PAR PACIFIC HOLDINGS, INC.
10-Ks and 10-Qs
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Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
| þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
| o | 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)
| Delaware | 84-1060803 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
| 370 17th Street, Suite 4300 | ||
| Denver, Colorado | 80202 | |
| (Address of principal executive offices) | (Zip Code) |
(303) 293-9133
(Registrant’s telephone number, including area code)
(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
þ
No
o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes
þ
No
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated
filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o |
Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act): Yes
o
No
þ
28,882,887 shares of common stock, $.01 par value per share, were outstanding as of August 1, 2011.
INDEX
The terms “Delta,” “Company,” “we,” “our,” and “us” refer to Delta Petroleum Corporation and its
consolidated entities unless the context suggests otherwise.
I
Table of Contents
| Item 1. |
Consolidated Financial Statements
|
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| June 30, | December 31, | |||||||
| 2011 | 2010 | |||||||
| (In thousands, except share data) | ||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 3,894 | $ | 14,190 | ||||
|
Short-term restricted deposits
|
100,000 | 100,000 | ||||||
|
Trade accounts receivable, net of allowance for doubtful
accounts of $100 and $100, respectively
|
7,510 | 7,373 | ||||||
|
Assets held for sale — DHS subsidiary and oil and gas properties
|
66,704 | 108,218 | ||||||
|
Deposits and prepaid assets
|
2,617 | 1,720 | ||||||
|
Inventories
|
642 | 3,446 | ||||||
|
Other current assets
|
2,836 | 4,821 | ||||||
|
|
||||||||
|
Total current assets
|
184,203 | 239,768 | ||||||
|
|
||||||||
|
Property and equipment:
|
||||||||
|
Oil and gas properties, successful efforts method of accounting:
|
||||||||
|
Unproved
|
229,623 | 229,943 | ||||||
|
Proved
|
695,189 | 671,041 | ||||||
|
Pipeline and gathering systems
|
92,461 | 93,558 | ||||||
|
Other
|
13,815 | 13,556 | ||||||
|
|
||||||||
|
Total property and equipment
|
1,031,088 | 1,008,098 | ||||||
|
Less accumulated depreciation and depletion
|
(247,438 | ) | (232,493 | ) | ||||
|
|
||||||||
|
Net property and equipment
|
783,650 | 775,605 | ||||||
|
|
||||||||
|
|
||||||||
|
Long-term assets:
|
||||||||
|
Investments in unconsolidated affiliates
|
3,590 | 3,376 | ||||||
|
Deferred financing costs
|
1,432 | 1,832 | ||||||
|
Other long-term assets
|
2,970 | 3,531 | ||||||
|
|
||||||||
|
Total long-term assets
|
7,992 | 8,739 | ||||||
|
|
||||||||
|
|
||||||||
|
Total assets
|
$ | 975,845 | $ | 1,024,112 | ||||
|
|
||||||||
|
|
||||||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Credit facility — Delta
|
$ | 15,000 | $ | — | ||||
|
Installment payable on property acquisition
|
99,144 | 97,874 | ||||||
|
3
3
/
4
% Senior convertible notes — current
|
110,953 | — | ||||||
|
Accounts payable
|
21,030 | 27,616 | ||||||
|
Liabilities related to assets held for sale — DHS subsidiary and
oil and gas properties
|
76,112 | 82,852 | ||||||
|
Other accrued liabilities
|
8,281 | 11,066 | ||||||
|
Derivative instruments
|
2,123 | 574 | ||||||
|
|
||||||||
|
Total current liabilities
|
332,643 | 219,982 | ||||||
|
|
||||||||
|
Long-term liabilities:
|
||||||||
|
7% Senior notes
|
149,722 | 149,684 | ||||||
|
3
3
/
4
% Senior convertible notes
|
— | 108,593 | ||||||
|
Credit facility — Delta
|
— | 29,130 | ||||||
|
Asset retirement obligations
|
3,299 | 2,709 | ||||||
|
Derivative instruments
|
3,482 | 2,419 | ||||||
|
|
||||||||
|
Total long-term liabilities
|
156,503 | 292,535 | ||||||
|
|
||||||||
|
Commitments and contingencies
|
||||||||
|
|
||||||||
|
Equity:
|
||||||||
|
Preferred stock, $.01 par value:
authorized 3,000,000 shares, none issued |
— | — | ||||||
|
Common stock, $.01 par value: authorized 200,000,000 shares,
issued 29,095,000 shares at June 30, 2011 and
28,514,000 shares at December 31, 2010
(1)
|
291 | 285 | ||||||
|
Additional paid-in capital
|
1,640,295 | 1,635,783 | ||||||
|
Treasury stock at cost; zero shares at June 30, 2011
and 3,000 shares at December 31, 2010
(1)
|
— | (279 | ) | |||||
|
Accumulated deficit
|
(1,150,145 | ) | (1,121,342 | ) | ||||
|
|
||||||||
|
Total Delta stockholders’ equity
|
490,441 | 514,447 | ||||||
|
|
||||||||
|
Non-controlling interest
|
(3,742 | ) | (2,852 | ) | ||||
|
|
||||||||
|
Total equity
|
486,699 | 511,595 | ||||||
|
|
||||||||
|
|
||||||||
|
Total liabilities and equity
|
$ | 975,845 | $ | 1,024,112 | ||||
|
|
||||||||
| (1) |
All common share amounts (except par value and par value per share amounts) have been
retroactively restated as of June 30, 2011 to reflect the Company’s one-for-ten reverse
common stock split effective July 13, 2011, as described in Note 10 — Stockholders’ Equity
to these consolidated financial statements.
|
See accompanying notes to consolidated financial statements.
1
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| Three Months Ended | ||||||||
| June 30, | ||||||||
| 2011 | 2010 | |||||||
| (In thousands, except per share amounts) | ||||||||
|
Revenue:
|
||||||||
|
|
||||||||
|
Oil and gas sales
|
$ | 16,882 | $ | 14,822 | ||||
|
Loss on property sales
|
— | (109 | ) | |||||
|
|
||||||||
|
|
||||||||
|
Total revenue
|
16,882 | 14,713 | ||||||
|
|
||||||||
|
Operating expenses:
|
||||||||
|
|
||||||||
|
Lease operating expense
|
3,563 | 6,067 | ||||||
|
Transportation expense
|
3,625 | 4,359 | ||||||
|
Production taxes
|
611 | 786 | ||||||
|
Exploration expense
|
233 | 358 | ||||||
|
Dry hole costs and impairments
|
273 | 29,865 | ||||||
|
Depreciation, depletion, amortization and accretion
|
10,528 | 12,142 | ||||||
|
General and administrative expense
|
6,471 | 10,648 | ||||||
|
|
||||||||
|
|
||||||||
|
Total operating expenses
|
25,304 | 64,225 | ||||||
|
|
||||||||
|
Operating loss
|
(8,422 | ) | (49,512 | ) | ||||
|
|
||||||||
|
Other income and (expense):
|
||||||||
|
Interest expense and financing costs, net
|
(7,997 | ) | (7,781 | ) | ||||
|
Other income
|
233 | 111 | ||||||
|
Realized loss on derivative instruments, net
|
(5,010 | ) | (601 | ) | ||||
|
Unrealized gain on derivative instruments, net
|
8,341 | 3,676 | ||||||
|
Income from unconsolidated affiliates
|
131 | 991 | ||||||
|
|
||||||||
|
|
||||||||
|
Total other expense
|
(4,302 | ) | (3,604 | ) | ||||
|
|
||||||||
|
|
||||||||
|
Loss from continuing operations before income taxes and
discontinued operations
|
(12,724 | ) | (53,116 | ) | ||||
|
|
||||||||
|
Income tax expense (benefit)
|
(3,938 | ) | 203 | |||||
|
|
||||||||
|
Loss from continuing operations
|
(8,786 | ) | (53,319 | ) | ||||
|
|
||||||||
|
Discontinued operations:
|
||||||||
|
|
||||||||
|
Gain (loss) from results of operations and sale of discontinued operations, net of tax
|
9,320 | (99,161 | ) | |||||
|
|
||||||||
|
|
||||||||
|
Net income (loss)
|
534 | (152,480 | ) | |||||
|
|
||||||||
|
Less net (gain) loss attributable to non-controlling interest included in discontinued
operations
|
(1,497 | ) | 2,730 | |||||
|
|
||||||||
|
|
||||||||
|
Net loss attributable to Delta common stockholders
|
$ | (963 | ) | $ | (149,750 | ) | ||
|
|
||||||||
|
|
||||||||
|
Amounts attributable to Delta common stockholders:
|
||||||||
|
Loss from continuing operations
|
$ | (8,786 | ) | $ | (53,319 | ) | ||
|
Gain (loss) from discontinued operations, net of tax
|
7,823 | (96,431 | ) | |||||
|
|
||||||||
|
Net loss
|
$ | (963 | ) | $ | (149,750 | ) | ||
|
|
||||||||
|
|
||||||||
|
Basic loss attributable to Delta common stockholders per common share:
(1)
|
||||||||
|
Loss from continuing operations
|
$ | (0.31 | ) | $ | (1.93 | ) | ||
|
Discontinued operations
|
0.28 | (3.50 | ) | |||||
|
|
||||||||
|
Net loss
|
$ | (0.03 | ) | $ | (5.43 | ) | ||
|
|
||||||||
|
|
||||||||
|
Diluted loss attributable to Delta common stockholders per common share:
(1)
|
||||||||
|
Loss from continuing operations
|
$ | (0.31 | ) | $ | (1.93 | ) | ||
|
Discontinued operations
|
0.28 | (3.50 | ) | |||||
|
|
||||||||
|
Net loss
|
$ | (0.03 | ) | $ | (5.43 | ) | ||
|
|
||||||||
| (1) |
All common share amounts (except par value and par value per share amounts) have been
retroactively restated as of June 30, 2011 to reflect the Company’s one-for-ten reverse
common stock split effective July 13, 2011, as described in Note 10 — Stockholders’
Equity to these consolidated financial statements.
|
See accompanying notes to consolidated financial statements.
2
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| Six Months Ended | ||||||||
| June 30, | ||||||||
| 2011 | 2010 | |||||||
| (In thousands, except per share amounts) | ||||||||
|
Revenue:
|
||||||||
|
|
||||||||
|
Oil and gas sales
|
$ | 34,597 | $ | 34,484 | ||||
|
Loss on property sales
|
— | (538 | ) | |||||
|
|
||||||||
|
|
||||||||
|
Total revenue
|
34,597 | 33,946 | ||||||
|
|
||||||||
|
Operating expenses:
|
||||||||
|
|
||||||||
|
Lease operating expense
|
6,958 | 10,527 | ||||||
|
Transportation expense
|
7,568 | 7,642 | ||||||
|
Production taxes
|
1,461 | 1,691 | ||||||
|
Exploration expense
|
276 | 584 | ||||||
|
Dry hole costs and impairments
|
416 | 30,219 | ||||||
|
Depreciation, depletion, amortization and accretion
|
22,479 | 23,887 | ||||||
|
General and administrative expense
|
13,100 | 20,898 | ||||||
|
|
||||||||
|
|
||||||||
|
Total operating expenses
|
52,258 | 95,448 | ||||||
|
|
||||||||
|
Operating loss
|
(17,661 | ) | (61,502 | ) | ||||
|
|
||||||||
|
Other income and (expense):
|
||||||||
|
|
||||||||
|
Interest expense and financing costs, net
|
(14,803 | ) | (16,484 | ) | ||||
|
Other income
|
164 | 179 | ||||||
|
Realized loss on derivative instruments, net
|
(5,450 | ) | (4,714 | ) | ||||
|
Unrealized gain (loss) on derivative instruments, net
|
(2,612 | ) | 20,948 | |||||
|
Income from unconsolidated affiliates
|
214 | 983 | ||||||
|
|
||||||||
|
|
||||||||
|
Total other income and (expense)
|
(22,487 | ) | 912 | |||||
|
|
||||||||
|
|
||||||||
|
Loss from continuing operations before income taxes and
discontinued operations
|
(40,148 | ) | (60,590 | ) | ||||
|
|
||||||||
|
Income tax expense (benefit)
|
(4,633 | ) | 478 | |||||
|
|
||||||||
|
|
||||||||
|
Loss from continuing operations
|
(35,515 | ) | (61,068 | ) | ||||
|
|
||||||||
|
Discontinued operations:
|
||||||||
|
|
||||||||
|
Gain (loss) from results of operations and sale of discontinued operations, net of tax
|
5,785 | (107,404 | ) | |||||
|
|
||||||||
|
|
||||||||
|
Net loss
|
(29,730 | ) | (168,472 | ) | ||||
|
|
||||||||
|
Less net loss attributable to non-controlling interest included in discontinued
operations
|
927 | 5,925 | ||||||
|
|
||||||||
|
|
||||||||
|
Net loss attributable to Delta common stockholders
|
$ | (28,803 | ) | $ | (162,547 | ) | ||
|
|
||||||||
|
|
||||||||
|
Amounts attributable to Delta common stockholders:
|
||||||||
|
Loss from continuing operations
|
$ | (35,515 | ) | $ | (61,068 | ) | ||
|
Gain (loss) from discontinued operations, net of tax
|
6,712 | (101,479 | ) | |||||
|
|
||||||||
|
Net loss
|
$ | (28,803 | ) | $ | (162,547 | ) | ||
|
|
||||||||
|
|
||||||||
|
Basic loss attributable to Delta common stockholders per common share:
(1)
|
||||||||
|
Loss from continuing operations
|
$ | (1.27 | ) | $ | (2.22 | ) | ||
|
Discontinued operations
|
0.24 | (3.68 | ) | |||||
|
|
||||||||
|
Net loss
|
$ | (1.03 | ) | $ | (5.90 | ) | ||
|
|
||||||||
|
|
||||||||
|
Diluted loss attributable to Delta common stockholders per common share:
(1)
|
||||||||
|
Loss from continuing operations
|
$ | (1.27 | ) | $ | (2.22 | ) | ||
|
Discontinued operations
|
0.24 | (3.68 | ) | |||||
|
|
||||||||
|
Net loss
|
$ | (1.03 | ) | $ | (5.90 | ) | ||
|
|
||||||||
| (1) |
All common share amounts (except par value and par value per share amounts) have been
retroactively restated as of June 30, 2011 to reflect the Company’s one-for-ten reverse
common stock split effective July 13, 2011, as described in Note 10 — Stockholders’
Equity to these consolidated financial statements.
|
See accompanying notes to consolidated financial statements.
