting principle - * - *
----------- -----------
Net income $ 0.08 $ 0.02
=========== ===========
* less than $.01 per common share
See accompanying notes to consolidated financial statements.
5
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Consolidated Statement of Stockholders' Equity and Comprehensive Income (Loss)
Year Ended June 30, 2003 and Six Months Ended December 31, 2003
(Unaudited)
- -----------------------------------------------------------------------------
Accumu-
lated
other
Put compre- Compre-
Common Stock Additional Option hensive hensive
-------------------- paid-in on Delta income income Accumulated
Shares Amount capital stock (loss) (loss) deficit Total
---------- -------- ---------- ---------- -------- --------- ----------- -----------
Balance, July 31,
2002 22,618,000 $226,000 76,514,000 (2,886,000) (85,000) (28,853,000) $44,916,000
Comprehensive
loss:
Net income - - - - - 1,257,000 1,257,000 1,257,000
---------
Other comprehensive
loss, 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 - 124,000
=========
Stock options granted
as compensation - - 124,000 - - - 124,000
Put options 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
Comprehensive
income:
Net income - - - - - 2,016,000 2,016,000 2,016,000
---------
Other comprehen-
sive gain, net
of tax
Change in fair
value of deri-
vative hedging
instruments - - - - 106,000 106,000 - 106,000
Unrealized gain
on equity
securities,
net - - - - 325,000 325,000 - 325,000
---------
Comprehensive income - - - - - 2,447,000
=========
Stock options granted
as compensation 108,000 - - - 108,000
Shares issued for
oil and gas
properties 1,773,000 18,000 9,449,000 - - - 9,467,000
Shares issued for
cash upon
exercise of
options 353,000 3,000 1,001,000 - - - 1,004,000
---------- -------- ---------- ---------- -------- ----------- -----------
Balance,
December 31,
2003 25,412,000 $254,000 86,200,000 - 55,000 (25,580,000) $60,929,000
========== ======== ========== ========== ======== =========== ===========
See accompanying notes to consolidated financial statements.
6
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- -----------------------------------------------------------------------------
Six Months Ended
December 31, December 31,
2003 2002
------------ -----------
Cash flows operating activities:
Net income $ 2,016,000 $ 545,000
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation and depletion 3,948,000 2,706,000
Depreciation and depletion - discontinued operations 111,000 171,000
Stock option expense 108,000 46,000
Amortization of financing costs 266,000 227,000
Loss on sale of oil and gas properties 28,000 -
Cumulative effect on change in accounting principle - 20,000
Net changes in operating assets and operating liabilities:
(Increase) decrease in trade accounts receivable (414,000) 755,000
(Increase) decrease in prepaid assets (674,000) 27,000
Increase in other current assets - (57,000)
Increase (decrease) in accounts payable trade 1,298,000 (261,000)
Increase (decrease) in other accrued liabilities (541,000) 198,000
----------- -----------
Net cash provided by operating activities $ 6,146,000 $ 4,377,000
----------- -----------
Cash flows from investing activities:
Additions to property and equipment, net (14,690,000) (2,774,000)
Proceeds from sales of oil and gas properties 3,422,000 -
Payment on investment transaction (307,000) -
Increase in long term assets 47,000 123,000
----------- -----------
Net cash used in investing activities (11,528,000) (2,651,000)
----------- -----------
Cash flows from financing activities:
Stock issued for cash upon exercise of options 1,004,000 529,000
Proceeds from borrowings 13,704,000 -
Payment of financing fees (205,000) -
Repayment of borrowings and financing costs (10,681,000) (983,000)
----------- -----------
Net cash provided by (used in) financing activities 3,822,000 (454,000)
----------- -----------
Net increase (decrease) in cash and cash equivalents (1,560,000) 1,272,000
----------- -----------
Cash at beginning of period 2,271,000 1,024,000
----------- -----------
Cash at end of period $ 711,000 $ 2,296,000
=========== ===========
Supplemental cash flow information -
Cash paid for interest and financing costs $ 1,111,000 $ 688,000
=========== ===========
See accompanying notes to consolidated financial statements.
7
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended December 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, 2003, 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.
8
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended December 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(2) 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:
December 31, June 30,
2003 2003
----------- -----------
INTANGIBLE ASSETS:
Proved leasehold acquisition costs $84,598,000 $68,966,000
Unproved leasehold acquisition costs 10,201,000 10,164,000
----------- -----------
Total leasehold acquisition costs 94,799,000 79,130,000
Less: Accumulated depletion 11,946,000 10,858,000
----------- -----------
Net leasehold acquisition costs $82,853,000 $68,272,000
=========== ===========
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.
9
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended December 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(3) 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.
