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, 2004
[ ] 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___
32,376,000 shares of common stock $.01 par value were outstanding as of May 4,
2004.
FORM 10-Q
3rd QTR.
FY 2004
INDEX
PART I FINANCIAL INFORMATION
PAGE NO.
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets - March 31, 2004
(unaudited) and June 30, 2003 ........................... 3
Consolidated Statements of Operations - Three and
Nine Months Ended March 31, 2004 and 2003
(unaudited) ............................................. 4-5
Consolidated Statement of Stockholders' Equity
and Comprehensive Income (loss) - Year Ended June 30,
2003 and Nine Months Ended March 31, 2004
(unaudited) ............................................. 6
Consolidated Statements of Cash Flows -
Nine Months Ended March 31, 2004 and 2003
(unaudited) ............................................. 7
Notes to Consolidated Financial Statements
(unaudited) ............................................. 8-19
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations ..................... 20-30
Item 3. Quantitative and Qualitative Disclosures About
Market Risk ............................................. 30
Item 4. Controls and Procedures ................................. 30
PART II OTHER INFORMATION
Item 1. Legal Proceedings ....................................... 31
Item 2. Changes in Securities, Use of Proceeds and
Issuer Purchases of Equity Securities ................... 31
Item 3. Defaults upon Senior Securities ......................... 32
Item 4. Submission of Matters to a Vote of
Security Holders ........................................ 32
Item 5. Other Information ...................................... 32
Item 6. Exhibits and Reports on Form 8-K ........................ 32
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
March 31, June 30,
2004 2003
------------ ------------
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 28,440,000 $ 2,271,000
Marketable securities available for sale 912,000 662,000
Trade accounts receivable, net of
allowance for doubtful accounts of
$50,000 at March 31, 2004 and June 30, 2003 5,842,000 4,410,000
Prepaid assets 1,214,000 764,000
Inventory 1,169,000 -
Other current assets 358,000 560,000
------------ ------------
Total current assets 37,935,000 8,667,000
------------ ------------
Property and Equipment:
Oil and gas properties, successful efforts
method of accounting 118,108,000 90,151,000
Drilling and trucking equipment 6,572,000 -
Other 936,000 336,000
------------ ------------
Total property and equipment 125,616,000 90,487,000
Less accumulated depreciation and depletion (18,643,000) (12,669,000)
------------ ------------
Net property and equipment 106,973,000 77,818,000
------------ ------------
Long term assets:
Investment in LNG project 1,022,000 -
Deferred financing costs 95,000 117,000
Partnership net assets 208,000 245,000
------------ ------------
Total long term assets 1,325,000 362,000
$146,233,000 $ 86,847,000
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current portion of long-term debt $ 4,143,000 $ 10,039,000
Accounts payable 11,574,000 3,604,000
Derivative instruments 61,000 468,000
Current foreign tax payable 703,000 703,000
Other accrued liabilities 934,000 1,087,000
------------ ------------
Total current liabilities 17,415,000 15,901,000
------------ ------------
Long-term Liabilities:
Bank debt, net 27,050,000 22,175,000
Asset retirement obligation 975,000 868,000
Other debt, net 66,000 -
------------ ------------
Total long-term liabilities 28,091,000 23,043,000
Minority Interest 3,286,000 -
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 30,578,000
shares at March 31, 2004 and 23,286,000
at June 30, 2003 306,000 233,000
Additional paid-in capital 119,980,000 75,642,000
Accumulated other comprehensive loss 281,000 (376,000)
Accumulated deficit (23,126,000) (27,596,000)
------------ ------------
Total stockholders' equity 97,441,000 47,903,000
------------ ------------
Commitments $146,233,000 $ 86,847,000
============ ============
See accompanying notes to consolidated financial statements.
3
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
March 31, March 31,
2004 2003
------------ ------------
Revenue:
Oil and gas sales $ 10,628,000 $ 6,817,000
Realized loss on derivative instruments,
net (286,000) (971,000)
------------ ------------
Total revenue 10,342,000 5,846,000
Operating expenses:
Lease operating expense 2,506,000 2,275,000
Depreciation and depletion 3,085,000 1,300,000
Exploration expense 1,698,000 83,000
Dry hole costs 210,000 89,000
Professional fees 308,000 187,000
General and administrative (includes
stock compensation expense of $87,000 and
$36,000 for the three months ended
March 31, 2004 and 2003, respectively) 1,722,000 946,000
------------ ------------
Total operating expenses 9,529,000 4,880,000
------------ ------------
Income from continuing operations 813,000 966,000
Other income and (expense):
Other income 43,000 -
Interest and financing costs (373,000) (408,000)
------------ ------------
Total other expense (330,000) (408,000)
------------ ------------
Income before discontinued operations 483,000 558,000
Discontinued operations:
Income from operations of properties sold,
net 189,000 520,000
Gain on sale of properties 1,782,000 229,000
------------ ------------
Net income $ 2,454,000 $ 1,307,000
============ ============
Basic income per common share:
Income before discontinued operations $ 0.02 $ 0.02
Discontinued operations 0.07 0.04
------------ ------------
Net Income $ 0.09 $ 0.06
============ ============
Diluted income per common share:
Income before discontinued operations $ 0.01 $ 0.02
Discontinued operations 0.07 0.03
------------ ------------
Net Income $ 0.08 $ 0.05
============ ============
See accompanying notes to consolidated financial statements.