3
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
| Additional | Accu- | Total Delta | Non- | |||||||||||||||||||||||||||||||||
| Common stock | paid-in | Treasury stock | mulated | stockholders’ | controlling | Total | ||||||||||||||||||||||||||||||
| Shares (1) | Amount | capital | Shares (1) | Amount | deficit | equity | interest | equity | ||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||
|
Balance, December 31, 2010
|
28,514 | $ | 285 | $ | 1,635,783 | 3 | $ | (279 | ) | $ | (1,121,342 | ) | $ | 514,447 | $ | (2,852 | ) | $ | 511,595 | |||||||||||||||||
|
|
||||||||||||||||||||||||||||||||||||
|
Net loss
|
— | — | — | — | — | (28,803 | ) | (28,803 | ) | (927 | ) | (29,730 | ) | |||||||||||||||||||||||
|
Employee vesting of treasury stock held by
subsidiary
|
— | — | (135 | ) | (3 | ) | 279 | — | 144 | (59 | ) | 85 | ||||||||||||||||||||||||
|
Issuance of vested stock
|
591 | 6 | (6 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||||
|
Shares repurchased for withholding taxes
|
(1 | ) | — | (7 | ) | — | — | — | (7 | ) | — | (7 | ) | |||||||||||||||||||||||
|
Forfeitures
|
(9 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
|
Stock based compensation
|
— | — | 4,660 | — | — | — | 4,660 | 96 | 4,756 | |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||||||
|
Balance, June 30, 2011
|
29,095 | $ | 291 | $ | 1,640,295 | — | $ | — | $ | (1,150,145 | ) | $ | 490,441 | $ | (3,742 | ) | $ | 486,699 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||||||
| (1) |
All common share amounts (except par value and par value per share amounts) have been
retroactively restated as of June 30, 2011 to reflect the Company’s one-for-ten reverse
common stock split effective July 13, 2011, as described in Note 10 — Stockholders’
Equity to these consolidated financial statements.
|
See accompanying notes to consolidated financial statements.
4
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| Six Months Ended | ||||||||
| June 30, | ||||||||
| 2011 | 2010 | |||||||
| (In thousands) | ||||||||
|
Cash flows from operating activities:
|
||||||||
|
Net loss
|
$ | (29,730 | ) | $ | (168,472 | ) | ||
|
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
|
||||||||
|
Loss on property sales
|
— | 538 | ||||||
|
Depreciation, depletion, amortization — oil and gas
|
22,479 | 23,887 | ||||||
|
Depreciation, depletion, amortization — discontinued operations
|
5,464 | 31,844 | ||||||
|
(Gain) loss on sale of drilling assets — discontinued operations
|
(2,438 | ) | 256 | |||||
|
Gain on sale of oil and gas assets — discontinued operations
|
(8,946 | ) | — | |||||
|
Impairments — discontinued operations
|
— | 93,064 | ||||||
|
Dry hole costs and impairments
|
416 | 30,219 | ||||||
|
Stock based compensation
|
4,762 | 6,852 | ||||||
|
Amortization of deferred financing costs, bond discount, and installments payable discount
|
6,198 | 7,215 | ||||||
|
Unrealized (gain) loss on derivative contracts
|
2,612 | (20,948 | ) | |||||
|
Income from unconsolidated affiliates
|
(214 | ) | (983 | ) | ||||
|
Deferred income tax expense
|
478 | 478 | ||||||
|
Other
|
(395 | ) | 48 | |||||
|
Net changes in operating assets and liabilities:
|
||||||||
|
Increase in trade accounts receivable
|
(67 | ) | (1,103 | ) | ||||
|
(Increase) decrease in deposits and prepaid assets
|
(897 | ) | 686 | |||||
|
Increase in inventories
|
(64 | ) | — | |||||
|
(Increase) decrease in other current assets
|
(17 | ) | 765 | |||||
|
Increase (decrease) in accounts payable
|
112 | (12,863 | ) | |||||
|
Decrease in offshore litigation payable
|
— | (14,756 | ) | |||||
|
Decrease in other accrued liabilities
|
(1,854 | ) | — | |||||
|
Increase in assets held for sale working capital, net
|
2,213 | — | ||||||
|
|
||||||||
|
|
||||||||
|
Net cash provided by (used in) operating activities
|
112 | (23,273 | ) | |||||
|
|
||||||||
|
|
||||||||
|
Cash flows from investing activities:
|
||||||||
|
Additions to property and equipment
|
(36,727 | ) | (18,861 | ) | ||||
|
Additions to drilling and trucking equipment — assets held for sale
|
(822 | ) | (709 | ) | ||||
|
Proceeds from sale of oil and gas properties
|
41,216 | 2,007 | ||||||
|
Proceeds from sale of drilling assets — assets held for sale
|
3,367 | 464 | ||||||
|
Proceeds from sale of other fixed assets
|
61 | 39 | ||||||
|
Proceeds from sale of unconsolidated affiliates
|
898 | 3,500 | ||||||
|
Proceeds from escrow deposit
|
— | 1,380 | ||||||
|
Decrease in other long-term assets
|
— | 106 | ||||||
|
|
||||||||
|
|
||||||||
|
Net cash provided by (used in) investing activities
|
7,993 | (12,074 | ) | |||||
|
|
||||||||
|
|
||||||||
|
Cash flows from financing activities:
|
||||||||
|
Proceeds from borrowings
|
49,202 | 66,500 | ||||||
|
Repayments of borrowings
|
(66,617 | ) | (80,678 | ) | ||||
|
Payment of deferred financing costs
|
(979 | ) | (1,337 | ) | ||||
|
Stock repurchased for withholding taxes
|
(7 | ) | (5 | ) | ||||
|
|
||||||||
|
|
||||||||
|
Net cash used in financing activities
|
(18,401 | ) | (15,520 | ) | ||||
|
|
||||||||
|
|
||||||||
|
Net decrease in cash and cash equivalents
|
(10,296 | ) | (50,867 | ) | ||||
|
|
||||||||
|
Cash at beginning of period
|
14,190 | 61,918 | ||||||
|
|
||||||||
|
|
||||||||
|
Cash at end of period
|
$ | 3,894 | $ | 11,051 | ||||
|
|
||||||||
|
|
||||||||
|
Supplemental cash flow information:
|
||||||||
|
Cash paid for interest and financing costs
|
$ | 10,011 | $ | 14,395 | ||||
|
|
||||||||
|
|
||||||||
|
DHS interest payable capitalized to principal balance (non-cash financing transaction)
|
$ | 3,566 | $ | — | ||||
|
|
||||||||
See accompanying notes to consolidated financial statements.
5
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(1) Nature of Organization and Basis of Presentation
Delta Petroleum Corporation (“Delta”), a Delaware corporation, and its consolidated subsidiaries
(collectively, the “Company”) are principally engaged in acquiring, exploring, developing and
producing oil and gas properties. The Company’s core area of operations is the Rocky Mountain
Region in which the majority of its proved reserves, production and long-term growth prospects are
concentrated.
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
previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31,
2010. 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.
Subsequent events were evaluated through the date of issuance of these consolidated financial
statements at the time this quarterly report on Form 10-Q was filed with the Securities and
Exchange Commission (“SEC”). 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
December 31, 2010, previously filed with the SEC.
(2) Going Concern
The accompanying financial statements have been prepared assuming the Company will continue as a
going concern.
On December 29, 2010, the Company entered into a Third Amended and Restated Credit Agreement (the
“MBL Credit Agreement”), with Macquarie Bank Limited (“MBL”) as administrative agent and issuing
lender as more fully described in Note 6, “Long Term Debt.” Proceeds available from the MBL Credit
Agreement were used to substantially reduce amounts outstanding under the Company’s prior credit
facility, as well as to extend the maturity of the remaining balance under that credit facility
from January 15, 2011 to January 31, 2012, and to fund capital expenditures. On June 28, 2011, the
Company amended the MBL Credit Agreement to permit the 2011 Wapiti Transaction.
On June 28, 2011, the Company closed on a transaction with Wapiti Oil & Gas, L.L.C. (“Wapiti”) to
sell its remaining interests in various non-core assets primarily located in Texas and Wyoming (the
“2011 Wapiti Transaction”) for gross cash proceeds of approximately $43.2 million. Proceeds from
the 2011 Wapiti Transaction were used to further reduce amounts outstanding under the MBL Credit
Agreement, as well as to fund capital expenditures.
The MBL Credit Agreement, as amended, provides for a revolving loan and a term loan, each with a
maturity date of January 31, 2012. At June 30, 2011, zero was outstanding under the revolving loan
and $15.0 million was outstanding under the term loan. The Company was in compliance with its
financial covenants under the MBL Credit Agreement as of June 30, 2011.
During the six months ended June 30, 2011, the Company experienced a net loss attributable to Delta
common stockholders of $28.8 million, and at June 30, 2011 had a working capital deficiency,
excluding discontinued operations, of $139.0 million, including $15.0 million outstanding under the
MBL Credit Agreement (which is classified as a current liability in the accompanying balance
sheet). In addition to the amounts outstanding under the Company’s credit facility which are due
on January 31, 2012, the holders of the Company’s $115.0 million 3
3
/
4
% senior
convertible notes have the option to require the Company to repurchase the notes at par on May 1,
2012.
6
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(2) Going Concern, Continued
While the 2011 Wapiti Transaction and the MBL Credit Agreement provided capital to the Company that
helped to improve its financial position, the Company does not have adequate capital to repay its
credit facility borrowings due on January 31, 2012 or fund the purchase of convertible notes if the
holders of such notes elect to require the Company to repurchase such notes on May 1, 2012, as
expected.
The Company believes that the amounts available under the Company’s credit facility, as amended,
combined with projected net cash from operating activities, will provide sufficient liquidity to
fund its operating expenses, the limited Vega Area capital development plan, and maintain current
debt service obligations until the January 2012 maturity of the Company’s credit facility. In order
to address the January 2012 maturity of the Company’s credit facility and the expected mandatory
redemption in May 2012 of the $115.0 million senior convertible notes, the Company is in the
process of seeking additional sources of long-term capital (including the issuance of equity, debt
instruments, sales of assets and joint venture financing), as well as consider other potential
corporate transactions such as a sale of the Company.
As a result, in July 2011, the Board of Directors of the Company announced that it had engaged
Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors to the Company in
conducting a strategic alternatives process in order to maximize shareholder value and address the
2012 debt maturities. Through this process, the Board of Directors intends to evaluate all
opportunities available, including a potential sale of the Company.
The timing, structure, terms, size, and pricing of any transaction consummated as a result of the
strategic alternatives process will depend on investor interest and market conditions, as well as
the Company’s drilling and completion results, and there can be no assurance that the Company will
be able to obtain any such financing or consummate any such transaction, and if so, that it will be
on terms satisfactory to the Company which raises substantial doubt about the Company’s ability to
continue as a going concern. The financial statements do not include any adjustments that might
result from the outcome of uncertainty regarding the Company’s ability to raise additional capital,
sell assets, or otherwise obtain sufficient funds to meet its obligations.
The DHS Drilling Company (“DHS”) credit facility debt of $69.9 million at June 30, 2011 is included
in the accompanying consolidated balance sheets as a component of liabilities related to assets
held for sale. DHS has entered into a forbearance agreement, as amended, that currently expires on
August 8, 2011. Although DHS is in ongoing negotiations with its lender, Lehman Commercial Paper,
Inc. (“LCPI”) to modify the terms of the existing DHS credit facility, there can be no assurance
that DHS will be able to renegotiate the terms of its debt agreement or obtain any further
extension to the forbearance agreement. If DHS is unable to extend the forbearance agreement or
modify the terms of its debt agreement, and if LCPI exercises its default rights upon expiration of
the forbearance period, including demanding immediate payment of all amounts outstanding under the
debt agreement, DHS is not anticipated to have sufficient capital to repay the amounts due. The DHS
facility is non-recourse to Delta. During the first quarter of 2011, the Board of Directors of DHS
engaged transaction advisors to commence a strategic alternatives process, focused on a sale of DHS
or substantially all of its assets. There can be no assurance that the terms offered by a
potential buyer or buyers, if any, will be acceptable to the DHS shareholders, including Delta.
Additionally, the consummation of certain transactions are subject to the approval of LCPI and the
proceeds received will be required to be used to pay down amounts outstanding under its LCPI credit
facility.
(3) Summary of Significant Accounting Policies
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of Delta and its consolidated
subsidiaries (collectively, the “Company”). All inter-company balances and transactions have been
eliminated in consolidation. Certain of the Company’s oil and gas activities are conducted through
partnerships and joint ventures, including CRB Partners, LLC (“CRBP”) and through the date of the
divestiture in 2010 to Wapiti, PGR Partners, LLC (“PGR”). The Company
includes its proportionate share of assets, liabilities, revenues and expenses from these entities
in its consolidated financial statements. The Company does not have any off-balance sheet financing
arrangements (other than operating leases) or any unconsolidated special purpose entities.
7
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
Investments in operating entities where the Company has the ability to exert significant influence,
but does not control the operating and financial policies, are accounted for using the equity
method. The Company’s share of net income of these entities is recorded as income (losses) from
unconsolidated affiliates in the consolidated statements of operations.