Cumulative
Unrealized Estimated
Cost Gain (loss) Market Value
-------- ----------- ------------
December 31, 2003
Bion Environmental
Technologies, Inc. $152,000 $(146,000) $ 6,000
Tipperary Oil & Gas Company $418,000 $ 344,000 $762,000
-------- --------- --------
$570,000 $ 198,000 $768,000
======== ========= ========
Cumulative
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
======== ========= ========
(4) 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 $10,201,000, at December 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.
10
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended December 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(4) Oil and Gas Properties, Continued
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 December 31, 2003
and that no impairment in the carrying values has occurred. Pursuant to a
ruling in California v. Norton, later affirmed by the 9th Circuit Court of
Appeals, the U.S. Government 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. On January 9, 2002, the Company and several other plaintiffs filed a
lawsuit in the United States Court of Federal Claims in Washington, D.C.
alleging that the U.S. Government has materially breached the terms of forty
undeveloped federal leases, some of which are part of our Offshore California
properties. See disclosure in Item 1 of Part II.
Fiscal 2004 - Acquisition
On September 19, 2003, the Company completed an acquisition of certain
producing and drilling prospects in Colorado and Wyoming from Edward Mike
Davis LLC and Edward Mike Davis, individually (collectively, "Davis"),
pursuant to the terms of a Purchase and Sale Agreement effective as of August
1, 2003. The total consideration paid for these properties was 1,000,000
shares of our common stock and $8 million, of which $2 million was paid in
cash and $6 million in the form of a short-term promissory note payable which
was paid on October 3, 2003. The shares issued were recorded at a price of
$5.15, a five day average surrounding the announcement of the transaction.
The Company recorded an upward purchase price adjustment of approximately
$220,000 which reflects the operating and acquisition related costs in excess
of net revenue from the effective date of August 1, 2003 through the closing
date of September 19, 2003. The total acquisition cost of $13,380,000 was
allocated between proved developed producing of $5,220,000 and unproved
undeveloped of $8,160,000 based on preliminary information.
The Company will also be obligated to issue additional shares of common
stock to Davis in the event that it is determined that valid drillable
prospects for the discovery and production of hydrocarbons on certain leases,
or land pooled therewith, meet certain requirements, including a determination
that there are at least 1,000,000 barrels of recoverable oil or six billion
cubic feet of recoverable gas, or a combination thereof, in an individual
prospect. These prospects are referred to as "Bonus Prospects." Davis will
receive up to 190,000 (not more that $950,000 worth of stock) shares for each
Bonus Prospect. No more than 1,900,000 shares will be issued to Davis under
this provision, regardless of how many barrels of oil equivalent may be found.
Davis also has the option to elect to take an assignment of up to a 50%
working interest in each well drilled on any prospect within the acquired
properties after payout, on a well-by-well basis.
11
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended December 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(4) Oil and Gas Properties, Continued
The following unaudited pro forma consolidated statements of operations
information assumes that the Davis acquisition occurred as of
July 1, 2002:
Three Months Ended Six Months Ended
December 31, December 31,
2003 2002 2003 2002
---------- ---------- ----------- -----------
Oil and gas sales $8,074,000 $6,160,000 $16,641,000 $11,619,000
Net income $ 652,000 $ 547,000 $ 2,267,000 $ 735,000
Net income per common
share:
Basic $ .03 $ .02 $ .10 $ .03
Diluted $ .03 $ .02 $ .09 $ .03
The above unaudited adjusted Pro Forma Consolidated Statements of
Operations are based on the historical results of Davis and Delta, are not
necessarily indicative of the results of operations if Delta would have
acquired the Davis properties at July 1, 2002.
On December 10, 2003, the Company completed an acquisition of certain
production and acreage located primarily in Eland and Stadium fields in Stark
County, North Dakota, from Sovereign Holdings, LLC, a privately - held
Colorado limited liability company ("Sovereign"), pursuant to the terms of a
Purchase and Sale Agreement effective as of December 1, 2003. The total
consideration paid for these properties was 773,500 shares of our common
stock. The shares issued were recorded at a price of $5.58, a five day average
surrounding the closing of the transaction. The Company recorded an downward
purchase price adjustment of approximately $84,000 which reflects the
operating and acquisition related costs in excess of net revenue from the
effective date of December 1, 2003 through the closing date of December 5,
2003. The total acquisition cost of $4,233,000 was allocated to proved
developed producing.
Fiscal 2004 - Discontinued Operations
On December 5, 2003, the Company completed the sale of certain properties
located in Texas to Sovereign for cash consideration of $2,600,000 with an
effective date of January 1, 2004 and resulted in a loss on the sale of oil
and gas properties of $28,000. In accordance with SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets", the results of
operations and loss on the sale of these properties have been reflected as
discontinued operations. Revenues from the sale of these oil and gas
properties was approximately $292,000 and $550,000 for the three and six
months ended December 31, 2003 and $283,000 and $496,000 for the three and six
months ended December 31, 2002.