4
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Nine Months Ended
March 31, March 31,
2004 2003
------------ ------------
Revenue:
Oil and gas sales $ 25,401,000 $ 17,049,000
Realized loss on derivative instruments,
net (666,000) (1,391,000)
------------ ------------
Total revenue 24,735,000 15,658,000
Operating expenses:
Lease operating expense 6,896,000 6,392,000
Depreciation and depletion 6,877,000 3,887,000
Exploration expense 1,966,000 130,000
Dry hole costs 387,000 132,000
Professional fees 920,000 506,000
General and administrative (includes
stock compensation expense of $195,000 and
$82,000 for the nine months ended
March 31, 2004 and 2003, respectively) 4,443,000 2,737,000
------------ ------------
Total operating expenses 21,489,000 13,784,000
------------ ------------
Income from continuing operations 3,246,000 1,874,000
Other income and (expense):
Other income 78,000 21,000
Interest and financing costs (1,458,000) (1,348,000)
------------ ------------
Total other expense (1,380,000) (1,327,000)
------------ ------------
Income before discontinued operations and
cumulative effect on change in accounting
principle 1,866,000 547,000
Discontinued operations:
Income from operations of properties sold,
net 850,000 1,096,000
Gain on sale of properties 1,754,000 229,000
------------ ------------
Income before cumulative effect of
change in accounting principle 4,470,000 1,872,000
Cumulative effect of change in accounting
principle - (20,000)
------------ ------------
Net income $ 4,470,000 $ 1,852,000
============ ============
Basic income per common share:
Income before discontinued operations
and cumulative effect of change in
accounting principle $ 0.07 $ 0.02
Discontinued operations 0.11 0.06
------------ ------------
Income before cumulative effect of
change in acounting principle 0.18 0.08
Cumulative effect of change in
accounting principle - - *
------------ ------------
Net income $ 0.18 $ 0.08
============ ============
Diluted income per common share:
Income before discontinued operations and
cumulative effect on change in accounting
principle $ 0.06 $ 0.02
Discontinued operations 0.10 0.05
------------ ------------
Income before cumulative effect of
change in accounting principle 0.16 0.07
Cumulative effect of change in accounting
principle - - *
------------ ------------
Net income $ 0.16 $ 0.07
============ ============
* 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
Year Ended June 30, 2003 and Nine Months Ended March 31, 2004
Accumulated
other com-
Common Stock Additional Put Option prehensive
------------------- paid-in on income Comprehensive Accumulated
Shares Amount capital Delta stock (loss) income (loss) deficit Total
---------- -------- ----------- ----------- ------------- ------------- ------------ -----------
Balance, July 1,
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
gain, net of tax
Change in fair value
of derivative hedging
instruments - - - - (468,000) (468,000) - (468,000)
Unrealized gain on
equity securities,
net - - - - 177,000 177,000 - 177,000
-------------
Comprehensive income - - - - - 966,000
=============
Stock options granted
as compensation 124,000 - - - 124,000
Put option on Delta
stock - - (2,886,000) 2,886,000 -
Shares issued for
oil and gas
properties 200,000 2,000 920,000 - - - 922,000
Shares issued for
cash upon exercis
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 - - - - - 4,470,000 4,470,000 4,470,000
-------------
Other comprehensive
gain, net of tax
Change in fair
value of derivative
hedging instruments - - - - 407,000 407,000 - 250,000
Unrealized gain on
equity securities, net - - - - 250,000 250,000 - 407,000
-------------
Comprehensive income - - - - - 5,127,000
=============
Stock options granted
as compensation 195,000 - - - 195,000
Shares issued for cash,
net 4,000,000 40,000 29,650,000 - - - 29,690,000
Shares issued for
oil and gas
properties 1,985,000 20,000 11,195,000 - - - 11,215,000
Shares issued for
cash upon exercise
of options 1,307,000 13,000 3,298,000 - - - 3,311,000
---------- -------- ----------- ----------- ------------- ------------ -----------
Balance, March 31,
2004 30,578,000 $306,000 119,980,000 - 281,000 (23,126,000) $97,441,000
========== ======== =========== =========== ============= ============ ===========
See accompanying notes to consolidated financial statements.
6
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
March 31, March 31,
2004 2003
------------ ------------
Cash flows operating activities:
Net income $ 4,470,000 $ 1,852,000
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation and depletion 6,829,000 3,866,000
Depreciation and depletion -
discontinued operations 329,000 418,000
Accretion of abandonment obligation 48,000 21,000
Stock compensation expense 195,000 82,000
Amortization of financing costs 269,000 341,000
Gain on sale of oil and gas properties (1,754,000) (229,000)
Cumulative effect of change in
accounting principle - 20,000
Net changes in operating assets and
operating liabilities:
Increase in trade accounts receivable (1,432,000) (1,145,000)
(Increase) decrease in prepaid assets (450,000) 48,000
Increase in inventory (1,169,000) -
(Increase) decrease in other current assets 175,000 (80,000)
Increase in accounts payable trade 1,879,000 42,000
Increase (decrease) in other accrued
liabilities (153,000) 147,000
------------ ------------
Net cash provided by operating activities $ 9,236,000 $ 5,383,000
operating activities ------------ ------------
Cash flows from investing activities:
Capital and exploration expenditures, net (24,835,000) (4,956,000)
Proceeds from sales of oil and gas
properties 11,013,000 725,000
Payment on investment transaction (772,000) -
Decrease in long term assets 37,000 117,000
------------ ------------
Net cash used in investing activities (14,557,000) (4,114,000)
investing activities ------------ ------------
Cash flows from financing activities:
Stock issued for cash upon exercise of
options 3,312,000 780,000
Stock issued for cash, net 29,690,000 -
Proceeds from borrowings 14,204,000 -
Payment of financing fees (220,000) -
Repayment of borrowings (15,496,000) (1,359,000)
------------ ------------
Net cash provided by (used in) financing
activities 31,490,000 (579,000)
------------ ------------
Net increase in cash and cash equivalents 26,169,000 690,000
------------ ------------
Cash at beginning of period 2,271,000 1,024,000
------------ ------------
Cash at end of period $ 28,440,000 $ 1,714,000
============ ============
Supplemental cash flow information -
Cash paid for interest and financing
costs $ 1,256,000 $ 952,000
============ ============
Common stock issued for the purchase of
oil and gas properties $ 11,215,000 $ 922,000
============ ============
See accompanying notes to consolidated financial statements.
7
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Nine Months Ended March 31, 2004 and 2003
(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, oil and
gas properties, income taxes, derivatives, asset retirement obligation,
contingencies and litigation. Actual results could differ from these
estimates.
(2) Recently Issued or Proposed Accounting Standards and Pronouncements
The Company has been made aware that an issue has arisen within the
industry regarding the application of provisions of SFAS No. 142, "Goodwill
and Other Intangible Assets" 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, the Company and other
oil and gas companies have included the cost of these oil and gas leasehold
interests as part of oil and gas properties. Also under consideration is
whether SFAS No. 142 requires registrants to provide the additional
disclosures prescribed by SFAS No. 142 for intangible assets for costs
associated with mineral rights.