Investments in operating entities where the Company does not exert significant influence are
accounted for using the cost method, and income is only recognized when a distribution is received.
Certain reclassifications have been made to amounts reported in the previous periods to conform to
the current presentation. Among other items, revenues and expenses on certain properties that were
sold or held for sale during the three and six months ended June 30, 2011 have been reclassified
from continuing operations to discontinued operations for all periods presented. In addition, the
assets and liabilities of DHS, and oil and gas properties that were sold or held for sale, have
been separately reflected in the accompanying consolidated balance sheets as assets held for sale
and liabilities related to assets held for sale. Such reclassifications had no effect on net loss
(See Note 4, “Discontinued Operations”).
Property and Equipment
The Company accounts for its natural gas and crude oil exploration and development activities under
the successful efforts method of accounting. Under such method, costs of productive exploratory
wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and
gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs,
certain geological or geophysical expenses and delay rentals for gas and oil leases, are charged to
expense as incurred. Exploratory drilling costs are initially capitalized, then evaluated
quarterly and 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 units-of-production amortization rate. A gain or loss is recognized for all other sales
of producing properties.
Unproved properties with significant acquisition costs are assessed quarterly on a
property-by-property basis and any impairment in value is charged to expense. If the unproved
properties are determined to be productive, the related costs are transferred to proved gas and oil
properties. Proceeds from sales of partial interests in unproved leases are accounted for as a
recovery of cost without recognizing any gain or loss until all costs have been recovered.
Depreciation and depletion of capitalized acquisition, exploration and development costs are
computed on the units-of-production method by individual fields as the related proved reserves are
produced.
Drilling equipment is recorded at cost or estimated fair value upon acquisition and depreciated on
a component basis using the straight-line method over its estimated useful life ranging from five
to 15 years. Pipelines and gathering systems and other property and equipment are recorded at cost
and depreciated using the straight-line method over their estimated useful lives ranging from three
to 40 years.
Impairment of Long-Lived Assets
Long-lived assets are reviewed for impairment when events or changes in circumstances indicate that
the carrying value of such assets may not be recoverable.
Estimates of expected future cash flows represent management’s best estimate based on reasonable
and supportable assumptions and projections. For proved properties, if the expected future cash
flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value
of the asset exceeds the expected future cash flows, an
impairment exists and is measured by the excess of the carrying value over the estimated fair value
of the asset. Any impairment provisions recognized are permanent and may not be restored in the
future.
8
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
The Company assesses proved properties on an individual field basis for impairment on at least an
annual basis. For proved properties, the review consists of a comparison of the carrying value of
the asset with the asset’s expected future undiscounted cash flows without interest costs. For the
three and six months ended June 30, 2011 and 2010, the expected future undiscounted cash flows of
the assets exceeded the carrying value of the corresponding asset and as such no impairment
provisions were recognized.
For unproved properties, the need for an impairment charge is based on the Company’s plans for
future development and other activities impacting the life of the property and the ability of the
Company to recover its investment. When the Company believes the costs of the unproved property
are no longer recoverable, an impairment charge is recorded based on the estimated fair value of
the property. For the three and six months ended June 30, 2011, no significant impairments were
recorded. For the three and six months ended June 30, 2010, the Company recorded
impairment provisions attributable to unproved properties of $24.6 million and $25.5 million,
respectively. These impairment provisions are included within dry hole costs and impairments in
the accompanying statements of operations for the three and six months ended June 30, 2010.
During the remainder of 2011, the Company plans to develop and evaluate certain proved and unproved
properties. Favorable or unfavorable drilling results or changes in commodity prices may cause a
revision to estimates of those properties’ future cash flows. Such revisions of estimates could
require the Company to record additional impairment provisions in the period of such revisions.
Exploratory Well Costs
| Six Months Ended | ||||
| June 30, 2011 | ||||
|
Balance at beginning of year
|
$ | 6,200 | ||
|
Additions to capitalized exploratory well costs pending
the determination of proved reserves
|
13,445 | |||
|
Exploratory well costs included in property divestitures
|
— | |||
|
Reclassified to proved oil and gas properties based on
the determination of proved reserves
|
— | |||
|
Capitalized exploratory well costs charged to dry hole expense
|
— | |||
|
|
||||
|
Balance at end of period
|
$ | 19,645 | ||
|
|
||||
|
Exploratory well costs capitalized for one year or less after
after completion of drilling
|
19,645 | |||
|
Exploratory well costs capitalized for greater than one year
after completion of drilling
|
— | |||
|
|
||||
|
Balance at end of period
|
$ | 19,645 | ||
|
|
||||
The table does not include amounts that were capitalized and either subsequently expensed or
reclassified to producing well costs in the same period. During 2010, the Company spud a deep test
well in the Vega Area to explore the Company’s Piceance leasehold below the currently productive
Williams Fork zone. Completion activities on the well began in February 2011 and the well was
completed as a producing well with proved reserves subsequent to June 30, 2011. A second deep test
well was spud and completed as a producing well with proved reserves during the six months ended
June 30, 2011 and therefore is not included in the table above. A third deep test well was spud
during the three months ended June 30, 2011 and remains in progress.
Asset Retirement Obligations
The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for
its oil and gas wells. The Company has no obligation to provide for the retirement of most of its
offshore properties as the obligations
remained with the seller from whom the Company acquired the properties.
9
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
The following is a reconciliation of the Company’s asset retirement obligations from January 1,
2011 to June 30, 2011 (in thousands):
|
Asset retirement obligation — January 1, 2011
|
$ | 5,146 | ||
|
Reclassification for assets held for sale
|
(1,215 | ) | ||
|
|
||||
|
Adjusted asset retirement obligation — January 1, 2011
|
3,931 | |||
|
Accretion expense
|
150 | |||
|
Change in estimate
|
(114 | ) | ||
|
Obligations incurred (from new wells)
|
45 | |||
|
Obligations settled
|
(20 | ) | ||
|
Obligations on sold properties
|
(118 | ) | ||
|
|
||||
|
Asset retirement obligation — June 30, 2011
|
3,874 | |||
|
Less: Current portion of asset retirement obligation
|
(575 | ) | ||
|
|
||||
|
Long-term asset retirement obligation
|
$ | 3,299 | ||
|
|
||||
Comprehensive Income (Loss)
Comprehensive income (loss) includes all changes in equity during a period except those resulting
from investments by owners and distributions to owners, if any. For the three months ended June
30, 2011 and 2010, comprehensive loss attributable to Delta common stockholders was $963,000 and
$149.8 million, respectively. For the six months ended June 30, 2011 and 2010, comprehensive loss
attributable to Delta common stockholders was $28.8 million and $162.5 million, respectively.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the reporting period.
Significant estimates include oil and gas reserves, bad debts, depletion and impairment of oil and
gas properties, income taxes, derivatives, asset retirement obligations, contingencies and
litigation accruals. Actual results could differ from these estimates.
(4) Discontinued Operations
During the third quarter of 2010, the Company closed a transaction with Wapiti (the “2010 Wapiti
Transaction”), selling all or a portion of the Company’s interest in various non-core assets
primarily located in Colorado, Texas, and Wyoming for gross proceeds of $130.0 million. During the
three months ended June 30, 2011, the Company closed the 2011 Wapiti Transaction, selling the
remaining portion of its interests in non-core assets primarily located in Texas and Wyoming for
gross cash proceeds of approximately $43.2 million. In accordance with accounting standards, the
results of operations relating to these properties have been reflected as discontinued operations
for all periods presented. In addition, the assets and liabilities related to the oil and gas
properties in the 2011 Wapiti Transaction have been separately reflected in the accompanying
consolidated balance sheet as of December 31, 2010 as assets held for sale and liabilities related
to assets held for sale.
In separate transactions in 2010, the Company sold its interest in the Howard Ranch field and the
Laurel Ridge field and has included these properties in discontinued operations as well.
During the three months ended March 31, 2011, the Board of Directors of DHS engaged transaction
advisors to commence a strategic alternatives process, focused on a sale of DHS or substantially
all of its assets. As such, in accordance with accounting standards, the results of operations
relating to DHS have been reflected as discontinued operations. In addition, the assets and
liabilities of DHS have been separately reflected in the accompanying consolidated balance sheets
as assets held for sale and liabilities related to assets held for sale.
10
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(4) Discontinued Operations, Continued
The following table shows the oil and gas segment and drilling segment revenues and expenses
included in discontinued operations for the above mentioned oil and gas properties for the three
months ended June 30, 2011 and 2010 (in thousands):
| Three Months Ended | Three Months Ended | |||||||||||||||||||||||
| June 30, 2011 | June 30, 2010 | |||||||||||||||||||||||
| Oil & Gas | Drilling | Total | Oil & Gas | Drilling | Total | |||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||||||
|
Oil and gas sales
|
$ | 4,594 | $ | — | $ | 4,594 | $ | 13,504 | $ | — | $ | 13,504 | ||||||||||||
|
Contract drilling and trucking fees
|
— | 12,129 | 12,129 | — | 11,064 | 11,064 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total Revenues
|
4,594 | 12,129 | 16,723 | 13,504 | 11,064 | 24,568 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||||||||||
|
Lease operating expense
|
1,307 | — | 1,307 | 2,943 | — | 2,943 | ||||||||||||||||||
|
Transportation expense
|
12 | — | 12 | 799 | — | 799 | ||||||||||||||||||
|
Production taxes
|
321 | — | 321 | 792 | — | 792 | ||||||||||||||||||
|
Depreciation, depletion, amortization
and accretion — oil and gas
|
1,286 | — | 1,286 | 9,605 | — | 9,605 | ||||||||||||||||||
|
Impairment provision
(1)
|
— | — | — | 93,064 | — | 93,064 | ||||||||||||||||||
|
Drilling and trucking operating expenses
|
— | 9,406 | 9,406 | — | 8,123 | 8,123 | ||||||||||||||||||
|
Depreciation and amortization —
drilling and trucking
(2)
|
— | — | — | — | 5,226 | 5,226 | ||||||||||||||||||
|
General and administrative expense
|
— | 1,051 | 1,051 | — | 992 | 992 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total operating expenses
|
2,926 | 10,457 | 13,383 | 107,203 | 14,341 | 121,544 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Operating income (loss)
|
1,668 | 1,672 | 3,340 | (93,699 | ) | (3,277 | ) | (96,976 | ) | |||||||||||||||
|
|
||||||||||||||||||||||||
|
Other income and (expense):
|
||||||||||||||||||||||||
|
Interest expense and financing costs, net
|
— | (2,091 | ) | (2,091 | ) | — | (1,775 | ) | (1,775 | ) | ||||||||||||||
|
Other income (expense)
|
— | 124 | 124 | — | (410 | ) | (410 | ) | ||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total other income and (expense)
|
— | (1,967 | ) | (1,967 | ) | — | (2,185 | ) | (2,185 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Income (loss) from discontinued operations
|
1,668 | (295 | ) | 1,373 | (93,699 | ) | (5,462 | ) | (99,161 | ) | ||||||||||||||
|
Income tax expense
(3)
|
(615 | ) | — | (615 | ) | — | — | — | ||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Income (loss) from results of operations of discontinued
operations, net of tax
|
1,053 | (295 | ) | 758 | (93,699 | ) | (5,462 | ) | (99,161 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
Gain on sales of discontinued operations, net of tax
(4)
|
5,645 | 2,917 | 8,562 | — | — | — | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Gain (loss) from results of operations and sale of discontinued
operations, net of tax
|
$ | 6,698 | $ | 2,622 | $ | 9,320 | $ | (93,699 | ) | $ | (5,462 | ) | $ | (99,161 | ) | |||||||||
|
|
||||||||||||||||||||||||
| (1) |
Impairment provision
. In accordance with accounting standards, the
impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction
with the 2010 Wapiti Transaction were reflected as discontinued operations.
|
|
| (2) |
Depreciation and Amortization — Drilling and Trucking
. Depreciation and
amortization expense — drilling decreased to zero for the three months ended June 30, 2011 as
compared to $5.2 million for the comparable year earlier period. The decrease is due to not
recording depreciation expense beginning in March 2011 in accordance with accounting rules
related to the asset held for sale treatment of DHS.
|
|
| (3) |
Income tax expense
. For the three months ended June 30, 2011, the Company
recorded a tax benefit of $3.9 million due to a non-cash income tax benefit related to gains
from discontinued oil and gas operations. Generally accepted accounting principles, or GAAP,
require all items be considered, including items recorded in discontinued operations, in
determining the amount of tax benefit that results from a loss from continuing operations that
should be allocated to continuing operations. In accordance with GAAP, the Company recorded a
tax benefit on our loss from continuing operations, which was exactly offset by income tax
expense on discontinued operations.
|
|
| (4) |
Gain on sales of discontinued operations — oil and gas
. On June 28, 2011,
the Company closed on a transaction with Wapiti Oil & Gas to sell its remaining interests in
various non-core assets primarily located in Texas and Wyoming (the “2011 Wapiti Transaction”)
for gross cash proceeds of approximately $43.2 million. In accordance with accounting
standards, the Company recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3
million of tax) for the three months ended June 30, 2011 that is reflected in discontinued
operations.