12
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended December 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(5) Long Term Debt
December 31, 2003 June 30, 2003
A $31,472,000 $27,668,000
B $ 3,765,000 $ 4,546,000
C $ 708,000 $ -
----------- -----------
$35,945,000 $32,214,000
Current Portion $ 7,945,000 $10,039,000
----------- -----------
Long-Term Portion $28,000,000 $22,175,000
=========== ===========
A On December 30, 2003, the Company amended and restated its credit
facility. The new $50 million facility with Bank of Oklahoma, U.S.
Bank National Association and Hibernia National Bank (the "Banks")
has an available borrowing base of $32.85 million. The facility has
a variable interest rate of LIBOR +1.75% to 2.85% and/or prime
+.5%/-.5% based on the total debt outstanding and a monthly commitment
reduction of $350,000. The Company paid a $107,000 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
December 31, 2006 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 and the oil and gas properties purchased on
December 10, 2003. 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 December 31, 2003, the Company
was in compliance with its quarterly debt covenants and restrictions,
as amended.
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 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.
13
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended December 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(5) Long Term Debt, Continued
C On October 1, 2003, the Company entered into a $1,000,000 note payable
agreement to acquire a minority interest in an unaffiliated Delaware
limited liability company that is currently in the process of
attempting to obtain rights to own and operate a liquified natural gas
facility from an existing platform located in offshore California.
The investment is to be paid in ten $100,000 installments and has a
interest rate of 5% per annum. The Company has recorded this
investment in long term assets and is carried at cost.
Maturities of long-term debt for each of the five years following
December 31, 2003 are as follows:
YEAR ENDING December 31,
2004................................ $ 7,945,000
2005................................ 4,200,000
2006................................ 4,200,000
2007................................ 4,200,000
2008................................ 4,200,000
Thereafter 11,200,000
-----------
$35,945,000
===========
(6) Stockholders' Equity
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 have 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.
14
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended December 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(6) Stockholders' Equity, Continued
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 six months ended December 31, 2003 and
2002 would have been as follows:
December 31,
-------------------------------
2003 2002
---- ----
Net Income $ 2,016,000 $ 545,000
FAS 123 compensation effect (4,316,000)* (173,000)
----------- ----------
Net loss after FAS 123
compensation effect $(2,300,000) $ 372,000
=========== ==========
Income (loss) per common share: $ (.10) $ .02
=========== ==========
The Company had approximately 5,805,000 options to purchase the Company's
common stock outstanding, with an average price of $3.78, at December 31,
2003. The Company granted 260,000 options during the quarter ended December
31, 2003. No options were granted during the three months ended December 31,
2002.
* During the three months ended September 30, 2003 the Company granted to
its officers options to purchase 1,250,000 shares of its common stock at a
price of $5.29 per share, which was the market price on the date of the grant.
All of these options vested immediately upon issuance. The fair market value
of each option granted was $3.45 and was calculated using a risk free rate of
4.34%, volatility factors of the expected market price of the Company's common
stock of 48.94% and an expected life of 10 years, the life of the option.
(7) Commodity Derivative Instruments and Hedging Activities
The Company periodically enters into commodity price risk transactions to
manage its exposure to oil and gas price volatility. These transactions may
take the form of futures contracts, swaps or options. All transactions are
accounted for in accordance with requirements of SFAS No. 133 which the
Company adopted on January 1, 2001. Accordingly, unrealized gains and losses
related to the change in fair market value of derivative contracts which
qualify and are designated as cash flow hedges are recorded as other
comprehensive income or loss and such amounts are reclassified to realized
gain (loss) on derivative instruments as the associated production occurs.
Derivative contracts that do not qualify for hedge accounting treatment are
recorded as derivative assets and liabilities at market value in the
consolidated balance sheet, and the associated unrealized gains and losses are
recorded as current income or expense in the consolidated statement of
operations. While such derivative contracts do not qualify for hedge
accounting, management believes these contracts can be utilized as an
effective component of commodity price risk activities.
15
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended December 31, 2003 and 2002
(Unaudited)
- -----------------------------------------------------------------------------
(7) Commodity Derivative Instruments and Hedging Activities, Continued
As of December 31, 2003, the Company recorded a derivative liability of
approximately $143,000 for the fair market value of its derivative instruments
designated as cash flow hedges and a corresponding gain in other comprehensive
income. The realized net losses from hedging activities were $68,000 and
$387,000 for the three and six months ended December 31, 2003.