8
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(Unaudited)
- -----------------------------------------------------------------------------
(2) Recently Issued or Proposed Accounting Standards and Pronouncements,
Continued
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:
March 31, June 30,
2004 2003
----------- -----------
INTANGIBLE ASSETS:
Proved leasehold acquisition costs $62,223,000 $55,441,000
Unproved leasehold acquisition costs 32,651,000 23,689,000
----------- -----------
Total leasehold acquisition costs 94,874,000 79,130,000
Less: Accumulated depletion 13,559,000 10,858,000
----------- -----------
Net leasehold acquisition costs $81,315,000 $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.
(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
-------- ----------- ------------
March 31, 2004
Bion Environmental
Technologies, Inc. $152,000 $(140,000) $ 12,000
Tipperary Oil & Gas Company 418,000 482,000 900,000
-------- --------- --------
$570,000 $ 342,000 $912,000
======== ========= ========
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
======== ========= ========
9
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(Unaudited)
- -----------------------------------------------------------------------------
(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 $10,782,000, at March 31, 2004. 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, 2004
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 the 1999 lease suspension requests under a 1990 amendment to the
Coastal Zone Management Act. In the event that there is some future adverse
ruling under the Coastal Zone Management Act that the Company decides not to
appeal or that the Company appeals 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 the
Company's interests in the leases to become impaired, and the Company 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 the Company's 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 (the "South Tongue Prospect") and
Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually
(collectively, "Davis"), pursuant to the terms of a Purchase and Sale
Agreement effective as of August 1, 2003. The total consideration paid for
these properties was 1,000,000 shares of the Company's common stock and
$8,000,000, of which $2,000,000 was paid in cash and $6,000,000 in the form of
a short-term promissory note payable that was paid on October 3, 2003. The
shares issued were recorded at a price of $5.15 per share, a five day average
surrounding the announcement of the transaction. The Company recorded an
upward purchase price adjustment of approximately $220,000 which reflects the
operating and acquisition related costs in excess of net revenue from the
effective date of August 1, 2003 through the closing date of September 19,
2003. The total acquisition cost of $13,380,000 was allocated between proved
developed producing of $5,220,000 and unproved undeveloped of $8,160,000 based
on preliminary information.
10
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(Unaudited)
- -----------------------------------------------------------------------------
(4) Oil and Gas Properties, Continued
On April 22, 2004, subsequent to the quarter end, the Company amended its
agreement with Davis to, among other things, add certain oil and gas leases
located in Colorado known as the "North Tongue Prospect," decrease the amount
of Davis's reversionary working interest after payout in the properties
acquired under the initial agreement from 50% to 42.5%, change the definition
of payout, change certain drilling obligations and modify the Company's
obligation to issue additional shares of stock to Davis upon the designation
of Bonus Prospects. The initial consideration required to be paid to Davis
upon execution of the Amended Agreement was 1,525,000 shares of the Company's
common stock. The Company has agreed to file a registration statement with
the Securities and Exchange Commission to register the re-sale of these shares
by Davis and to pay all of the expenses associated with such registration.
The Company is also obligated to acquire additional leases, obtain seismic
surveys, drill wells and make certain other expenditures under the amended
agreement. The amount of the purchase price was the result of arms-length
negotiations between the parties.
The amended agreement eliminates the Company's obligation to issue shares
for Bonus Prospects that existed under the initial agreement with respect to
the South Tongue Prospect, but it added a new obligation to issue additional
shares for Bonus Prospects that are designated with respect to the North
Tongue Prospect. With regard to the North Tongue Prospect only, for any
prospect that is identified at any time after drilling, coring, testing and
logging to contain in combination from specified formations at least one
million barrels of recoverable oil or six billion cubic feet of recoverable
gas or a combination of oil or gas equal to or exceeding one million barrels
of oil equivalent using a six million cubic feet to one barrel gas-to-oil
ratio, as determined by independent engineers, then such acreage is required
to be designated as a "Bonus Prospect."
Upon designation of a Bonus Prospect, the Company is required to issue to
Davis as additional purchase price, up to 190,000 shares of the Company's
common stock, or such lesser amount so that the value of such stock based upon
the average closing price of the stock for the immediately preceding 30-day
period may equal but does not exceed $950,000, for each Bonus Prospect (a
"Bonus"). This requirement applies only to the North Tongue Prospect and is
limited to a maximum of five Bonus Prospects. No Bonus or additional shares
are payable for prospects located on the South Tongue Prospect, regardless of
potential or ultimate production. The Company is obligated to file additional
registration statements at the Company's expense covering the re-sale of each
issuance of shares for each Bonus Prospect designation.
11
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(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 Nine Months Ended
March 31, March 31,
2004 2003 2004 2003
---------- ---------- ----------- -----------
Oil and gas sales $10,628,000 $ 8,480,000 $26,458,000 $19,269,000
Net income $ 2,454,000 $ 1,840,000 $ 4,809,000 $ 2,569,000
Net income per common
share:
Basic $ .08 $ .08 $ .16 $ .11
Diluted $ .08 $ .08 $ .16 $ .11
The above unaudited adjusted Pro Forma Consolidated Statements of
Operations, 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 the Company's
common stock. The shares issued were recorded at a price of $5.58, a five day
average surrounding the closing of the transaction. The Company recorded a
downward purchase price adjustment of approximately $84,000 which reflects the
operating and acquisition related costs in excess of net revenue from the
effective date of December 1, 2003 through the closing date of December 5,
2003. The total acquisition cost of $4,233,000 was allocated to proved
developed producing properties.
On February 24, 2004, the Company acquired certain properties in Texas
from Labyrinth Enterprises, LLC, an unrelated entity for $1,320,000 in cash
and 185,000 shares of the Company's common stock valued at $1,619,000 based on
a five day average surrounding the closing of the transaction.