Gain on sales of discontinued operations — drilling
. In June 2011, DHS sold
substantially all of its Chapman Trucking assets for $3.3 million in proceeds and a gain of
$2.9 million. Proceeds were used to reduce DHS bank debt.
|
11
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(4) Discontinued Operations, Continued
The following table shows the oil and gas segment and drilling segment revenues and expenses
included in discontinued operations for the above mentioned oil and gas properties for the six
months ended June 30, 2011 and 2010 (in thousands):
| Six Months Ended | Six Months Ended | |||||||||||||||||||||||
| June 30, 2011 | June 30, 2010 | |||||||||||||||||||||||
| Oil & Gas | Drilling | Total | Oil & Gas | Drilling | Total | |||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||||||
|
Oil and gas sales
|
$ | 9,935 | $ | — | $ | 9,935 | $ | 28,295 | $ | — | $ | 28,295 | ||||||||||||
|
Contract drilling and trucking fees
|
— | 26,393 | 26,393 | — | 20,996 | 20,996 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total Revenues
|
9,935 | 26,393 | 36,328 | 28,295 | 20,996 | 49,291 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||||||||||
|
Lease operating expense
|
2,517 | — | 2,517 | 6,654 | — | 6,654 | ||||||||||||||||||
|
Transportation expense
|
22 | — | 22 | 1,443 | — | 1,443 | ||||||||||||||||||
|
Production taxes
|
404 | — | 404 | 1,568 | — | 1,568 | ||||||||||||||||||
|
Depreciation, depletion, amortization
and accretion — oil and gas
|
2,795 | — | 2,795 | 21,046 | — | 21,046 | ||||||||||||||||||
|
Impairment provision
(1)
|
— | — | — | 93,064 | — | 93,064 | ||||||||||||||||||
|
Drilling and trucking operating expenses
|
— | 22,507 | 22,507 | — | 16,012 | 16,012 | ||||||||||||||||||
|
Depreciation and amortization —
drilling and trucking
(2)
|
— | 2,669 | 2,669 | — | 10,798 | 10,798 | ||||||||||||||||||
|
General and administrative expense
|
— | 2,084 | 2,084 | — | 2,129 | 2,129 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total operating expenses
|
5,738 | 27,260 | 32,998 | 123,775 | 28,939 | 152,714 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Operating income (loss)
|
4,197 | (867 | ) | 3,330 | (95,480 | ) | (7,943 | ) | (103,423 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
Other income and (expense):
|
||||||||||||||||||||||||
|
Interest expense and financing costs, net
|
— | (4,129 | ) | (4,129 | ) | — | (3,632 | ) | (3,632 | ) | ||||||||||||||
|
Other income (expense)
|
— | (428 | ) | (428 | ) | — | (349 | ) | (349 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total other income and (expense)
|
— | (4,557 | ) | (4,557 | ) | — | (3,981 | ) | (3,981 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Income (loss) from discontinued operations
|
4,197 | (5,424 | ) | (1,227 | ) | (95,480 | ) | (11,924 | ) | (107,404 | ) | |||||||||||||
|
|
||||||||||||||||||||||||
|
Income tax expense
(3)
|
(1,550 | ) | — | (1,550 | ) | — | — | — | ||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Income (loss) from results of operations of discontinued
operations, net of tax
|
2,647 | (5,424 | ) | (2,777 | ) | (95,480 | ) | (11,924 | ) | (107,404 | ) | |||||||||||||
|
|
||||||||||||||||||||||||
|
Gain on sales of discontinued operations
(4)
|
5,645 | 2,917 | 8,562 | — | — | — | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Gain (loss) from results of operations and sale of discontinued
operations, net of tax
|
$ | 8,292 | $ | (2,507 | ) | $ | 5,785 | $ | (95,480 | ) | $ | (11,924 | ) | $ | (107,404 | ) | ||||||||
|
|
||||||||||||||||||||||||
| (1) |
Impairment provision
. In accordance with accounting standards, the
impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction
with the 2010 Wapiti Transaction were reflected as discontinued operations.
|
|
| (2) |
Depreciation and Amortization — Drilling and Trucking
. Depreciation and
amortization expense — drilling decreased to $2.7 million for the six months ended June 30,
2011 as compared to $10.8 million for the comparable year earlier period. The decrease is due
to not recording depreciation expense beginning in March 2011 in accordance with accounting
rules related to the asset held for sale treatment of DHS.
|
|
| (3) |
Income tax expense
. For the six months ended June 30, 2011, the Company
recorded a tax benefit of $4.8 million due to a non-cash income tax benefit related to gains
from discontinued oil and gas operations. Generally accepted accounting principles, or GAAP,
require all items be considered, including items recorded in discontinued operations, in
determining the amount of tax benefit that results from a loss from continuing operations that
should be allocated to continuing operations. In accordance with GAAP, the Company recorded a
tax benefit on our loss from continuing operations, which was exactly offset by income tax
expense on discontinued operations. Our net deferred tax position at June 30, 2011 is not
impacted by this tax allocation.
|
|
| (4) |
Gain on sales of discontinued operations — oil and gas
. On June 28, 2011,
the Company closed on a transaction with Wapiti Oil & Gas to sell its remaining interests in
various non-core assets primarily located in Texas and Wyoming (the “2011 Wapiti Transaction”)
for gross cash proceeds of approximately $43.2 million. In accordance with accounting
standards, the Company recognized a $5.6 million gain on sale ($8.9 million gain, net of
$3.3 million of tax) for the six months ended June 30, 2011 that is reflected in discontinued
operations.
Gain on sales of discontinued operations — drilling
. In June 2011, DHS sold
substantially all of its Chapman Trucking assets for $3.3 million in proceeds and a gain of $2.9
million. Proceeds were used to reduce DHS bank debt.
|
12
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(5) DHS Drilling
The carrying value of DHS’s drilling rigs and related equipment is assessed for impairment whenever
circumstances indicate an impairment may exist. No such impairment provisions were recorded during
the three and six months ended June 30, 2011 and 2010.
In January 2010, DHS entered into a daywork drilling contract with Desarrollos y Perforaciones De
Mexico (“DPM”) to drill geothermal wells for the benefit of the Mexican national electric company
(“CFE”) in the state of Puebla. The rig was released in July after drilling two wells. A total of
$3.7 million has been invoiced to DPM for the project with $1.6 million being collected to date.
The balance of $2.1 million has been reserved as a doubtful account due to concerns regarding
collection, which is included as a component of assets held for sale — DHS subsidiary. Legal
action is being taken to collect the amount owed to DHS and the rig is currently under contract.
Installments Payable on Property Acquisition
On February 28, 2008, the Company closed a transaction with EnCana to jointly develop a portion of
EnCana’s leasehold in the Vega Area of the Piceance Basin. The remaining installment payable due in
November 2011 is recorded in the accompanying consolidated financial statements as a current
liability at a discounted value. The discount is being accreted on the effective interest method
over the term of the installments, including accretion of $600,000 and $1.3 million for the three
months ended June 30, 2011 and 2010, respectively, and accretion of $1.3 million and $2.5 million
for the six months ended June 30, 2011 and 2010, respectively.
7% Senior Unsecured Notes, due 2015
On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate principal amount
of $150.0 million. The Company was in compliance with the covenants under the indenture as of June
30, 2011 (See Note 13, “Guarantor Financial Information”). The fair value of the Company’s senior
unsecured notes at June 30, 2011 was approximately $114.0 million.
3
3
/
4
% Senior Convertible Notes, due 2037
On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3
3
/
4
% Senior
Convertible Notes due 2037 for net proceeds of $111.6 million after underwriters’ discounts and
commissions of approximately $3.4 million. The convertible notes will mature on May 1, 2037 unless
earlier converted, redeemed or repurchased, but each holder of convertible notes has the option to
require the Company to purchase any outstanding convertible notes on each of May 1, 2012, May 1,
2017, May 1, 2022, May 1, 2027 and May 1, 2032 at a price equal to 100% of the principal amount of
the convertible notes to be purchased, payable in cash. The convertible notes were recorded based
on the estimated fair value of the liability component and the equity component. The debt discount
on the liability component is accreted over the expected life of the convertible notes, including
$1.2 million and $1.1 million of accretion for the three months ended June 30, 2011 and 2010,
respectively, and $2.4 million and $2.3 million of accretion for the six months ended June 30, 2011
and 2010, respectively. Combined with the amortization of debt discount, the convertible notes had
an effective interest rate of approximately 7.9% and 7.7% with total interest costs of $2.3 million
and $2.2 million for the three months ended June 30, 2011 and 2010, respectively, and interest
costs of $4.5 million and $4.4 million for the six months ended June 30, 2011 and 2010,
respectively. The fair value of the convertible notes at June 30, 2011 was approximately $102.4
million.
13
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(6) Long Term Debt, Continued
Credit Facility — Delta
On December 29, 2010, the Company entered into the MBL Credit Agreement, which provides for a
revolving loan and a term loan, each with a maturity date of January 31, 2012. As a combined
result of amendments on March 14, 2011 to increase the amount available under the term loan and
June 28, 2011 to reduce the borrowing base for the revolving loan and reduce the amount available
under the term loan in conjunction with the divestiture of assets, the revolving loan currently has
a borrowing base of $18.0 million and the term loan is limited to $15.0 million. The revolving
loan bears interest at prime plus 6% per annum for prime rate advances and LIBOR plus 7% per annum
for LIBOR advances, while the term loan bears interest at prime plus 9.5% through September 30,
2011 and prime plus 11.0% thereafter for prime rate advances and at LIBOR plus 10.5% for LIBOR
advances through September 30, 2011 and LIBOR plus 12.0% thereafter for LIBOR advances. The March
14, 2011 amendment removed the requirement that advances under the term loan be subject to approval
of a development plan. In addition, so long as Delta is not in default under the MBL Credit
Agreement, Delta is not required to comply with certain cash management provisions, including the
previous requirement to repay any term loan advances outstanding on a monthly basis with 100% of
net operating cash flows.
At June 30, 2011, zero was outstanding under the revolving loan and $15.0 million was outstanding
under the term loan. The revolving loan and the term loan are subject to quarterly financial
covenants, in each case as defined in the MBL Credit Agreement and described in summary here,
including maintenance of a minimum current ratio of 1:1, minimum quarterly net operating cash flow
of $8.6 million, and maximum quarterly general and administrative expenses (excluding equity based
compensation) of $5.0 million.
In addition, the Company may not permit its trade payables to be outstanding more than 90 days
following the receipt of applicable invoices. At June 30, 2011, the Company was in compliance with
its financial covenants under the MBL Credit Agreement, as adjusted
by the lender for certain one-time effects of the 2011 Wapiti
Transaction.
Credit Facility — DHS
DHS did not pay its scheduled principal and interest payments due on January 3, April 1, and July
1, 2011 and as a result, entered into a forbearance agreement, as amended, that currently expires
on August 8, 2011. In conjunction with the forbearance agreement, the January 3 and April 1
missed interest payments were capitalized to the principal balance of the loan on April 1, 2011 and
the July 1 interest payment was capitalized to the principal balance of the loan on July 1, 2011,
and the loan now bears interest at the default rate of 11% per annum. The DHS credit agreement
financial covenants require a minimum EBITDA of $1.5 million per quarter and a capital expenditures
limitation of $1.2 million for any fiscal quarter and $2.3 million in the aggregate for fiscal year
2011. DHS was not in compliance with its minimum EBITDA covenant and capital expenditures
limitation for the six months ended June 30, 2011. The DHS credit facility debt of $69.9 million
at June 30, 2011 is included in the accompanying consolidated balance sheets as a component of
liabilities related to assets held for sale. The DHS credit facility is non-recourse to Delta.
14
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(7) Fair Value Measurements
The Company follows accounting guidance which defines fair value, establishes a framework for
measuring fair value in generally accepted accounting principles, and requires additional
disclosures about fair value measurements. As required, the Company applied the following fair
value hierarchy:
Level 1 — Assets or liabilities for which the item is valued based on quoted prices
(unadjusted) for identical assets or liabilities in active markets.
Level 2 — Assets or liabilities valued based on observable market data for similar
instruments.
Level 3 — Assets or liabilities for which significant valuation assumptions are not readily
observable in the market; instruments valued based on the best available data, some of which
is internally-developed, and considers risk premiums that a market participant would
require.
The level in the fair value hierarchy within which the fair value measurement in its entirety falls
shall be determined based on the lowest level input that is significant to the fair value
measurement in its entirety.
Derivative liabilities consist of future oil, gas, and natural gas liquids commodity swap contracts
valued using both quoted prices for identically traded contracts and observable market data for
similar contracts (NYMEX WTI oil, CIG gas, and Mont Belvieu natural gas liquids swaps — Level 2).
Proved property impairments —
The fair values of the proved properties are estimated using internal
discounted cash flow calculations based upon the Company’s estimates of reserves and are considered
to be level three fair value measurements.
Asset retirement obligations —
The initial fair values of the asset retirement obligations are
estimated using internal discounted cash flow calculations based upon the Company’s asset
retirement obligations, including revisions of the estimated fair values during the six months
ended June 30, 2011 and 2010, and are considered to be Level 3 fair value measurements.
The following table lists the Company’s fair value measurements by hierarchy as of June 30, 2011
and December 31, 2010 (in thousands):
| Fair Value Measurements | ||||||||||||||||
| Quoted Prices | Significant | Significant | ||||||||||||||
| in Active Markets | Other Observable | Unobservable | ||||||||||||||
| for Identical Assets | Inputs | Inputs | ||||||||||||||
| Assets (Liabilities) | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
|
|
||||||||||||||||
|
Recurring
|
||||||||||||||||
|
Derivative liabilities — June 30, 2011
|
$ | — | $ | (5,605 | ) | $ | — | $ | (5,605 | ) | ||||||
|
Derivative liabilities — December 31, 2010
|
— | (2,993 | ) | — | (2,993 | ) | ||||||||||
15
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(8) Commodity Derivative Instruments
The Company periodically enters into commodity price risk transactions to manage its exposure to
oil, gas, and natural gas liquids price volatility. These transactions may take the form of
futures contracts, collar agreements, swaps or options. The purpose of the transactions is to
provide a measure of stability to the Company’s cash flows in an environment of volatile oil and
gas prices. The Company has not elected hedge accounting and recognizes mark-to-market gains and
losses in earnings currently.