As of December 31, 2003, the Company had approximately 122,000 Bbls of
oil and 364,000 mcf of natural gas subject to commodity price risk contracts
for the remainder of fiscal 2004. The fiscal 2004 contract has weighted
average floor prices of $31.11 per barrel and $5.25 per Mmbtu, with weighted
average ceiling prices of $31.11 per barrel and $6.43 per Mmbtu, respectively.
(8) Comprehensive Income
Comprehensive income (loss) includes all changes in equity during a
period. The components of comprehensive income (loss) for the six months ended
December 31, 2003 and 2002 are as follows:
Six Months Ended Six Months Ended
December 31, 2003 December 31, 2002
----------------- -----------------
Net Income $2,016,000 $ 545,000
Other comprehensive income
Change in fair value of derivative
hedging instruments 325,000 -
Unrealized gain (loss) on marketable
securities $ 106,000 $ (99,000)
---------- ---------
Other comprehensive income (loss) 431,000 (99,000)
Comprehensive income $2,447,000 $ 446,000
========== =========
(9) Income Taxes
For income tax purposes, the Company has net operating loss carryforwards
expiring at various dates through 2023. 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 the first six months of fiscal
2004 primarily due to recognition of deferred tax assets for which a valuation
allowance had previously been provided and recognized no tax benefit in fiscal
2003 because realization was not more likely than not. The remaining deferred
tax asset at December 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.
16
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended December 31, 2003 and 2002
- -----------------------------------------------------------------------------
(10) Earnings Per Share
The following table sets forth the computation of basic and diluted
earnings per share, net of discontinued operations:
Three Months Ended
December 31,
2003 2002
---- ----
Numerator:
Numerator for basic and diluted
earnings per share - income
available to common stockholders $ 652,000 $ 428,000
----------- -----------
Denominator:
Denominator for basic earnings
per share-weighted average shares
outstanding 23,560,000 22,690,000
Effect of dilutive securities-
stock options and warrants 2,183,000 2,786,000
----------- -----------
Denominator for diluted
earnings per common share 25,743,000 25,476,000
=========== ===========
Anti-dilutive securities outstanding 75,000 2,023,000
=========== ===========
Basic income per common share:
Income before discontinued operations $ .03 $ .02
Discontinued operations - * - *
Net Income ----------- -----------
$ .03 $ .02
=========== ===========
Diluted income per common share:
Income before discontinued operations $ .03 $ .02
Discontinued operations - * - *
Net Income ----------- -----------
$ .03 $ .02
=========== ===========
* less than $.01 per common share
17
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended December 31, 2003 and 2002
- -----------------------------------------------------------------------------
(10) Earnings Per Share, Continued
Six Months Ended
December 31,
2003 2002
---- ----
Numerator:
Numerator for basic and diluted
earnings per share - income
available to common stockholders $ 2,016,000 $ 545,000
----------- -----------
Denominator:
Denominator for basic earnings
per share-weighted average shares
outstanding 23,651,000 22,749,000
Effect of dilutive securities-
stock options and warrants 2,127,000 3,056,000
----------- -----------
Denominator for diluted
earnings per common share 25,778,000 25,805,000
=========== ===========
Anti-dilutive securities outstanding 360,000 1,753,000
=========== ===========
Basic income per common share:
Income before discontinued operations
and cumulative effect on change in
accounting principle $ .08 $ .02
Discontinued operations - * - *
Income before cumulative effect of ----------- -----------
change in accounting principle .08 .02
Cumulative effect of change in - * - *
accounting principle ----------- -----------
Net Income $ .08 $ .02
=========== ===========
Diluted income per common share:
Income before discontinued operations
and cumulative effect on change in
accounting principle $ .07 $ .02
Discontinued operations .01 - *
Income before cumulative effect of ----------- -----------
change in accounting principle .08 .02
Cumulative effect of change in - * - *
accounting principle ----------- -----------
Net Income $ .08 $ .02
=========== ===========
* less than $.01 per common share
18
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended December 31, 2003 and 2002
- -----------------------------------------------------------------------------
(11) Commitments
As of December 31, 2003, the Company had approximately 280 Bbls of oil
per day of its offshore production under fixed price contracts. The
contracts' fixed prices range from $25.50 to $29.70.
(12) Reclassification
Certain amounts in the 2002 financial statements have been reclassified
to conform to the 2003 financial statement presentation.
19
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Forward Looking Statements
--------------------------
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 reported in
our annual report on Form 10-K. 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 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
included in our annual report on Form 10-K. In response to SEC Release No.
33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting
Policies," we have identified certain of these policies as being of particular
importance to the portrayal of our financial position and results of
operations and which require the application of significant judgment by
management. We analyze our estimates, including those related to oil and gas
reserves, bad debts, oil and gas properties, marketable securities, income
taxes, derivatives, contingencies and litigation, and base our estimates on
historical experience and various other assumptions that we believe are
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
20
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. We reevaluate our
reserves quarterly.