On February 26, 2004, the Company acquired approximately 135,000
leasehold acres in the Columbia River Basin project in eastern Washington from
an unrelated entity for $1,357,000 in cash. The Company will become the
operator once drilling begins on this acreage. Subsequent to the quarter end,
the Company purchased approximately 23,000 additional net acreage in this
project through State and Federal lease sales.
In March 2004, the Company purchased a 50% interest in Big Dog Drilling
Company, LLC ("BDDC") for an initial investment of approximately $3,000,000.
The remaining interest is owned 25% by Davis described above and 25% by an
unrelated individual. BDDC's primary assets include two drilling rigs rated
at drilling depths of up to 10,000 feet and certain additional drilling
equipment.
12
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(Unaudited)
- -----------------------------------------------------------------------------
(4) Oil and Gas Properties, Continued
Also in March 2004, the Company purchased a 50% interest in Shark
Trucking Company, LLC ("STC") for an initial investment of approximately
$276,000. STC has a similar ownership structure to that of BDDC. STC's
primary assets include the ownership of trucking equipment used for the
mobilization of drilling rigs and equipment.
Both BDDC and STC meet the criteria for control and require consolidation
of the entities. Neither entity has commenced operations as of March 31,
2004.
The drilling rigs and trucking company will be used primarily for
drilling activities on Delta's properties. Increasing drilling rig rates,
periodic lack of availability of drilling rigs and increased drilling by Delta
were contributing factors to this venture.
During the current fiscal year, the Company agreed to invest an aggregate
of $1,000,000 for a 6.25% interest as a member of an unaffiliated Delaware
limited liability company that is currently in the process of attempting to
obtain the rights to own and operate a liquid natural gas facility from an
existing platform located offshore California. If the limited liability
company is successful in obtaining these rights, it intends to engage in the
business of accepting and vaporizing liquid natural gas delivered by liquid
natural gas tankers, transporting the vaporized liquid natural gas through
proprietary gas pipelines and selling the vaporized natural gas to third 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. The Company has accounted for its investment at cost.
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. The
effective date of the transaction is January 1, 2004 and it 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 attributed to the sale of
these oil and gas properties were approximately $0 and $537,000 for the three
and nine months ended March 31, 2004 and $372,000 and $868,000 for the three
and nine months ended March 31, 2003, respectively.
On March 31, 2004, the Company completed the sale of all of our
Pennsylvania properties to Castle Energy Corporation, a 25% shareholder of
Delta at March 31, 2004, for cash consideration of $8,000,000, which the
Company believes is fair value, with an effective date of January 1, 2004 and
resulted in a gain on sale of oil and gas properties of $1,782,000. In
accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of
13
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(Unaudited)
- -----------------------------------------------------------------------------
(4) Oil and Gas Properties, Continued
Long-Lived Assets," the results of operations and gain on sale of these
properties have been reflected as discontinued operations. Revenues from the
sale of these oil and properties was approximately $390,000 and $1,189,000 for
the three and nine months ended March 31, 2004 and $528,000 and $1,358,000 for
the three and nine months ended March 31, 2003.
(5) Long Term Debt
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"). Currently, the
Company has an available borrowing base of $37,000,000 with a current balance
outstanding of $30,922,000. 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 no current monthly commitment reduction. The loan matures on
December 31, 2006 and is collateralized by substantially all of Delta's oil
and gas properties. 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 the 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 the Company is notified by the Bank of Oklahoma, the
Company must make a mandatory prepayment of principal that is sufficient to
cause the Company's total outstanding indebtedness to not exceed the borrowing
base. The Company is required to meet quarterly debt covenants and
restrictions. At March 31, 2004, the Company was in compliance with its
quarterly debt covenants and restrictions.
Bank Debt
Kaiser Francis Oil Company - Debt
On December 1, 1999, the Company borrowed $8,000,000 at prime plus 1-1/2%
from Kaiser Francis Oil Company. The proceeds from this loan were used to pay
off existing debt and the balance of the Point Arguello Unit and New Mexico
acquisitions. During the third quarter of fiscal 2004, the loan was paid in
full.
Five Year Debt Maturity Schedule
Maturities of long-term debt for each of the five years following March
31, 2004 are as follows:
YEAR ENDING March 31,
2004................................ $ 4,143,000
2005................................ 27,071,000
2006................................ 22,000
2007................................ 23,000
-----------
$31,259,000
===========
14
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(Unaudited)
- -----------------------------------------------------------------------------
(6) Stockholders' Equity
Common Stock Issued for Cash
On February 19, 2004, the Company completed the sale of 4 million shares
of its common stock at a price of $8.00 per share in a private placement for
$29,690,000, net of $2,310,000 in offering costs.
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.
Had compensation cost for the Company's stock-based compensation plan
been determined using the fair value of the options at the grant date, the
Company's net income for the nine months ended March 31, 2004 and 2003 would
have been as follows:
March 31,
-----------------------------
2004 2003
---- ----
Net Income $ 4,470,000 $1,852,000
FAS 123 compensation effect (4,316,000)** (209,000)
----------- ----------
Net income after FAS 123
compensation effect $ 154,000 $1,643,000
=========== ==========
Income per common share: $ * $ .07
=========== ==========
*less than $.01 per common share
** 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.
The Company had approximately 4,807,000 options to purchase the Company's
common stock outstanding, with an average price of $3.91, at March 31, 2004.
The Company granted 353,000 options to non-officer employees during the nine
months ended March 31, 2004 and granted 175,000 options to non-officer
employees during the nine months ended March 31, 2003.
15
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(Unaudited)
- -----------------------------------------------------------------------------
(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, "Accounting for
Derivative Instruments and Hedging Activities" 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.
As of March 31, 2004, the Company recorded a derivative liability of
approximately $61,000 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 $286,000 and
$666,000 for the three and nine months ended March 31, 2004.
As of March 31, 2004, the Company had approximately 364,000 mcf of
natural gas subject to commodity price risk contracts for the remainder of
fiscal 2004. The fiscal 2004 contract has a weighted average floor price of
$4.50 per Mmbtu, with weighted average ceiling price of $5.45 per Mmbtu.