The Company is exposed to the fluctuations in natural gas, natural gas liquids, or crude oil prices
due to the nature of business in which the Company is primarily involved. In order to mitigate the
risks associated with uncertain cash flows from volatile commodity prices and to provide stability
and predictability in the Company’s future revenues, the Company periodically enters into commodity
price risk management transactions to manage its exposure to gas and oil price volatility.
On June 28, 2011, as required by the amendment to the MBL Credit Agreement completed in conjunction
with the 2011 Wapiti Transaction, the Company paid $3.3 million cash to settle a portion of its oil
derivative contracts outstanding from July 2011 to December 2013. The table below reflects the
remaining open derivative contracts after consideration of this early termination.
At June 30, 2011, all of the Company’s outstanding derivative contracts were fixed price swaps.
Under the swap agreements, the Company receives the fixed price and pays the floating index price.
The Company’s swaps are settled in cash on a monthly basis. By entering into swaps, the Company
effectively fixes the price that it will receive for a portion of its production.
The following table summarizes the Company’s open derivative contracts at June 30, 2011:
| Net Fair Value | ||||||||||||||
| Remaining | Asset (Liability) at | |||||||||||||
| Commodity | Volume | Fixed Price | Term | Index Price | June 30, 2011 | |||||||||
| (In thousands) | ||||||||||||||
|
|
||||||||||||||
|
Crude oil
|
192 Bbls / Day | $ | 57.70 | Jul ’11 - Dec ’11 | NYMEX – WTI | $ | (1,307 | ) | ||||||
|
Crude oil
|
79 Bbls / Day | $ | 91.05 | Jul ’11 - Dec ’11 | NYMEX – WTI | (68 | ) | |||||||
|
Crude oil
|
230 Bbls / Day | $ | 91.05 | Jan ’12 - Dec ’12 | NYMEX – WTI | (632 | ) | |||||||
|
Crude oil
|
162 Bbls / Day | $ | 91.05 | Jan ’13 - Dec ’13 | NYMEX – WTI | (444 | ) | |||||||
|
Natural gas
|
12,000 MMBtu / Day | $ | 5.150 | Jul ’11 - Dec ’11 | CIG | 2,064 | ||||||||
|
Natural gas
|
3,253 MMBtu / Day | $ | 5.040 | Jul ’11 - Dec ’11 | CIG | 494 | ||||||||
|
Natural gas
|
12,052 MMBtu / Day | $ | 4.440 | Jan ’12 - Dec ’12 | CIG | (66 | ) | |||||||
|
Natural gas
|
10,301 MMBtu / Day | $ | 4.440 | Jan ’13 - Dec ’13 | CIG | (890 | ) | |||||||
|
Natural gas liquids
(1)
|
35,406 Gallons / Day | $ | 0.913 | Jul ’11 - Dec ’11 | MT. BELVIEU | (1,698 | ) | |||||||
|
Natural gas liquids
(1)
|
30,617 Gallons / Day | $ | 0.832 | Jan ’12 - Dec ’12 | MT. BELVIEU | (2,317 | ) | |||||||
|
Natural gas liquids
(1)
|
12,286 Gallons / Day | $ | 0.767 | Jan ’13 - Dec ’13 | MT. BELVIEU | (741 | ) | |||||||
|
|
||||||||||||||
|
|
$ | (5,605 | ) | |||||||||||
|
|
||||||||||||||
| (1) |
Natural gas liquids includes purity ethane, propane, natural gasoline,
normal butane and isobutene derivatives and the weighted average price is used.
|
The pre-credit risk adjusted fair value of the Company’s net derivative liabilities as of
June 30, 2011 was $6.9 million. A credit risk adjustment of $1.3 million to the fair value of the
derivatives increased the reported amount of the net derivative liabilities on the Company’s
consolidated balance sheet to $5.6 million.
16
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(8) Commodity Derivative Instruments, Continued
The Company classifies the fair value amounts of derivative assets and liabilities executed under
master netting arrangements as net derivative assets or net derivative liabilities, whichever the
case may be, by commodity and master netting counterparty. The following table summarizes the fair
values and location in the Company’s consolidated balance sheet of all derivatives held by the
Company as of June 30, 2011 and December 31, 2010 (in thousands):
| Derivatives Not Designated as | June 30, 2011 | Dec. 31, 2010 | ||||||||
| Hedging Instruments | Balance Sheet Classification | Fair Value | Fair Value | |||||||
|
Liabilities
|
||||||||||
|
Commodity Swaps
|
Derivative Instruments – Current Liabilities, net | $ | (2,123 | ) | $ | (574 | ) | |||
|
Commodity Swaps
|
Derivative Instruments – Long-Term Liabilities, net | (3,482 | ) | (2,419 | ) | |||||
|
|
||||||||||
|
Total
|
$ | (5,605 | ) | $ | (2,993 | ) | ||||
|
|
||||||||||
The following table summarizes the realized and unrealized gains and losses and the
classification in the consolidated statement of operations of derivatives not designated as hedging
instruments for the six months ended June 30, 2011 and 2010 (in thousands):
| June 30, 2011 | June 30, 2010 | |||||||||
| Amount of | Amount of Gain | |||||||||
| Loss Recognized | (Loss) Recognized | |||||||||
| Derivatives Not Designated as | Location of Gain (Loss) Recognized in | in Income | in Income | |||||||
| Hedging Instruments | Income on Derivatives | on Derivatives | on Derivatives | |||||||
|
Commodity Swaps
|
Realized Loss on Derivative Instruments, net – Other Income and (Expense) | $ | (5,450 | ) | $ | (4,714 | ) | |||
|
Commodity Swaps
|
Unrealized Gain (Loss) on Derivative Instruments, net – Other Income and (Expense) | (2,612 | ) | 20,948 | ||||||
|
|
||||||||||
|
|
$ | (8,062 | ) | $ | 16,234 | |||||
|
|
||||||||||
(9) Commitments and Contingencies
Convertible Notes — Right of Repurchase
The $115.0 million in principal amount of 3
3
/
4
% Senior Convertible Notes due 2037 will mature on May
1, 2037 unless earlier converted, redeemed or repurchased. The holders of the Notes have the right
to require the Company to purchase all or a portion of the Notes on May 1, 2012, May 1, 2017, May
1, 2022, May 1, 2027, and May 1, 2032 at a price which is required to be paid in cash, equal to
100% of the principal amount of the Notes to be repurchased.
Decommissioning of Offshore California Leases
The Company formerly owned a 2.41934% working interest in OCS Lease 320 in the Sword Unit, Offshore
California, and its 91.68% owned subsidiary, Amber Resources Company of Colorado (“Amber”) formerly
owned a 0.97953% working interest in the same lease. Lease 320 was conveyed back to the United
States at the conclusion of litigation with the government (
Amber Resources Co., et al. vs. United
States,
Civ. Act. No. 2-30 filed in the United States Court of Federal Claims) when the courts
determined that the government had breached that lease (among others) and was liable to the working
interest owners for damages; however, the government now contends that the former working interest
owners are still obligated to permanently plug and abandon an exploratory well that was drilled on
the lease and to clear the well site. The former operator of the lease commenced litigation
against the government in United States District Court for the District of Columbia (
Noble Energy
Corp. vs. Kenneth L. Salazar, Secretary United States Department of the Interior, et al
No.
1:09-cv-02013-EGS) seeking a declaratory judgment that the former working interest owners are not
responsible for these costs as a result of the government’s breach of the lease. On April 22,
2011, the Court entered a judgment in favor of the government, ruling that the working interest
owners jointly and severally share the responsibility to permanently plug and abandon the subject
well, and that this duty was not
discharged by the government’s breach of contract. On May 11, 2011, the former operator filed an
appeal of this ruling to the United States Court of Appeals for the District of Columbia Circuit.
It is currently unknown whether or not the appeal will be successful, or what the actual costs of
decommissioning the well would be if the former working interest owners are ultimately held liable.
If the working interest owners are held liable, the Company and Amber would be responsible for the
payment of their respective proportionate shares of the cost.
17
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(9) Commitments and Contingencies, Continued
In addition, the Company formerly owned a 24.21692% interest in Lease 409 (Non-unitized), a
5.88682% interest in Lease 415 (Point Sal) and a 7.03049% interest in Lease 416 (Point Sal), all of
which are located offshore California in the Santa Maria Basin and were assigned back to the
government at the conclusion of the Amber litigation discussed above. These leases were operated
by a different operator who has commissioned a site clearance study for the decommissioning of
operations on the affected leases, but has reserved the right to possibly later take the position
that there is no obligation to engage in decommissioning efforts for specified legal and/or
regulatory reasons. It is currently unknown whether or not decommissioning efforts will ultimately
be undertaken, or what the associated costs would be.
212 Resources
In the fiscal quarter ended March 31, 2011, the Company was engaged in an arbitration with 212
Resources Corporation (“212”) that was filed with the American Arbitration Association on October
27, 2009. The matter was settled pursuant to a final Settlement Agreement executed by the parties
on January 25, 2011. In accordance with the Settlement Agreement, the Company paid $1.5 million to
212 in consideration of mutual releases of claims and the termination of the underlying agreement.
DHS Rig Matter
The Company’s indirect, 49.8% owned affiliate DHS and certain of its employees, among others, have
been notified by the Office of the Inspector General, Office of Investigations, of the
Export-Import Bank of the United States, and the U.S. Department of Justice, that DHS and certain
of its and the Company’s employees are the subject of an investigation in connection with a loan
guarantee sought from the Export-Import Bank in the first quarter of 2010 of a loan from a Mexican
bank sought by a DHS customer in Mexico. DHS has cooperated and will continue to cooperate with the
investigation. This investigation is subject to uncertainties, and, as such, DHS is unable to
estimate the nature of any possible liability that may result. There has been no communication with
the government regarding this matter since February 10, 2011.
(10) Stockholders’ Equity
Preferred Stock
The Company has 3.0 million shares of preferred stock authorized and issuable from time to time in
one or more series. As of June 30, 2011 and December 31, 2010, no shares of preferred stock were
outstanding.
Common Stock
On July 12, 2011, the shareholders of the Company approved a one-for-ten reverse split of the
common stock of the Company which became effective on July 13, 2011. All references in these
financial statements to the number of common shares or options, price per share and weighted
average number of common shares outstanding prior to the 1:10 reverse stock split have been
adjusted to reflect this stock split on a retroactive basis, unless otherwise noted.
Also on July 12, 2011, the shareholders of the Company approved an amendment to the Company’s
Amended and Restated Certificate of Incorporation to reduce the number of authorized shares of
common stock to 200,000,000 from 600,000,000 shares. Presentation of authorized shares of common
stock has been adjusted on a retroactive basis.
18
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(10) Stockholders’ Equity, Continued
During the three months ended March 31, 2011 and 2010, the Company issued 98,800 and 48,078 fully
vested shares to the non-employee members of the Board of Directors in consideration for their
service on the Board for the years ended December 31, 2010 and 2009, respectively. On June 10,
2011, the Company granted 3,308 fully vested shares in conjunction with the resignation of a member
of the Board of Directors in consideration for service in 2011 through the date of his resignation.
On June 21, 2011, the Company granted 489,227 shares of non-vested common stock to certain
employees. The shares vest in full on the earlier of a change in control or July 1, 2012. In
conjunction with this grant, the Company agreed to establish a “floor” price for the value of the
shares on the date of vesting equal to the value of the shares on the grant date ($5.50 per share).
In the event that the market price of the shares on the date of vesting is lower than the floor
price on the date of vesting, the difference will be paid to the employees in cash. The
compensation expense for the shares consists of a fixed equity component ($5.50 per share) and a
variable liability component (based on the difference between the market price of the shares, if
lower, and the floor price of the shares), both of which are included as a component of general and
administrative expense in the accompanying consolidated statements of operations.
Stock Based Compensation
The Company recognized stock compensation included in general and administrative expense as follows
(in thousands):
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
|
Non-vested stock
(1)
|
$ | 2,346 | $ | 3,105 | $ | 4,610 | $ | 6,136 | ||||||||
|
Performance shares
|
49 | 358 | 152 | 716 | ||||||||||||
|
|
||||||||||||||||
|
Total
|
$ | 2,395 | $ | 3,463 | $ | 4,762 | $ | 6,852 | ||||||||
|
|
||||||||||||||||
| (1) |
Non-vested stock includes $48,000 and $182,000 for the three months ended
June 30, 2011 and 2010, respectively, and $96,000 and $363,000 for the six months ended June
30, 2011 and 2010, respectively, that relates to DHS which is included as a component of
discontinued operations in the accompanying consolidated statements of operations.
|
The Company recognizes the cost of share based payments over the period during which the
employee provides service. Exercise prices for options outstanding under the Company’s various
plans as of June 30, 2011 ranged from $7.90 to $153.40 per share. At June 30, 2011, there was no
unrecognized compensation cost related to stock options as all outstanding options are vested. At
June 30, 2011, the Company had 150,300 options outstanding at a weighted average exercise price of
$75.00 per share. At June 30, 2011, the Company had 1,211,902 non-vested shares outstanding and no
performance shares outstanding. At June 30, 2011, the total unrecognized compensation cost related
to the performance shares and the non-vested portion of restricted stock was $4.9 million which is
expected to be recognized over a weighted average period of 0.6 years.
19
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(11) Income Taxes
Income tax expense (benefit) attributable to loss from continuing operations was approximately
($3.9) million and $203,000 for the three months ended June 30, 2011 and 2010, respectively, and
($4.6) million and $478,000 for the six months ended June 30, 2011 and 2010, respectively. Also
included in the three months ended June 30, 2011 was a current tax benefit related to a tax refund
received as a result of a tax law change that allowed us to carry-back operating losses to a period
in which we previously paid tax.