Impairment of Gas and Oil Properties
------------------------------------
We review our oil and gas properties for impairment whenever events and
circumstances indicate a decline in the recoverability of their carrying
value. We estimate the expected future cash flows of our 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
21
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 record an impairment of the recorded book
values associated with gas and oil properties. The Company did not record an
impairment during the six months ended December 31, 2003 and 2002.
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.
Asset Retirement Obligation
---------------------------
We account for our asset retirement obligations under SFAS No. 143
"Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities
to record the fair value of a liability for retirement obligations of acquired
assets. SFAS No. 143 is effective for fiscal years beginning after June 15,
2002.
The Company adopted SFAS No. 143 on July 1, 2002 and recorded a
cumulative effect of a change in accounting principle on prior years related
to the depreciation and accretion expense that would have been reported had
the fair value of the asset retirement obligations, and corresponding increase
in the carrying amount of the related long-lived assets, been recorded when
incurred. The Company's asset retirement obligations arise from the plugging
and abandonment liabilities for its oil and gas wells.
22
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
---------------
Although we have a working capital deficit of $7,744,000 at December 31,
2003, we believe our cash flow will be sufficient to service our current
obligation during our 2004 fiscal year. It is also possible, however, that we
may obtain additional working capital from outside sources through the
issuance of equity securities or from the sale of properties in the ordinary
course of our business. Our current portion of long-term debt includes a
monthly commitment of $350,000 relating to our credit facility, $708,000
relating to a promissory note for an investment in limited liability company
that is currently in the process of attempting to obtain the right to own and
operate a liquid natural gas facility and the entire Kaiser Francis note
payable of $3,765,000 which is due on June 1, 2004.
Cash Provided by Operating Activities
-------------------------------------
During the six months ended December 31, 2003, we had cash provided by
operating activities of $6,146,000 compared to cash provided by operating
activities of $4,377,000 during the same period ended December 31, 2002. This
increase in operating activities is a result of the increase in oil and
natural gas sales relating to acquisitions completed during the fourth quarter
of fiscal 2003 and the two acquisitions completed during the six months ended
December 31, 2003 discussed in detail below.
Cash Used in Investing Activities
---------------------------------
During the six months ended December 31, 2003, we had cash used in
investing activities of $11,528,000 compared to cash used in investing
activities of $2,651,000 during the same period ended December 31, 2002.
Investing activities for fiscal 2004 included $8,000,000 used toward the
acquisition of production and drilling prospects in Colorado and Wyoming from
Edward Mike Davis LLC and Edward Mike Davis, individually (collectively,
"Davis") and $6,690,000 for development activities offset by sales proceeds of
$3,422,000. Investing activities for fiscal 2003 included approximately
$2,774,000 for development costs.
During our current fiscal year, we agreed to invest an aggregate of $1
million as a member of an unaffiliated Delaware limited liability company that
is currently in the process of attempting to obtain the rights to own and
operate a liquid natural gas facility from an existing platform located
offshore California. If the limited liability company is successful in
23
obtaining these rights, it intends to engage in the business of accepting and
vaporizing liquid natural gas delivered by liquid natural gas tankers,
transporting the vaporized liquid natural gas through proprietary gas
pipelines and selling the vaporized natural gas to third party customers
located in California. As payment for our membership interest in the limited
liability company, we executed a term promissory note that requires us to make
payments of $100,000 per month until August 1, 2004, at which time all of the
amounts due under the promissory note will become due and payable. As
collateral for the payment of this obligation, we granted a first lien on our
membership interest in the limited liability company and on all of the
proceeds and other distributions from the limited liability company that are
attributable to our membership interest. As of the date of this Report, the
limited liability company had not yet engaged in any revenue producing
activities.
Cash Used In Financing Activities
---------------------------------
During the six months ended December 31, 2003, we had cash provided by
financing activities of $3,822,000 compared to cash used in financing
activities of $454,000 for the same period ended December 31, 2002. Financing
activities for fiscal 2004 consist of proceeds from borrowings of $13,704,000,
repayment of borrowings and financing costs of $10,681,000 and stock issued
for cash upon exercise of options of $1,004,000. Financing activities for
fiscal 2003 consist of repayment of borrowings and financing costs of $983,000
and stock issued for cash upon exercise of options of $529,000.