(8) 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, 2004 and 2003 are as follows:
Nine Months Ended Nine Months Ended
March 31, 2004 March 31, 2003
----------------- -----------------
Net Income $4,470,000 $1,852,000
Other comprehensive income (loss)
Change in fair value of derivative
hedging instruments 407,000 (691,000)
Unrealized gain (loss) on marketable
securities 250,000 (50,000)
---------- ----------
Other comprehensive income (loss) 657,000 (741,000)
Comprehensive income $5,127,000 $1,111,000
========== ==========
(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.
16
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended March 31, 2004 and 2003
(Unaudited)
- -----------------------------------------------------------------------------
(9) Income Taxes, Continued
The Company recognized no tax expense in the first nine 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 March 31, 2004, for which a valuation allowance has been
recorded, will be recognized in the financial statements when its realization
is more likely than not.
(10) Earnings Per Share
The following table sets forth the computation of basic and diluted
earnings per share:
Three Months Ended
March 31,
2004 2003
---- ----
Numerator:
Numerator for basic and diluted
earnings per share - income
available to common stockholders $ 2,454,000 $ 1,307,000
----------- -----------
Denominator:
Denominator for basic earnings
per share-weighted average shares
outstanding 27,731,000 22,952,000
Effect of dilutive securities-
stock options and warrants 2,665,000 2,956,000
----------- -----------
Denominator for diluted
earnings per common share 30,396,000 25,908,000
=========== ===========
Anti-dilutive securities outstanding 88,000 1,809,000
=========== ===========
Basic income per common share:
Income before discontinued operations $ .02 $ .02
Discontinued operations .07 .04
----------- -----------
Net Income $ .09 $ .06
=========== ===========
Diluted income per common share:
Income before discontinued operations $ .02 $ .02
Discontinued operations .06 .03
----------- -----------
Net Income $ .08 $ .05
=========== ===========
17
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2004 and 2003
- -----------------------------------------------------------------------------
(10) Earnings Per Share, Continued
Nine Months Ended
March 31,
2004 2003
---- ----
Numerator:
Numerator for basic and diluted
earnings per share - income
available to common stockholders $ 4,470,000 $ 1,852,000
----------- -----------
Denominator:
Denominator for basic earnings
per share-weighted average shares
outstanding 25,298,000 22,756,000
Effect of dilutive securities-
stock options and warrants 2,306,000 2,905,000
----------- -----------
Denominator for diluted
earnings per common share 27,604,000 25,661,000
=========== ===========
Anti-dilutive securities outstanding 88,000 1,860,000
=========== ===========
Basic income per common share:
Income before discontinued operations
and cumulative effect of change in
accounting principle $ .07 $ .02
Discontinued operations .11 .06
Income before cumulative effect of ----------- -----------
change in accounting principle .18 .08
Cumulative effect of change in - -*
accounting principle ----------- -----------
Net Income $ .18 $ .08
=========== ===========
Diluted income per common share:
Income before discontinued operations
and cumulative effect of change in
accounting principle $ .06 $ .02
Discontinued operations .10 .05
Income before cumulative effect of ----------- -----------
change in accounting principle .16 .07
Cumulative effect of change in - -*
accounting principle ----------- -----------
Net Income $ .16 $ .07
=========== ===========
* less than $.01 per common share
(11) Commitments
As of March 31, 2004, 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 through June 2004.
18
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Nine Months Ended March 31, 2004 and 2003
- -----------------------------------------------------------------------------
(12) Reclassification
Certain amounts in the 2003 financial statements have been reclassified
to conform to the 2004 financial statement presentation.
(13) Subsequent Events
On April 21, 2004, the Company acquired a fifty percent interest in
approximately 1,300 leasehold acres in the Midway Loop Project located in Polk
County, Texas from WillSource Enterprises, LLC for $340,000 and 31,250 shares
of the Company's common stock valued at approximately $289,000 based on a five
day average surrounding the acquisition. The Company will become the operator
once drilling begins on this acreage.
Also on April 21, 2004, the Company acquired a seventy five percent
interest in approximately 9,800 leasehold acres in the Divide Creek Extension
Project located in Mesa County, Colorado from Willsource Enterprises, LLC for
$90,000 in cash and 187,500 shares of the Company's common stock valued at
approximately $1,734,000 based on a five day average surrounding the
acquisition. The Company will become the operator once drilling begins on
this acreage.
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 Estimate
------------------------------------------
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
20
drilling operation can take considerable time to analyze and the determination
that commercial reserves have been discovered requires both judgment and
industry experience. Wells may be completed that are assumed to be productive
and actually deliver gas and oil in quantities insufficient to be economic,
which may result in the abandonment of the wells at a later date. Wells are
drilled that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly
account for the results. Delineation seismic incurred to select development
locations within an oil and gas field is typically considered a development
cost and capitalized, but often these seismic programs extend beyond the
reserve area considered proved and management must estimate the portion of the
seismic costs to expense. The evaluation of gas and oil leasehold acquisition
costs requires managerial judgment to estimate the fair value of these costs
with reference to drilling activity in a given area. Drilling activities in
an area by other companies may also effectively condemn leasehold positions.
The successful efforts method of accounting can have a significant impact
on the operational results reported when 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
21
properties to determine if the carrying amount is recoverable. If the
carrying amount exceeds the estimated undiscounted future cash flows, we will
adjust the carrying amount of the oil and gas properties to their fair value.
The factors used to determine fair value include, but are not limited to,
estimates of proved reserves, future commodity pricing, future production
estimates, anticipated capital expenditures, and a discount rate commensurate
with the risk associated with realizing the expected cash flows projected.
Given the complexities associated with gas and oil reserve estimates and
the history of price volatility in the gas and oil markets, events may arise
that would require the Company to record an impairment of the recorded book
values associated with gas and oil properties. The Company did not record an
impairment during the nine months ended March 31, 2004 and 2003.
Commodity Derivative Instruments and Hedging Activities
-------------------------------------------------------
We periodically enter into commodity derivative contracts and fixed-price
physical contracts to manage our exposure to oil and natural gas price
volatility. We primarily utilize future contracts, swaps or options, which
are generally placed with major financial institutions or with counterparties
of high credit quality that we believe are minimal credit risks. The oil and
natural gas reference prices of these commodity derivatives contracts are
based upon crude oil and natural gas futures, which have a high degree of
historical correlation with actual prices we receive.