In assessing the realizability of deferred tax assets, management considers whether it is more
likely than not that some portion or all of the deferred tax assets will not be realized. The
ultimate realization of deferred tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities, projected future results of
operations, and tax planning strategies in making this assessment. Based upon the level of
historical taxable income, significant book losses during the current and prior periods, and
projections for future results of operations over the periods in which the deferred tax assets are
deductible, among other factors, management continues to conclude that the Company does not meet
the “more likely than not” requirement of ASC 740 in order to recognize deferred tax assets and a
valuation allowance has been recorded for the Company’s net deferred tax assets at June 30, 2011.
During the three months ended June 30, 2011 and 2010, DHS recorded net operating losses and as of
June 30, 2011 DHS’s deferred tax assets exceeded its deferred tax liabilities. Accordingly, based
on significant recent operating losses and projections for future results, a valuation allowance
was recorded for DHS’s net deferred tax assets.
For the three and six months ended June 30, 2011, the Company recorded a tax benefit of $3.9
million and $4.8 million, respectively, due to a non-cash income tax benefit related to gains from
discontinued oil and gas operations. Generally accepted accounting principles, or GAAP, require all
items be considered, including items recorded in discontinued operations, in determining the amount
of tax benefit that results from a loss from continuing operations that should be allocated to
continuing operations. In accordance with GAAP, the Company recorded a tax benefit on its loss from
continuing operations, which was exactly offset by income tax expense on discontinued operations.
The Company’s net deferred tax position at June 30, 2011 is not impacted by this tax allocation.
During the remainder of 2011 and thereafter, the Company will continue to assess the realizability
of its deferred tax assets based on consideration of actual and projected operating results and tax
planning strategies. Should actual operating results improve, the amount of the deferred tax asset
considered more likely than not to be realizable could be increased. Such a change in the
assessment of realizability could result in a decrease to the valuation allowance and corresponding
income tax benefit, both of which could be significant.
During the three and six months ended June 30, 2011 and 2010, no adjustments were recognized for
uncertain tax benefits.
20
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(12) Earnings Per Share
The following table sets forth the computation of basic and diluted earnings per share (in
thousands, except per share amounts):
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
|
|
||||||||||||||||
|
Net loss attributable to Delta
common stockholders
|
$ | (963 | ) | $ | (149,750 | ) | $ | (28,803 | ) | $ | (162,547 | ) | ||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Basic weighted-average common shares outstanding
|
27,873 | 27,583 | 27,878 | 27,565 | ||||||||||||
|
Add: dilutive effects of stock options and
unvested stock grants
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Diluted weighted-average common shares outstanding
|
27,873 | 27,583 | 27,878 | 27,565 | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Net loss per common share attributable to
Delta common stockholders
|
||||||||||||||||
|
Basic
|
$ | (0.03 | ) | $ | (5.43 | ) | $ | (1.03 | ) | $ | (5.90 | ) | ||||
|
|
||||||||||||||||
|
Diluted
|
$ | (0.03 | ) | $ | (5.43 | ) | $ | (1.03 | ) | $ | (5.90 | ) | ||||
|
|
||||||||||||||||
Potentially dilutive securities excluded from the calculation of diluted shares outstanding
include the following (in thousands):
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
|
Stock issuable upon conversion of convertible notes
|
379 | 379 | 379 | 379 | ||||||||||||
|
Stock options
|
150 | 143 | 150 | 143 | ||||||||||||
|
Performance share grants
(1)
|
— | 15 | — | 15 | ||||||||||||
|
Non-vested restricted stock
|
1,212 | 672 | 1,212 | 672 | ||||||||||||
|
|
||||||||||||||||
|
Total potentially dilutive securities
|
1,741 | 1,209 | 1,741 | 1,209 | ||||||||||||
|
|
||||||||||||||||
| (1) |
During the three months ended June 30, 2011, the two remaining holders of
the performance shares returned to the Company for no additional consideration the 8,000
unvested performance shares remaining at the time.
|
21
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(13) Guarantor Financial Information
On March 15, 2005, Delta issued $150.0 million of 7% senior notes that mature in 2015. In addition,
on April 25, 2007, the Company issued $115.0 million of 3
3
/
4
% convertible senior notes due in 2037.
Both the senior notes and the convertible notes are guaranteed by all of the Company’s wholly-owned
subsidiaries. Each of the guarantors, fully, jointly and severally, irrevocably and
unconditionally guarantees the performance and payment when due of all the obligations under the
senior notes and the convertible notes. DHS, CRBP, and Amber are not guarantors of the indebtedness
under the senior notes or the convertible notes.
The following financial information sets forth the Company’s condensed consolidated balance sheets
as of June 30, 2011 and December 31, 2010, the condensed consolidated statements of operations for
the three and six months ended June 30, 2011 and 2010 and the condensed consolidated statements of
cash flows for the six months ended June 30, 2011 and 2010. For purposes of the condensed financial
information presented below, the equity in the earnings or losses of subsidiaries is not recorded
in the financial statements of the issuer.
June 30, 2011
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
|
||||||||||||||||||||
|
Current assets
|
$ | 116,297 | $ | 311 | $ | 67,595 | $ | — | $ | 184,203 | ||||||||||
|
|
||||||||||||||||||||
|
Property and equipment:
|
||||||||||||||||||||
|
Oil and gas properties
|
905,597 | — | 19,215 | — | 924,812 | |||||||||||||||
|
Other
|
73,638 | 32,638 | — | — | 106,276 | |||||||||||||||
|
|
||||||||||||||||||||
|
Total property and equipment
|
979,235 | 32,638 | 19,215 | — | 1,031,088 | |||||||||||||||
|
|
||||||||||||||||||||
|
Accumulated depletion and depreciation
|
(218,715 | ) | (28,723 | ) | — | — | (247,438 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net property and equipment
|
760,520 | 3,915 | 19,215 | — | 783,650 | |||||||||||||||
|
|
||||||||||||||||||||
|
Investment in subsidiaries
|
85 | — | — | (85 | ) | — | ||||||||||||||
|
Other long-term assets
|
5,585 | 2,407 | — | — | 7,992 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total assets
|
$ | 882,487 | $ | 6,633 | $ | 86,810 | $ | (85 | ) | $ | 975,845 | |||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Current liabilities
|
$ | 256,559 | $ | (28 | ) | $ | 76,112 | $ | — | $ | 332,643 | |||||||||
|
|
||||||||||||||||||||
|
Long-term liabilities:
|
||||||||||||||||||||
|
Long-term debt, derivative instruments
and deferred taxes
|
151,403 | 1,801 | — | — | 153,204 | |||||||||||||||
|
Asset retirement obligations
|
3,299 | — | — | — | 3,299 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total long-term liabilities
|
154,702 | 1,801 | — | — | 156,503 | |||||||||||||||
|
|
||||||||||||||||||||
|
Total Delta stockholders’ equity
|
474,968 | 4,860 | 10,698 | (85 | ) | 490,441 | ||||||||||||||
|
|
||||||||||||||||||||
|
Non-controlling interest
|
(3,742 | ) | — | — | — | (3,742 | ) | |||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total equity
|
471,226 | 4,860 | 10,698 | (85 | ) | 486,699 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total liabilities and equity
|
$ | 882,487 | $ | 6,633 | $ | 86,810 | $ | (85 | ) | $ | 975,845 | |||||||||
|
|
||||||||||||||||||||
22
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(13) Guarantor Financial Information, Continued
Condensed Consolidated Balance Sheet
December 31, 2010
December 31, 2010
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
|
|
||||||||||||||||||||
|
Current assets
|
$ | 164,377 | $ | 322 | $ | 75,069 | $ | — | $ | 239,768 | ||||||||||
|
|
||||||||||||||||||||
|
Property and equipment:
|
||||||||||||||||||||
|
Oil and gas properties
|
881,886 | — | 19,215 | (118 | ) | 900,983 | ||||||||||||||
|
Other
|
74,438 | 32,677 | — | — | 107,115 | |||||||||||||||
|
|
||||||||||||||||||||
|
Total property and equipment
|
956,324 | 32,677 | 19,215 | (118 | ) | 1,008,098 | ||||||||||||||
|
|
||||||||||||||||||||
|
Accumulated depletion, depreciation
and amortization
|
(203,731 | ) | (28,762 | ) | — | — | (232,493 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net property and equipment
|
752,593 | 3,915 | 19,215 | (118 | ) | 775,605 | ||||||||||||||
|
|
||||||||||||||||||||
|
Investment in subsidiaries
|
1,156 | — | — | (1,156 | ) | — | ||||||||||||||
|
Other long-term assets
|
6,332 | 2,407 | — | — | 8,739 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total assets
|
$ | 924,458 | $ | 6,644 | $ | 94,284 | $ | (1,274 | ) | $ | 1,024,112 | |||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Current liabilities
|
$ | 138,375 | $ | (26 | ) | $ | 81,633 | $ | — | $ | 219,982 | |||||||||
|
|
||||||||||||||||||||
|
Long-term liabilities
|
||||||||||||||||||||
|
Long-term debt, derivative instruments
and deferred taxes
|
288,025 | 1,801 | — | — | 289,826 | |||||||||||||||
|
Asset retirement obligation and other
liabilities
|
2,709 | — | — | — | 2,709 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total long-term liabilities
|
290,734 | 1,801 | — | — | 292,535 | |||||||||||||||
|
|
||||||||||||||||||||
|
Total Delta stockholders’ equity
|
498,201 | 4,869 | 12,651 | (1,274 | ) | 514,447 | ||||||||||||||
|
|
||||||||||||||||||||
|
Non-controlling interest
|
(2,852 | ) | — | — | — | (2,852 | ) | |||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total equity
|
495,349 | 4,869 | 12,651 | (1,274 | ) | 511,595 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total liabilities and equity
|
$ | 924,458 | $ | 6,644 | $ | 94,284 | $ | (1,274 | ) | $ | 1,024,112 | |||||||||
|
|
||||||||||||||||||||
23
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(13) Guarantor Financial Information, Continued
Three Months Ended June 30, 2011
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
|
||||||||||||||||||||
|
Total revenue
|
$ | 16,882 | $ | — | $ | — | $ | — | $ | 16,882 | ||||||||||
|
|
||||||||||||||||||||
|
Operating expenses:
|
||||||||||||||||||||
|
Oil and gas expenses
|
7,799 | — | — | — | 7,799 | |||||||||||||||
|
Exploration expense
|
233 | — | — | — | 233 | |||||||||||||||
|
Dry hole costs and impairments
|
367 | (94 | ) | — | — | 273 | ||||||||||||||
|
Depreciation and depletion
|
10,528 | — | — | — | 10,528 | |||||||||||||||
|
General and administrative
|
6,424 | 21 | 26 | — | 6,471 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total operating expenses
|
25,351 | (73 | ) | 26 | — | 25,304 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Operating income (loss)
|
(8,469 | ) | 73 | (26 | ) | — | (8,422 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
Other income and (expense)
|
(4,314 | ) | 11 | 1 | — | (4,302 | ) | |||||||||||||
|
Income tax benefit
|
3,938 | — | — | — | 3,938 | |||||||||||||||
|
Discontinued operations
|
6,698 | — | 2,622 | — | 9,320 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net income (loss)
|
(2,147 | ) | 84 | 2,597 | — | 534 | ||||||||||||||
|
|
||||||||||||||||||||
|
Net income attributable to
non-controlling interest
|
(1,497 | ) | — | — | — | (1,497 | ) | |||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net income (loss) attributable to
Delta common stockholders
|
$ | (3,644 | ) | $ | 84 | $ | 2,597 | $ | — | $ | (963 | ) | ||||||||
|
|
||||||||||||||||||||
Condensed Consolidated Statement of Operations
Three Months Ended June 30, 2010
Three Months Ended June 30, 2010
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
|
||||||||||||||||||||
|
Total revenue
|
$ | 14,713 | $ | — | $ | — | $ | — | $ | 14,713 | ||||||||||
|
|
||||||||||||||||||||
|
Operating expenses:
|
||||||||||||||||||||
|
Oil and gas expenses
|
11,212 | — | — | 11,212 | ||||||||||||||||
|
Exploration expense
|
358 | — | — | — | 358 | |||||||||||||||
|
Dry hole costs and impairments
|
24,474 | 4,805 | 586 | — | 29,865 | |||||||||||||||
|
Depreciation and depletion
|
12,140 | 2 | — | — | 12,142 | |||||||||||||||
|
General and administrative
|
10,608 | 14 | 26 | — | 10,648 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total operating expenses
|
58,792 | 4,821 | 612 | — | 64,225 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Operating loss
|
(44,079 | ) | (4,821 | ) | (612 | ) | — | (49,512 | ) | |||||||||||
|
|
||||||||||||||||||||
|
Other income and (expense)
|
(3,683 | ) | 78 | 1 | — | (3,604 | ) | |||||||||||||
|
Income tax expense
|
(203 | ) | — | — | — | (203 | ) | |||||||||||||
|
Discontinued operations
|
(35,775 | ) | 106 | (63,492 | ) | — | (99,161 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss
|
(83,740 | ) | (4,637 | ) | (64,103 | ) | — | (152,480 | ) | |||||||||||
|
|
||||||||||||||||||||
|
Less net loss attributable to
non-controlling interest
|
2,730 | — | — | — | 2,730 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss attributable to
Delta common stockholders
|
$ | (81,010 | ) | $ | (4,637 | ) | $ | (64,103 | ) | $ | — | $ | (149,750 | ) | ||||||
|
|
||||||||||||||||||||
24
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(13) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Operations
Six Months Ended June 30, 2011
Six Months Ended June 30, 2011
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
|
||||||||||||||||||||
|
Total revenue
|
$ | 34,597 | $ | — | $ | — | $ | — | $ | 34,597 | ||||||||||
|
|
||||||||||||||||||||
|
Operating expenses:
|
||||||||||||||||||||
|
Oil and gas expenses
|
15,987 | — | — | — | 15,987 | |||||||||||||||
|
Exploration expense
|
276 | — | — | — | 276 | |||||||||||||||
|
Dry hole costs and impairments
|
455 | (39 | ) | — | — | 416 | ||||||||||||||
|
Depreciation and depletion
|
22,479 | — | — | — | 22,479 | |||||||||||||||
|
General and administrative
|
13,028 | 21 | 51 | — | 13,100 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total operating expenses
|