Fiscal 2004 - Acquisitions
--------------------------
On September 19, 2003, the Company completed an acquisition of certain
producing and drilling prospects in Colorado and Wyoming from Davis, ("Davis")
pursuant to the terms of a Purchase and Sale Agreement effective as of August
1, 2003. The total consideration paid for these properties was 1,000,000
shares of our common stock and $8 million, of which $2 million was paid in
cash and $6 million in the form of a short-term promissory note payable on
October 3, 2003. The shares issued were recorded at a price of $5.15, a five
day coverage surrounding the announcement of the transaction. The Company
recorded an upward purchase price adjustment of approximately $220,000 which
reflects the operating and acquisition related costs in excess of net revenue
from the effective date of August 1, 2003 through the closing date of
September 19, 2003. The total acquisition cost of $13,370,000 was allocated
between proved developed producing of $5,220,000 and proved undeveloped of
$8,150,000 based on preliminary information.
We will also be obligated to issue additional shares of common stock to
Davis in the event that it is determined that valid drillable prospects for
the discovery and production of hydrocarbons on certain leases, or land pooled
therewith, meet certain requirements, including a determination that there are
at least 1,000,000 barrels of recoverable oil or six billion cubic feet of
recoverable gas, or a combination thereof, in the prospect. These prospects
are referred to as "Bonus Prospects." Davis will receive up to 190,000 (not
more than $950,000 worth of stock) shares for each Bonus Prospect. No more
than 1,900,000 shares will be issued to Davis under this provision, regardless
of how many barrels of oil equivalent may be found. Davis also has the option
to elect to take assignment of up to a 50% working interest in each well
drilled on any prospect within the acquired properties after payout, on a
well-by-well basis.
24
On December 10, 2003, we completed an acquisition of certain production
and acreage located primarily in Eland and Stadium fields of Stark County,
North Dakota, from Sovereign Holdings, LLC, a privately - held Colorado
limited liability company ("Sovereign"), pursuant to the terms of a Purchase
and Sale Agreement effective as of December 1, 2003. The total consideration
paid for these properties was 773,500 shares of our common stock. The shares
issued were recorded at a price of $5.58, a five day average surrounding the
closing of the transaction. We recorded an downward purchase price adjustment
of approximately $84,000 which reflects the operating and acquisition related
costs in excess of net revenue from the effective date of December 1, 2003
through the closing date of December 5, 2003. The total acquisition cost of
$4,233,000 was allocated to proved developed producing properties.
Fiscal 2004 - Discontinued Operations
-------------------------------------
On December 5, 2003, We completed the sale of certain properties located
in Texas to Sovereign for cash consideration of $2,600,000 with an effective
date of January 1, 2004 and resulted in a loss of sale of oil and gas
properties of $28,000. In accordance with SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the results of operations and
loss on sale of these properties have been reflected as discontinued
operations. Revenues from the sale of these oil and properties was
approximately $292,000 and $550,000 for the three and six months ended
December 31, 2003 and $283,000 and $496,000 for the three and six months ended
December 31, 2002.
Fiscal 2004 Property Expenditures
---------------------------------
During the six months ended December 31, 2003, we've spent approximately
$8,000,000 in acquisition costs and an additional $6,690,000 on development of
our oil and gas properties. We estimate our capital expenditures for onshore
properties to range from $5 million to $15 million depending on drill rig
availability and success of drilling programs for the remainder of fiscal
2004. We anticipate that we will drill one to two developmental wells from
the Point Arguello Unit platforms to the Rocky Point structure during fiscal
2004. Each well will cost approximately $10 million ($670,000 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.
Options
-------
We received the proceeds from the exercise of options to purchase shares
of our common stock of $1,004,000 and $975,000 during the six months ended
December 31, 2003 and year ended June 30, 2003, respectively.
Credit Facility
---------------
On December 30, 2003, the Company amended and restated its credit
facility. The new $50 million facility with Bank of Oklahoma, U.S. Bank
National Association and Hibernia National Bank (the "Banks") has an available
borrowing base of $32.85 million. The facility has a variable interest rate
component of LIBOR +1.75% to 2.85% and/or prime +.5%/-.5% based on the total
debt outstanding and a monthly commitment reduction of $350,000. The Company
paid a $107,000 commitment fee in aggregate to the Banks. This fee was
25
recorded as a deferred financing fee and will be amortized over the life of
the loan which matures on December 31, 2006 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 and the oil and gas properties purchased on December 10, 2003.
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 December 31,
2003, the Company was in compliance with its quarterly debt covenants and
restrictions, as amended.
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 an exhibit to this report.
As of December 31, 2003, we had outstanding borrowings of approximately
$31,472,000 and letters of credit for Operator's Bonds outstanding of
$650,000.
Results of Operations for the Three and Six Months Ended December 31, 2003
Compared to the Three and Six Months Ended December 31, 2002
- --------------------------------------------------------------------------
Net Earnings (Loss). Our net income for the three and six months ended
December 31, 2003 were $652,000 and $2,016,000 compared to a net income of
$428,000 and $545,000 for the three and six months ended December 31, 2002.