On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." Under SFAS No. 133 all derivative
instruments are recorded on the balance sheet at fair value. Changes in the
derivative's fair value are recognized currently in earnings unless specific
hedge accounting criteria are met. For qualifying cash flow hedges, the gain
or loss on the derivative is deferred in accumulated other comprehensive
income (loss) to the extent the hedge is effective. For qualifying fair value
hedges, the gain or loss on the derivative is offset by related results of the
hedged item in the income statement. Gains and losses on hedging instruments
included in accumulated other comprehensive income (loss) are reclassified to
oil and natural gas sales revenue in the period that the related production is
delivered. Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at market value in
the consolidated balance sheet, and the associated unrealized gains and losses
are recorded as current expense or income in the consolidated statement of
operations. While such derivative contracts do not qualify for hedge
accounting, management believes these contracts can be utilized as an
effective component of commodity price risk management (CPRM) activities.
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
- ---------------
We have working capital of $20,520,000 at March 31, 2004 compared to a
working capital deficit of $7,234,000 at June 30, 2003. The increase in
working capital is primarily related to the private equity offering completed
in February for net proceeds of approximately $29,690,000.
Cash Provided by Operating Activities
- -------------------------------------
During the nine months ended March 31, 2004, we had cash provided by
operating activities of $9,236,000 compared to cash provided by operating
activities of $5,383,000 during the same period ended March 31, 2003. This
increase in operating activities is a result of the increase in oil and
natural gas sales relating to acquisitions completed during the last year as
discussed below.
Cash Used in Investing Activities
- ---------------------------------
During the nine months ended March 31, 2004, we had cash used in
investing activities of $14,557,000 compared to cash used in investing
activities of $4,114,000 during the same period ended March 31, 2003.
Investing activities for fiscal 2004 included $15,520,000 used toward the
numerous acquisitions, described below, completed during the nine months and
$9,315,000 for development activities offset by sales proceeds of $11,013,000.
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
$1,000,000 as a member of an unaffiliated Delaware limited liability company
that is currently in the process of attempting to obtain the rights to own and
operate a liquid natural gas facility from an existing platform located
offshore California. If the limited liability company is successful in
obtaining these rights, it intends to engage in the business of accepting and
vaporizing liquid natural gas delivered by liquid natural gas tankers,
transporting the vaporized liquid natural gas through proprietary gas
pipelines and selling the vaporized natural gas to third 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
23
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 nine months ended March 31, 2004, we had cash provided by
financing activities of $31,490,000 compared to cash used in financing
activities of $579,000 for the same period ended March 31, 2003. Financing
activities for fiscal 2004 consist of net proceeds of approximately 29,690,000
from a private equity offering completed in February, proceeds from borrowings
of $14,204,000, repayment of borrowings and financing costs of $15,496,000 and
stock issued for cash upon exercise of options of $3,312,000. Financing
activities for fiscal 2003 consist of repayment of borrowings and financing
costs of $1,359,000 and stock issued for cash upon exercise of options of
$780,000.
Fiscal 2004 - Acquisitions
- --------------------------
On September 19, 2003, we completed an acquisition of certain producing
and drilling prospects in Colorado (the "South Tongue Prospect") and Wyoming
from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively,
"Davis"), 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 $8,000,000, of which $2,000,000 was
paid in cash and $6,000,000 in the form of a short-term promissory note
payable that was paid on October 3, 2003. The shares issued were recorded at a
price of $5.15 per share, a five day average surrounding the announcement of
the transaction. We 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.
On April 22, 2004, subsequent to the quarter end, we amended our
agreement with Davis to, among other things, add certain oil and gas leases
located in Colorado known as the "North Tongue Prospect," decrease the amount
of Davis's reversionary working interest after payout in the properties
acquired under the initial agreement from 50% to 42.5%, change the definition
of payout, change certain drilling obligations and modify our obligation to
issue additional shares of stock to Davis upon the designation of Bonus
Prospects. The initial consideration required to be paid to Davis upon
execution of the Amended Agreement was 1,525,000 shares of our common stock.
We have agreed to file a registration statement with the Securities and
Exchange Commission to register the re-sale of these shares by Davis and to
pay all of the expenses associated with such registration. We are also
obligated to acquire additional leases, obtain seismic surveys, drill wells
and make certain other expenditures under the amended agreement. The amount
of the purchase price was the result of arms-length negotiations between the
parties.
The amended agreement eliminates our obligation to issue shares for
Bonus Prospects that existed under the initial agreement with respect to the
South Tongue Prospect, but it added a new obligation to issue additional
shares for Bonus Prospects that are designated with respect to the North
Tongue Prospect. With regard to the North Tongue Prospect only, for any
24
prospect that is identified at any time after drilling, coring, testing and
logging to contain in combination from specified formations at least one
million barrels of recoverable oil or six billion cubic feet of recoverable
gas or a combination of oil or gas equal to or exceeding one million barrels
of oil equivalent using a six million cubic feet to one barrel gas-to-oil
ratio, as determined by independent engineers, then such acreage is required
to be designated as a "Bonus Prospect."
Upon designation of a Bonus Prospect, we are required to issue to Davis
as additional purchase price, up to 190,000 shares of our common stock, or
such lesser amount so that the value of such stock based upon the average
closing price of the stock for the immediately preceding 30-day period may
equal but does not exceed $950,000, for each Bonus Prospect (a "Bonus"). This
requirement applies only to the North Tongue Prospect and is limited to a
maximum of five Bonus Prospects. No Bonus or additional shares are payable
for prospects located on the South Tongue Prospect, regardless of potential or
ultimate production. We are obligated to file additional registration
statements at our expense covering the re-sale of each issuance of shares for
each Bonus Prospect designation.
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.
On February 24, 2004, we acquired certain properties in Texas from
Labyrinth Enterprises, LLC, an unrelated entity for $1,320,000 in cash and
185,000 shares of our common stock valued at $1,619,000 based on a five day
average surrounding the closing of the transaction.