52,225 | (18 | ) | 51 | — | 52,258 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Operating income (loss)
|
(17,628 | ) | 18 | (51 | ) | — | (17,661 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
Other income and (expenses)
|
(22,500 | ) | 11 | 2 | — | (22,487 | ) | |||||||||||||
|
Income tax benefit
|
4,633 | — | — | — | 4,633 | |||||||||||||||
|
Discontinued operations
|
8,292 | — | (2,507 | ) | — | 5,785 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net income (loss)
|
(27,203 | ) | 29 | (2,556 | ) | — | (29,730 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
Less net loss attributable to
non-controlling interest
|
927 | — | — | — | 927 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net income (loss) attributable to
Delta common stockholders
|
$ | (26,276 | ) | $ | 29 | $ | (2,556 | ) | $ | — | $ | (28,803 | ) | |||||||
|
|
||||||||||||||||||||
Condensed Consolidated Statement of Operations
Six Months Ended June 30, 2010
Six Months Ended June 30, 2010
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
|
||||||||||||||||||||
|
Total revenue
|
$ | 33,946 | $ | — | $ | — | $ | — | $ | 33,946 | ||||||||||
|
|
||||||||||||||||||||
|
Operating expenses:
|
||||||||||||||||||||
|
Oil and gas expenses
|
19,860 | — | — | — | 19,860 | |||||||||||||||
|
Exploration expense
|
584 | — | — | — | 584 | |||||||||||||||
|
Dry hole costs and impairments
|
24,828 | 4,805 | 586 | — | 30,219 | |||||||||||||||
|
Depreciation and depletion
|
23,885 | 2 | — | — | 23,887 | |||||||||||||||
|
General and administrative
|
20,800 | 29 | 69 | — | 20,898 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total operating expenses
|
89,957 | 4,836 | 655 | — | 95,448 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Operating loss
|
(56,011 | ) | (4,836 | ) | (655 | ) | — | (61,502 | ) | |||||||||||
|
|
||||||||||||||||||||
|
Other income and (expenses)
|
837 | 72 | 3 | — | 912 | |||||||||||||||
|
Income tax expense
|
(478 | ) | — | — | — | (478 | ) | |||||||||||||
|
Discontinued operations
|
(34,719 | ) | 180 | (72,865 | ) | — | (107,404 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss
|
(90,371 | ) | (4,584 | ) | (73,517 | ) | — | (168,472 | ) | |||||||||||
|
|
||||||||||||||||||||
|
Less net loss attributable to
non-controlling interest
|
5,925 | — | — | — | 5,925 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss attributable to
Delta common stockholders
|
$ | (84,446 | ) | $ | (4,584 | ) | $ | (73,517 | ) | $ | — | $ | (162,547 | ) | ||||||
|
|
||||||||||||||||||||
25
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(13) Guarantor Financial Information, Continued
Six Months Ended June 30, 2011
| Guarantor | Non-Guarantor | |||||||||||||||
| Issuer | Entities | Entities | Consolidated | |||||||||||||
|
Cash provided by (used in):
|
||||||||||||||||
|
Operating activities
|
$ | (680 | ) | $ | 1 | $ | 791 | $ | 112 | |||||||
|
Investing activities
|
5,345 | 1 | 2,647 | 7,993 | ||||||||||||
|
Financing activities
|
(14,915 | ) | — | (3,486 | ) | (18,401 | ) | |||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Net decrease in cash and
cash equivalents
|
(10,250 | ) | 2 | (48 | ) | (10,296 | ) | |||||||||
|
|
||||||||||||||||
|
Cash at beginning of the period
|
13,154 | 61 | 975 | 14,190 | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Cash at the end of the period
|
$ | 2,904 | $ | 63 | $ | 927 | $ | 3,894 | ||||||||
|
|
||||||||||||||||
Condensed Consolidated Statement of Cash Flows
Six Months Ended June 30, 2010
Six Months Ended June 30, 2010
|
|
Guarantor | Non-Guarantor | ||||||||||||||
|
|
Issuer | Entities | Entities | Consolidated | ||||||||||||
|
|
||||||||||||||||
|
Cash provided by (used in):
|
||||||||||||||||
|
Operating activities
|
$ | (37,302 | ) | $ | 51 | $ | 13,978 | $ | (23,273 | ) | ||||||
|
Investing activities
|
(8,900 | ) | (31 | ) | (3,143 | ) | (12,074 | ) | ||||||||
|
Financing activities
|
(5,378 | ) | — | (10,142 | ) | (15,520 | ) | |||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Net increase (decrease) in cash and
cash equivalents
|
(51,580 | ) | 20 | 693 | (50,867 | ) | ||||||||||
|
|
||||||||||||||||
|
Cash at beginning of the period
|
58,533 | 74 | 3,311 | 61,918 | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Cash at the end of the period
|
$ | 6,953 | $ | 94 | $ | 4,004 | $ | 11,051 | ||||||||
|
|
||||||||||||||||
26
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)
(14) Business Segments
The Company has two reportable segments: oil and gas exploration and production (“Oil and Gas”)
and drilling and trucking operations (“Drilling”) through its ownership in DHS. However, as DHS
has been reported as discontinued operations (see Note 4, “Discontinued Operations”), drilling did
not affect continuing operations and thus is excluded from the table below. Following is a summary
of segment results impacting continuing operations for the three and six months ended June 30, 2011
and 2010:
| Inter-segment | ||||||||||||||||
| Oil and Gas | Drilling | Eliminations | Consolidated | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Three Months Ended June 30, 2011
|
||||||||||||||||
|
Revenues from external customers
|
$ | 16,882 | $ | — | $ | — | $ | 16,882 | ||||||||
|
Inter-segment revenues
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Total revenues
|
$ | 16,882 | $ | — | $ | — | $ | 16,882 | ||||||||
|
|
||||||||||||||||
|
Operating loss
|
$ | (8,422 | ) | $ | — | $ | — | $ | (8,422 | ) | ||||||
|
|
||||||||||||||||
|
Other expense
(1)
|
(4,302 | ) | — | — | (4,302 | ) | ||||||||||
|
|
||||||||||||||||
|
Loss from continuing operations, before tax
|
$ | (12,724 | ) | $ | — | $ | — | $ | (12,724 | ) | ||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Three Months Ended June 30, 2010
|
||||||||||||||||
|
Revenues from external customers
|
$ | 14,713 | $ | — | $ | — | $ | 14,713 | ||||||||
|
Inter-segment revenues
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Total revenues
|
$ | 14,713 | $ | — | $ | — | $ | 14,713 | ||||||||
|
|
||||||||||||||||
|
Operating loss
|
$ | (49,512 | ) | $ | — | $ | — | $ | (49,512 | ) | ||||||
|
|
||||||||||||||||
|
Other expense
(1)
|
(3,604 | ) | — | — | (3,604 | ) | ||||||||||
|
|
||||||||||||||||
|
Loss from continuing operations, before tax
|
$ | (53,116 | ) | $ | — | $ | — | $ | (53,116 | ) | ||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Six Months Ended June 30, 2011
|
||||||||||||||||
|
Revenues from external customers
|
$ | 34,597 | $ | — | $ | — | $ | 34,597 | ||||||||
|
Inter-segment revenues
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Total revenues
|
$ | 34,597 | $ | — | $ | — | $ | 34,597 | ||||||||
|
|
||||||||||||||||
|
Operating loss
|
$ | (17,661 | ) | $ | — | $ | — | $ | (17,661 | ) | ||||||
|
|
||||||||||||||||
|
Other expense
(1)
|
(22,487 | ) | — | — | (22,487 | ) | ||||||||||
|
|
||||||||||||||||
|
Loss from continuing operations, before tax
|
$ | (40,148 | ) | $ | — | $ | — | $ | (40,148 | ) | ||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Six Months Ended June 30, 2010
|
||||||||||||||||
|
Revenues from external customers
|
$ | 33,946 | $ | — | $ | — | $ | 33,946 | ||||||||
|
Inter-segment revenues
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Total revenues
|
$ | 33,946 | $ | — | $ | — | $ | 33,946 | ||||||||
|
|
||||||||||||||||
|
Operating loss
|
$ | (61,502 | ) | $ | — | $ | — | $ | (61,502 | ) | ||||||
|
|
||||||||||||||||
|
Other income
(1)
|
912 | — | — | 912 | ||||||||||||
|
|
||||||||||||||||
|
Loss from continuing operations, before tax
|
$ | (60,590 | ) | $ | — | $ | — | $ | (60,590 | ) | ||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
June 30, 2011
|
||||||||||||||||
|
Total Assets
|
$ | 975,540 | $ | 66,704 | $ | (66,399 | ) | $ | 975,845 | |||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
December 31, 2010
|
||||||||||||||||
|
Total Assets
|
$ | 1,016,635 | $ | 74,093 | $ | (66,616 | ) | $ | 1,024,112 | |||||||
|
|
||||||||||||||||
| (1) |
Other income and expense includes interest and financing costs, realized
losses on derivative instruments, unrealized gains and losses on derivative instruments,
interest income, income and loss from unconsolidated affiliates and other miscellaneous
income. Non-controlling interests are included in inter-segment eliminations.
|
27
Table of Contents
| Item 2. |
Management’s Discussion and Analysis of Financial Condition and Results of
Operations
|
Forward Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements, within the meaning of
Section 27A of the Securities Act of 1933, as amended (“Securities Act”) and Section 21E of the
Securities Exchange Act of 1934, as amended (“Exchange Act”).
We are including the following discussion to inform our existing and potential security holders
generally of some of the risks and uncertainties that can affect us and to take advantage of the
“safe harbor” protection for forward-looking statements afforded under federal securities laws.
From time to time, our management or persons acting on our behalf make forward-looking statements
to inform existing and potential security holders about us. Forward-looking statements are
generally accompanied by words such as “estimate,” “project,” “propose,” “potential,” “predict,”
“forecast,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the
uncertainty of future events or outcomes. Except for statements of historical or present facts, all
other statements contained in this Quarterly Report on Form 10-Q are forward-looking statements.
The forward-looking statements may appear in a number of places and include statements with respect
to, among other things: business objectives and strategies, including our focus on the Vega Area of
the Piceance Basin, as well as statements regarding intended value creation; operating strategies;
anticipated use of proceeds from 2011 Wapiti Transaction; our strategic alternatives process; our
expectation that we will have adequate cash from operations, credit facility borrowings and other
capital sources to maintain current debt service obligations, capital expenditure and working
capital requirements; anticipated operating costs; potential sources of long-term capital or
potential corporate transactions such as a sale of the company; acquisition and divestiture
strategies; completion and drilling activity and timing, expectations, processes and emphasis;
expected future revenues and earnings, and results of operations; future capital, development and
exploration expenditures (including the amount and nature thereof); impact of the adoption of new
accounting standards and our financial and accounting systems and analysis programs; anticipated
compliance with and impact of laws and regulations; anticipated results and impact of litigation
and other legal proceedings; and effectiveness of our internal control over financial reporting.
These statements by their nature are subject to certain risks, uncertainties and assumptions and
will be influenced by various factors. Should any of the assumptions underlying a forward-looking
statement prove incorrect, actual results could vary materially. In some cases, information
regarding certain important factors that could cause actual results to differ materially from any
forward-looking statement appears together with such statement. In addition, the factors described
under Critical Accounting Policies and Estimates and Risk Factors, as well as other possible
factors not listed, could cause actual results to differ materially from those expressed in
forward-looking statements, including, without limitation, the following:
| • |
uncertainty regarding the outcome of our strategic alternatives process;
|
| • |
deviations in and volatility of the market prices of both crude oil and natural gas
produced by us;
|
| • |
the availability of capital on an economic basis, or at all, to fund our required
payments under our senior credit facility, the expected mandatory redemption of our
convertible notes, our working capital needs, and drilling and leasehold acquisition
programs, including through potential joint ventures and asset monetization
transactions;
|
| • |
lower natural gas and oil prices negatively affecting our ability to borrow or raise
capital, or enter into joint venture arrangements and potentially requiring accelerated
repayment of amounts borrowed under our revolving credit facility;
|
| • |
declines in the values of our natural gas and oil properties resulting in
write-downs;
|
| • |
the impact of current economic and financial conditions on our ability to raise
capital;
|
| • |
the results of exploratory drilling activities;
|
28
Table of Contents
| • |
the outcome of the investigation of DHS Drilling Company (“DHS”) and certain of its
employees, among others, by the Office of the Inspector General, Office of
Investigations, of the Export-Import Bank of the United States, and the U.S. Department
of Justice;
|
| • |
expiration of oil and natural gas leases that are not held by production;
|
| • |
uncertainties in the estimation of proved reserves and in the projection of future
rates of production;
|
| • |
timing, amount, and marketability of production;
|
| • |
third party curtailment, or processing plant or pipeline capacity constraints beyond
our control;
|
| • |
our ability to find, acquire, develop, produce and market production from new
properties;
|
| • |
the availability of borrowings under our credit facility;
|
| • |
effectiveness of management strategies and decisions;
|
| • |
the strength and financial resources of our competitors;
|
| • |
climatic conditions;
|
| • |
changes in the legal and/or regulatory environment and/or changes in accounting
standards policies and practices or related interpretations by auditors or regulatory
entities;
|
| • |
unanticipated recovery or production problems, including cratering, explosions, fires
and uncontrollable flows of oil, gas or well fluids;
|
| • |
the timing, effects and success of our acquisitions, dispositions and exploration and
development activities;
|
| • |
our ability to fully utilize income tax net operating loss and credit carry-forwards;
and
|
| • |
the ability and willingness of counterparties to our commodity derivative contracts,
if any, to perform their obligations.
|
Many of these factors are beyond our ability to control or predict. These factors are not intended
to represent a complete list of the general or specific factors that may affect us.