The results for the three and six months ended December 31, 2003 and 2002 were
effected by the items described in detail below.
Revenue. Total revenues from continuing operations for the three and six
months ended December 31, 2003 were $8,006,000 and $15,192,000 compared to
$5,421,000 and $10,642,000 for the three and six months ended December 31,
2002. Oil and gas sales from continuing operations for the six months ended
December 31, 2003 were $8,074,000 and $15,572,000 compared to $5,808,000 and
$11,062,000 for the three and six months ended December 31, 2002. The increase
in oil and gas sales during the three and six months ended December 31, 2003
resulted from the acquisitions completed during fiscal 2004 and an increase in
oil and gas prices.
26
Production volumes and average prices received for the six months ended
December 31, 2003 and 2002 are as follows:
Three Months Ended
December 31,
2003 2002
Onshore Offshore Onshore Offshore
------- -------- ------- --------
Production:
Oil (barrels) 127,000 48,000 53,000 60,000
Gas (Mcf) 722,000 - 729,000 -
Discontinued Operations Production:
Oil (barrels) 9,000 - 9,000 -
Gas (Mcf) 10,000 - 10,000 -
Average Price from continuing operations:
Oil (per barrel) $29.91 $19.94 $27.56 $19.23
Gas (per Mcf) $ 4.60 $ - $ 4.38 $ -
Hedge effect:
(Per barrel equivalent) $(0.27) - $(2.09) -
Production volumes and average prices received for the six months ended
December 31, 2003 and 2002 are as follows:
Six Months Ended
December 31,
2003 2002
Onshore Offshore Onshore Offshore
------- -------- ------- --------
Production:
Oil (barrels) 230,000 96,000 109,000 122,000
Gas (Mcf) 1,452,000 - 1,527,000 -
Discontinued Operations
Production:
Oil (barrels) 16,000 - 17,000 -
Gas (Mcf) 21,000 - 13,000 -
Average Price from continuing
operations:
Oil (per barrel) $29.54 $19.98 $26.66 $19.66
Gas (per Mcf) $ 4.72 $ - $ 3.77 $ -
Hedge effect:
(Per barrel equivalent) $(0.81) - $(1.16) -
Lease Operating Expenses. Lease operating expenses from continuing
operations for the three and six months ended December 31, 2003 were
$2,341,000 and $4,550,000 compared to $2,303,000 and $4,273,000 for the three
and six months ended December 31, 2002. Lease operating expense increased
slightly compared to fiscal 2002 and first quarter fiscal 2004 as a result of
the JAED and Davis acquisitions completed during fourth quarter fiscal 2003.
On a per barrel ("Bbl") equivalent basis, production expenses and taxes were
$6.57 and $6.37 for onshore properties and $14.93 and $16.08 for offshore
properties during the three and six months ended December 31, 2003 compared to
$8.12 and $7.06 for onshore properties and $13.33 and $14.00 for offshore
properties for the three and six months ended December 31, 2002. Onshore
costs per equivalent Bbl decreased as operating cost from our recent
acquisitions in Colorado, Kansas and North Dakota are much lower than our
property base.
27
The unit operator has received approval to drill the east half of lease
451 of our Rocky Point unit and we anticipate that the first well will be
drilled in April 2004. If successful, the increase in production from the
Rocky Point production should lower per Bbl equivalent costs for the offshore
properties.
Depreciation and Depletion Expense. Depreciation and depletion expense
for the three and six months ended December 31, 2003 was $2,306,000 and
$3,948,000 compared to $1,101,000 and $2,706,000 for the three and six months
ended December 31, 2002. On a per Bbl equivalent basis, the depletion rate
was $8.61 and $7.58 for onshore properties and $2.46 and $3.06 for offshore
properties during the three and six months ended December 31, 2003 compared to
$4.28 and $5.72 for onshore properties and $5.05 and $4.95 for offshore
properties for the three and six months ended December 31, 2002. The increase
in depletion expense can be attributed to the Davis and Sovereign Acquisitions
completed during fiscal 2004. The major portion of the production from both
of these property acquisitions will be produced in the first few years.
Exploration Expenses and Dry Hole Expenses. Exploration expenses consist
of geological and geophysical costs and lease rentals. Exploration expenses
were $138,000 and $268,000 for the three and six months ended December 31,
2003 compared to $40,000 and $47,000 for the three and six months ended
December 31, 2002. Exploration costs during the quarter ended December 31,
2003 included seismic costs relating to the Davis acquisition which closed on
September 19, 2003.
Dry Hole Costs. The Company incurred dry hole costs of $177,000 during
the quarter ended December 31, 2003 relating to a non-operated property in
Richmond County, Montana.