On February 26, 2004, we acquired approximately 135,000 leasehold acres
in the Columbia River Basin project in eastern Washington from an unrelated
entity for $1,357,000 in cash. The Company will become the operator once
drilling begins on this acreage. Subsequent to the quarter end, the Company
purchased approximately 23,000 additional net acreage in this project through
State and Federal lease sales.
In March 2004, we purchased a 50% interest in Big Dog Drilling Company,
LLC ("BDDC") for an initial investment of approximately $3,000,000. The
remaining interest is owned 25% by Davis described above and 25% by an
unrelated individual. BDDC's primary assets include two drilling rigs rated
at drilling depths of up to 10,000 feet and certain additional drilling
equipment.
Also in March 2004, we purchased a 50% interest in Shark Trucking
Company, LLC ("STC") for an initial investment of approximately $276,000. STC
has a similar ownership structure to that of BDDC. STC's primary assets
include the ownership of trucking equipment used for the mobilization of
drilling rigs and equipment.
Both BDDC and STC meet the criteria for control and require consolidation
for the entities. Neither entity has commended operations as of March 31,
2004.
25
The drilling rigs and trucking company will be used primarily for
drilling activities on our properties. Increasing drilling rig rates,
periodic lack of availability of drilling rigs and increased drilling by us
were contributing factors to this venture.
On April 21, 2004, we acquired a fifty percent interest in approximately
1,300 leasehold acres in the Midway Loop Project located in Polk County, Texas
from Willsource Enterprises, LLC for $340,000 and 31,250 shares of the
Company's common stock valued at approximately $289,000. We will become the
operator once drilling begins on this acreage.
Also on April 21, 2004,we acquired a seventy five percent interest in
approximately 9,800 leasehold acres in the Divide Creek Extension Project
located in Mesa County, Colorado from Willsource Enterprises, LLC for $90,000
in cash and 187,500 shares of the Company's common stock valued at
approximately $1,688,000. We will become the operator once drilling begins on
this acreage.
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. The effective
date of the transaction is January 1, 2004 and resulted in a loss on 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 attributed to the sale of these oil and
properties were approximately $0 and $537,000 for the three and nine months
ended March 31, 2004 and $372,000 and $868,000 for the three and nine months
ended March 31, 2003, respectively.
On March 31, 2004, we completed the sale of all of our Pennsylvania
properties to Castle Energy Corporation, a 25% shareholder of Delta at March
31, 2004, for cash consideration of $8,000,000, which the Company believes is
fair value, with an effective date of January 1, 2004 and resulted in a gain
on sale of oil and gas properties of $1,782,000. In accordance with SFAS No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the
results of operations and gain on sale of these properties have been reflected
as discontinued operations. Revenues from the sale of these oil and
properties was approximately $390,000 and $1,189,000 for the three and nine
months ended March 31, 2004 and $528,000 and $1,358,000 for the three and nine
months ended March 31, 2003.
Fiscal 2004 Property Expenditures
- ---------------------------------
During the nine months ended March 31, 2004, we incurred approximately
$26,735,000 in acquisition costs and an additional $9,315,000 on development
of our oil and gas properties. We estimate our capital expenditures for
development of onshore properties to range from $5,000,000 to $10,000,000
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 $10,000,000
($670,000 to our interest). We anticipate paying for all capital expenditures
out of cash on hand and 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.
26
Common Stock Issued for Cash
- ----------------------------
On February 19, 2004, we completed the sale of 4 million shares of our
common stock at a price of $8.00 per share in a private placement for
approximately $29,690,000, net of $2,310,000 in offering costs.
Options
- -------
We received proceeds from the exercise of options to purchase shares of
our common stock of $3,311,000 and $975,000 during the nine months ended March
31, 2004 and year ended June 30, 2003, respectively.
Credit Facility
- ---------------
On December 30, 2003, we amended and restated our credit facility. The
new $50 million facility with Bank of Oklahoma, U.S. Bank National Association
and Hibernia National Bank (the "Banks"). Currently we have an available
borrowing base of $37,000,000. 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 no current monthly commitment reduction. The loan
matures on December 31, 2006 and is collateralized by substantially all of
Delta's oil and gas properties. Our 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 the borrowing base, the total amount of the 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. We are required to
meet quarterly debt covenants and restrictions. At March 31, 2004, we were in
compliance with our quarterly debt covenants and restrictions.
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 March 31, 2004, we had outstanding borrowings of approximately
$30,922,000 and letters of credit for Operator's Bonds outstanding of
$550,000.
Results of Operations for the Three and Nine Months Ended March 31, 2004
Compared to the Three and Nine Months Ended March 31, 2003
- --------------------------------------------------------------------------
Net Earnings (Loss). Our net income for the three and nine months ended
March 31, 2004 were $2,454,000 and $4,470,000 compared to a net income of
$1,307,000 and $1,852,000 for the three and nine months ended March 31, 2003.
The results for the three and nine months ended March 31, 2004 and 2003 were
effected by the items described in detail below.
27
Revenue. Total revenues from continuing operations for the three and
nine months ended March 31, 2004 were $10,342,000 and $24,735,000 compared to
$5,846,000 and $15,658,000 for the three and nine months ended March 31, 2003.
Oil and gas sales from continuing operations for the nine months ended March
31, 2004 were $10,628,000 and $25,401,000 compared to $6,817,000 and
$17,049,000 for the three and nine months ended March 31, 2003. The increase
in oil and gas sales during the three and nine months ended March 31, 2004
resulted from the acquisitions completed during fiscal 2004 and an increase in
oil and gas prices.
Production volumes and average prices received for the three months ended
March 31, 2004 and 2003 are as follows:
Three Months Ended
March 31,
2004 2003
Onshore Offshore Onshore Offshore
------- -------- ------- --------
Production:
Oil (barrels) 166,000 42,000 53,000 53,000
Gas (Mcf) 709,000 - 642,000 -
Discontinued Operations Production:
Oil (barrels) - - 10,000 -
Gas (Mcf) 77,000 - 106,000 -
Average Price received from continuing operations:
Oil (per barrel) $33.98 $21.60 $32.52 $22.82
Gas (per Mcf) $ 5.75 $ - $ 6.05 $ -
Hedge effect:
(Per barrel equivalent) $(1.01) $(6.07)
Production volumes and average prices received for the nine months ended
March 31, 2004 and 2003 are as follows:
Nine Months Ended
March 31,
2004 2003
Onshore Offshore Onshore Offshore
------- -------- ------- --------
Production:
Oil (barrels) 396,000 138,000 162,000 175,000
Gas (Mcf) 1,991,000 - 1,948,000 -
Discontinued Operations
Production:
Oil (barrels) 16,000 - 27,000 -
Gas (Mcf) 268,000 - 340,000 -
Average Price received from continuing
operations:
Oil (per barrel) $31.43 $20.48 $28.58 $20.61
Gas (per Mcf) $ 5.09 $ - $ 4.52 $ -
Hedge effect:
(Per barrel equivalent) $(.92) $(2.86)
28
Lease Operating Expenses. Lease operating expenses from continuing
operations for the three and nine months ended March 31, 2004 were $2,506,000
and $6,896,000 compared to $2,275,000 and $6,392,000 for the three and nine
months ended March 31, 2003. Lease operating expense increased slightly
compared to fiscal 2003 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 $5.77 and
$6.23 for onshore properties and $20.65 and $17.09 for offshore properties
during the three and nine months ended March 31, 2004 compared to $9.34 and
$8.02 for onshore properties and $14.71 and $14.21 for offshore properties for
the three and nine months ended March 31, 2003. Onshore costs per equivalent
Bbl decreased as operating cost from our recent acquisitions in Colorado,
Kansas and North Dakota incur much lower cost than our previous property base.
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 May 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 nine months ended March 31, 2004 was $3,085,000 and
$6,877,000 compared to $1,300,000 and $3,887,000 for the three and nine months
ended March 31, 2003. On a per Bbl equivalent basis, the depletion rate was
$9.75 and $8.50 for onshore properties and $5.57 and $3.82 for offshore
properties during the three and nine months ended March 31, 2004 compared to
$6.45 and $6.15 for onshore properties and $4.81 and $4.90 for offshore
properties for the three and nine months ended March 31, 2003. The increase
in depletion expense can be attributed to the Davis and North Dakota
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 and as a result they have a high depletion rate.
Exploration Expenses. Exploration expenses consist of geological and
geophysical costs and lease rentals. Exploration expenses were $1,698,000 and
$1,966,000 for the three and nine months ended March 31, 2004 compared to
$83,000 and $130,000 for the three and nine months ended March 31, 2003.
Exploration costs during the quarter ended March 31, 2004 included an
extensive seismic program in Washington County. The Company has expanded its
seismic program based on initial results. The Company will continue to incur
seismic costs over the next few quarters.
Dry Hole Costs. The Company incurred dry hole costs of $387,000 during
the nine months ended March 31, 2004 relating to non-operated properties in
Richmond County, Montana and Renville County, North Dakota.
Professional Fees. Professional fees for the three and nine months ended
March 31, 2004 were $308,000 and $920,000 compared to $187,000 and $506,000
for the three and nine months ended March 31, 2003. Professional fees consist
of corporate, legal and accounting costs related to investor relations and
legal fees for representation in litigation, 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, 2004 were $1,722,000 and $4,443,000
compared to $946,000 and $2,737,000 for the three and nine months ended March
31, 2003. The increase in general and administrative expenses is primarily
attributed to the increase in technical staff expanded office facility and
increased fees relating to our listing on the NASDAQ National Market System.
29
Interest and Financing Costs. Interest and financing costs for the three
and nine months ended March 31, 2004 were $373,000 and $1,458,000 compared to
$408,000 and $1,348,000 for the three and nine months ended March 31, 2003.
Interest expense decreased with the reduction in interest rates and our recent
debt reduction during the quarter ended March 31, 2004.
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 2004 because
realization was not more likely than not. The remaining deferred tax asset at
March 31, 2004, for which a valuation allowance has been recorded, will be
recognized in the financial statements when its realization is more likely
than not, which continues to monitor.
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 $30,922,000 of variable rate
debt obligations at March 31, 2004. The annual effect of a one percent change
in interest rates would be approximately $309,000. The interest rate on these
variable rate debt obligations approximates current market rates as of March
31, 2004.
Item 4. Controls and Procedures
As of March 31, 2004, 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 March 31,
2004. 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. The Company will continue to monitor change to its
internal control procedures.
30
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 March 31, 2004, we issued securities that were
not registered under the Securities Act of 1933 as follows:
On February 19, 2004, we issued a total of 4,000,000 shares of our common
stock to 37 Accredited Investors in a private placement. The shares were sold
for $8.00 per share for an aggregate of $32,000,000. In connection with the
private placement we paid Sterne, Agee & Leach, Inc., the placement agent, a
commission of $2,240,000. In connection with this offering we relied on the
exemptions provided by Section 4(2) of the Securities Act of 1933 and Rule 506
of Regulation D promulgated under the Securities Act of 1933. We reasonably
believe that all of the investors are "Accredited Investors" as such term is
31
defined in Rule 501 of Regulation D at the time the offering occurred. The
investors acquired the shares for investment purposes. Restrictive legends
were placed on the certificates issued to the investors, and stop transfer
orders were given to our transfer agent. A Form D reporting the offering was
filed with the Securities and Exchange Commission.
On February 24, 2004, we issued a total of 185,000 shares of our common
stock to Labyrinth Enterprises, LLC in connection with the acquisition of
certain production primarily located in South Texas. 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 the investor is an
"Accredited Investor" as such term is defined in Rule 501 of Regulation D
promulgated under the Securities Act of 1933 at the time the transactions
occurred. The investor acquired the shares for investment purposes. A
restrictive legend was placed on the certificate issued to the investor, and
stop transfer orders were given to our transfer agent.
Item 3. Defaults Upon Senior Securities. None.
Item 4. Submission of Matters to a Vote of Security Holders.
Item 5. Other Information. None.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits are as follows:
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 March 31, 2004, Delta
filed Reports on Form 8-K as follows:
1. Report on Form 8-K dated February 4, 2004, reporting information
under Item 5, Item 7 and Item 12 filed on February 5, 2004.
2. Report on Form 8-K dated March 8, 2004, reporting information
under Item 5 filed on March 8, 2004.
32
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: May 10, 2004