Professional Fees. Professional fees for the three and six months ended
December 31, 2003 were $308,000 and $612,000 compared to $142,000 and $319,000
for the three and six months ended December 31, 2002. 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 six months ended December 31, 2003 were $1,528,000 and
$2,667,000 compared to $871,000 and $1,734,000 for the three and six months
ended December 31, 2002. The increase in general and administrative expenses
is primarily attributed to the increase in technical staff and increased fees
relating to our listing on the NASDAQ national market.
Interest and Financing Costs. Interest and financing costs for the three
and six months ended December 31, 2003 were $576,000 and $1,085,000 compared
to $432,000 and $940,000 for the three and six months ended December 31, 2002.
Interest expense stayed consistent as the increase in long term debt was
offset by a reduction in interest rates.
Income Taxes
- ------------
The Company recognized no tax expense in 2004 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
December 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.
28
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 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 $35,945,000 of variable rate
debt obligations at December 31, 2003. The annual effect of a one percent
change in interest rates would be approximately $359,000. The interest rate
on these variable rate debt obligations approximates current market rates as
of December 31, 2003.
Item 4. Controls and Procedures
As of December 31, 2003, under the supervision and with the participation
of the Company's Chief Executive Officer and the Chief Financial Officer,
management has evaluated the effectiveness of the design and operation of the
Company's disclosure controls and procedures. Based on that evaluation, the
Chief Executive Officer and the Chief Financial Officer concluded that the
Company's disclosure controls and procedures were effective as of December 31,
2003. There were no changes in internal control over financial reporting that
occurred during the fiscal quarter covered by this report that have materially
affected, or are reasonably likely to affect, the Company's internal control
over financial reporting.
29
PART II - OTHER INFORMATION
Item 1. 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.
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.
Although the computation of the various amounts that we would be required to
pay to landowners and other owners of royalties and similar interests is
dependent upon facts and circumstances that are not yet known, it is possible
that they may be as much as twenty percent of any proceeds that we might
ultimately obtain.
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 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities.
During the quarter ended December 31, 2003, we issued securities that
were not registered under the Securities Act of 1933 as follows:
On December 10, 2003, we issued a total of 773,500 shares of our common
stock to Sovereign Holdings, LLC, Conway J. Schatz and Goldline Creek LLC in
connection with the acquisition of certain production primarily located in
Eland and Stadium Fields in Stark County, North Dakota.
In connection with this transaction we relied on the exemption provided
by Section 4(2) of the Securities Act of 1933. We reasonably believe that all
of the investors are "Accredited Investors" as such term is defined in Rule
501 of Regulation D promulgated under the Securities Act of 1933 at the time
the transactions occurred. The investors acquired the shares for investment
purposes. Restrictive legends were placed on the certificates issued to the
investors, and stop transfer orders were given to our transfer agent.
30
Item 3. Defaults Upon Senior Securities. None.
Item 4. Submission of Matters to a Vote of Security Holders.
The 2003 Annual Meeting of our shareholders was held on December 1, 2003.
At the Annual Meeting the following persons, constituting the entire
board of directors, were elected as directors of the Company to serve until
the next annual meeting:
Abstentions and
Name For Against Broker Non-Votes
---- --- ------- ----------------
Aleron H. Larson, Jr. 19,148,504 52,233 14,529
Roger A. Parker 19,165,550 37,187 12,529
Jerrie F. Eckelberger 19,088,588 39,100 87,578
James B. Wallace 19,095,482 34,390 85,394
James L. Castle II 18,713,932 396,272 105,062
Russell S. Lewis 19,165,891 35,800 13,575
John P. Keller 19,167,137 34,600 13,529
The appointment of KPMG, LLP as our auditors for the year ended June 30,
2004, was ratified with 19,154,935 affirmative votes, 49,601 negative votes,
and 10,730 abstentions.
Item 5. Other Information. None.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits are as follows:
10.1 Amended and Restated Credit Agreement dated December 30, 2003,
by and among Delta Petroleum Corporation, Delta Exploration
Company, Inc., Piper Petroleum Company and Bank of Oklahoma,
N.A.
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
(b) Reports on Form 8-K. During the quarter ended December 31, 2003,
Delta filed Reports on Form 8-K as follows:
1. Report on Form 8-K dated November 6, 2003 reporting information
under Item 12 filed on November 10, 2003.
2. Report on Form 8-K/A dated September 19, 2003, reporting
information under Item 7 filed on December 2, 2003.
3. Report on Form 8-K dated December 9, 2003, reporting information
under Item 5 filed on December 19, 2003.
31
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this Report to be signed
on its behalf by the undersigned, thereunto duly authorized.
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
Date: February 3, 2004