All forward-looking statements speak only as of the date made. All subsequent written and oral
forward-looking statements attributable to us, or persons acting on our behalf, are expressly
qualified in their entirety by the cautionary statements above. Except as required by law, we
undertake no obligation to update any forward-looking statement to reflect events or circumstances
after the date on which it is made or to reflect the occurrence of anticipated or unanticipated
events or circumstances.
We caution you not to place undue reliance on these forward-looking statements. We urge you to
carefully review and consider the disclosures made in this Form 10-Q and our reports filed with the
SEC that attempt to advise interested parties of the risks and factors that may affect our
business.
29
Table of Contents
Recent Developments
| • |
On July 25, 2011, we announced that our 2C well drilled to evaluate deep potential on our
Vega leasehold was successfully completed and brought on sales on July 21, 2011.
|
| • |
In May 2011, we retained Macquarie Tristone to provide advisory services relating to the
potential sale of certain of our non-operated assets located in the Texas Gulf Coast and DJ
Basin regions. On June 28, 2011, we closed on a transaction with Wapiti Oil & Gas, L.L.C.
(“Wapiti”) to sell our remaining interests in various non-core assets primarily located in
Texas and Wyoming (the “2011 Wapiti Transaction”) for gross cash proceeds of approximately
$43.2 million. A portion of the proceeds from the 2011 Wapiti Transaction was used to further
reduce amounts outstanding under the Company’s credit facility, and a portion will be used to
fund our planned capital development activities in the Vega Area.
|
| • |
On June 28, 2011, the MBL Credit Agreement was amended in conjunction with the 2011 Wapiti
Transaction to reduce the amounts available under the revolving and term loan portions of the
credit facility to $18.0 million and $15.0 million, respectively. In addition, as required
by the MBL Credit agreement amendment, we paid $3.3 million cash to settle a portion of our
oil derivative contracts outstanding from July 2011 to December 2013.
|
| • |
In July 2011, our Board of Directors announced that it had engaged Macquarie Capital (USA)
Inc. and Evercore Group, L.L.C. to act as advisors in conducting a strategic alternatives
process in order to maximize shareholder value and address the 2012 debt maturities. Through
this process, the Board of Directors intends to evaluate all opportunities available,
including a potential sale of the Company.
|
| • |
During the three months ended March 31, 2011, the Board of Directors of DHS, engaged
transaction advisors to commence a strategic alternatives process, focused on a sale of DHS
or substantially all of its assets. As such, in accordance with accounting standards, the
results of operations relating to DHS have been reflected as discontinued operations.
|
| • |
DHS did not pay its scheduled principal and interest payments on January 1, April 1, and
July 1, 2011 and as a result, entered into a forbearance agreement, as amended, that
currently expires on August 8, 2011. In conjunction with the forbearance agreement, the
January 3 and April 1 missed interest payments were capitalized to the principal balance of
the loan on April 1, 2011 and the July 1 interest payment was capitalized to the principal
balance of the loan on July 1, 2011, and the loan now bears interest at the default rate of
11% per annum.
|
| • |
In June 2011, DHS sold substantially all of its Chapman Trucking assets for $3.3 million
in proceeds and a gain of $2.9 million. Proceeds were used to reduce DHS bank debt.
|
2011 Overview
During the first six months of 2011, we completed three previously drilled Williams Fork wells
using Gen IV fracturing methods, continued drilling operations on our exploratory test well that
was in progress at year-end, and spud, completed and began production on a second test well in an
effort to continue to evaluate resource potential below the Williams Fork formation in the Vega
Area. A third exploratory test well below the Williams Fork was spud in mid-May and will also
serve as a lease preservation well. The completions of the remaining two previously drilled
Williams Fork wells are currently scheduled for the fourth quarter of 2011; however, these plans
could be altered depending on exploratory well results, with capital potentially being reallocated
to additional drilling activities in the Vega Area targeting the deeper shale formations. Based on
current commodity prices and our current sources of capital, we intend to continue to focus capital
expenditures for the remainder of 2011 on completing the remaining two previously drilled wells and
completing our exploratory test well in progress in order to continue to develop the Williams Fork
and to evaluate resource potential below the Williams Fork formation in the Vega Area. Although our
available capital is limited we expect it will be sufficient to allow for the funding of these
development plans. These plans may be adjusted from time to time depending on commodity prices,
exploratory well test results, capital availability or other factors.
30
Table of Contents
Liquidity and Capital Resources
Our sources of liquidity and capital resources historically have been provided through the issuance
of debt and equity securities when market conditions permit, operating activities, sales of oil and
gas properties, and through borrowings under our credit facility. The primary uses of our liquidity
and capital resources have been in the development and exploration of oil and gas properties. To
address our liquidity needs, we sold certain non-core assets to Wapiti for $130.0 million in 2010
(the “2010 Wapiti Transaction”). In 2011, we closed the 2011 Wapiti Transaction, pursuant to which
we sold our remaining interests in various non-core assets primarily located in Texas and Wyoming
for gross cash proceeds of approximately $43.2 million.
We believe that the amounts available under our credit facility, as amended, combined with our net
cash from operating activities, will provide us with sufficient funds to fund our planned operating
expenses and capital development activities described herein and maintain current debt service
obligations through the end of 2011. Significant changes in operating cash flow, drilling and
completion costs, or capital development decisions could impact remaining liquidity and cause
violations under our credit facility. As discussed above, our 2011 capital expenditure program, and
in particular our drilling and completion capital budget for the Vega Area, is dependent on the
results of our drilling and completion activities on the Vega Area exploratory test wells that are
currently underway.
To support our future capital expenditure program, and in order to address the January 2012
maturity of our credit facility and the potential mandatory redemption in May 2012 of our $115.0
million convertible notes, we will need to seek sources of long-term capital (including the
issuance of equity, debt instruments, sales of assets and joint venture financing), as well as
consider other potential corporate transactions including, potentially, the sale of the Company.
As discussed, we have announced and are pursuing a strategic alternatives process in that regard.
The timing, structure, terms, size, and pricing of any such financing or transaction will depend on
investor interest and market conditions, as well as our drilling and completion results, and there
can be no assurance that we will be able to obtain any such financing or consummate any such
transaction, and if so, that it will be on terms satisfactory to the Company.
Our Credit Facility
On December 29, 2010, we entered into the MBL Credit Agreement pursuant to which the former lenders
assigned their interests to MBL. As a combined result of amendments on March 14, 2011 to increase
the amount available under the term loan and June 28, 2011 to reduce the borrowing base for the
revolving loan and reduce the amount available under the term loan in conjunction with the
divestiture of assets, the revolving loan currently has a borrowing base of $18.0 million and the
term loan is limited to $15.0 million. At June 30, 2011, zero was outstanding under the revolving
loan and $15.0 million was outstanding under the term loan. We were in compliance with our
financial covenants under our credit facility at June 30, 2011.
DHS Credit Facility
At June 30, 2011, DHS remained out of compliance with the debt covenants under its credit facility
and is currently subject to a forbearance agreement, as amended, with LCPI which currently expires
on August 8, 2011. The DHS credit facility matures on August 31, 2011 and, as such, all amounts
outstanding under the DHS credit facility are classified as a current liability in the accompanying
consolidated balance sheet as of June 30, 2011 as a component of liabilities related to assets held
for sale. Accordingly, DHS has an immediate debt obligation in an amount in excess of its existing
sources of liquidity when the forbearance agreement expires. DHS is in discussions with its credit
facility lender regarding further amendments, waivers or other restructuring of the credit
facility, but there can be no assurance that the lender will agree to any such amendments. In
addition, during the first quarter of 2011, the Board of Directors of DHS engaged transaction
advisors to commence a strategic alternatives process, focused on a sale of the company or
substantially all of its assets. There can be no assurance that the terms offered by a potential
buyer, if any, will be acceptable to the DHS shareholders. Additionally, the consummation of
certain transactions are subject to the approval of DHS’s senior lender and the proceeds received
will be required to be used to pay down amounts outstanding under its DHS credit facility.
31
Table of Contents
Capital Resources and Requirements
Our accompanying financial statements have been prepared assuming we will continue as a going
concern. The 2010 Wapiti Transaction and the 2011 Wapiti Transaction provided capital to reduce
debt and fund our development program. However, the MBL Credit Agreement matures in January 2012
and the holders of our $115.0 million convertible notes can require us to repurchase the notes at
par on May 1, 2012. Thus, our ability to continue as a going concern will be dependent upon our
lender’s willingness to amend the terms or extend the maturity of our credit facility, the
convertible note holders’ willingness to amend or restructure the convertible notes, or our success
in generating additional sources of capital in the near future.
As of June 30, 2011, our corporate rating and senior unsecured debt rating were Caa3 and Ca,
respectively, as issued by Moody’s Investors Service. Moody’s outlook was “negative.” As of June
30, 2011, our corporate credit and senior unsecured debt ratings were CCC- and CCC-, respectively,
as issued by Standard and Poor’s (“S&P”). S&P’s outlook on its rating was “negative.”
Our future cash requirements are also largely dependent upon the number and timing of projects
included in our capital development plan, most of which are discretionary. The prices we receive
for future oil and natural gas production and the level of production have a significant impact on
our operating cash flows. Beyond the volumes for which we have entered into derivative contracts,
we are unable to predict with any degree of certainty the prices we will receive for our future oil
and gas production or the success of our exploration and development activities in generating
additional production.
Cash Flows
During the six months ended June 30, 2011, we had an operating loss of $29.7 million, net cash
provided by operating activities of $112,000, net cash provided by investing activities of $8.0
million, and net cash used by financing activities of $18.4 million. During this period we spent
$36.7 million on oil and gas development activities. At June 30, 2011, we had $3.9 million in cash
and $18.0 million available under our credit facility, total assets of $975.8 million and a debt to
capitalization ratio of 36.2%. Debt, excluding installments payable on property acquisition which
are secured by restricted cash deposits and the DHS credit facility which is non-recourse to Delta,
at June 30, 2011 totaled $275.7 million, comprised of $15.0 million of bank debt, $149.7 million of
senior subordinated notes and $111.0 million of senior convertible notes. In accordance with
applicable accounting rules, the senior convertible notes are recorded at a discount to their
stated amount due of $115.0 million.
Results of Operations
The following discussion and analysis relates to items that have affected our results of operations
for the three and six months ended June 30, 2011 and 2010. This analysis should be read in
conjunction with our consolidated financial statements and the accompanying notes thereto included
in this Form 10-Q.
Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010
Net Loss Attributable to Delta Common Stockholders.
Net loss attributable to Delta common
stockholders was $1.0 million, or $0.03 per diluted common share, for the three months ended June
30, 2011, compared to a net loss attributable to Delta common stockholders of $149.8 million, or a
loss of $5.43 per diluted common share, for the three months ended June 30, 2010. There were a
number of items affecting comparability between periods including dry hole costs and impairments,
operating expenses, and discontinued operations, among others. Explanations of significant items
affecting comparability between periods are discussed by financial statement caption below.
Oil and Gas Sales.
During the three months ended June 30, 2011, oil and gas sales increased 14%
to $16.9 million, as compared to $14.8 million for the comparable period a year earlier. The
increase was principally the result of an 8% increase in the natural gas price and a 49% increase
in the oil price. The average natural gas price received during the three months ended June 30,
2011 increased to $5.31 per Mcf compared to $4.92 per Mcf for the year earlier period. The average
oil price received during the three months ended June 30, 2011 increased to $86.87 per Bbl compared
to $58.29 per Bbl for the prior year period.
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Table of Contents
Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the three months ended
June 30, 2011 and 2010 are as follows:
| Three Months Ended | ||||||||
| June 30, | ||||||||
| 2011 | 2010 | |||||||
|
Production — Continuing Operations:
|
||||||||
|
Oil (Mbbl)
|
38 | 41 | ||||||
|
Gas (Mmcf)
|
2,550 | 2,528 | ||||||
|
Total Production (Mmcfe) — Continuing Operations
|
2,781 | 2,774 | ||||||
|
|
||||||||
|
Average Price — Continuing Operations:
|
||||||||
|
Oil (per barrel)
|
$ | 86.87 | $ | 58.29 | ||||
|
Gas (per Mcf)
|
$ | 5.31 | $ | 4.92 | ||||
|
|
||||||||
|
Costs (per Mcfe) — Continuing Operations:
|
||||||||
|
Lease operating expense
|
$ | 1.28 | $ | 2.19 | ||||
|
Transportation expense
|
$ | 1.30 | $ | 1.57 | ||||
|
Production taxes
|
$ | 0.22 | $ | 0.28 | ||||
|
Depletion expense
|
$ | 3.54 | $ | 4.03 | ||||
|
|
||||||||
|
Realized derivative losses (per Mcfe)
|
$ | (1.80 | ) | $ | (0.22 | ) | ||
Lease Operating Expense.
Lease operating expenses for the three months ended June 30, 2011
decreased to $3.6 million from $6.1 million in the prior year period primarily due to lower water
handling costs in the Vega Area as a result of the resumption of development activities and
improved water handling facilities. As a result, lease operating
expenses per Mcfe in the Vega Area declined from $2.18 per Mcfe for
the three months ended June 30, 2010 to $0.87 per Mcfe for the
three months ended June 30, 2011. Overall, lease operating
expense per Mcfe from continuing operations for the three months ended
June 30, 2011 decreased to $1.28 per Mcfe from $2.19 per Mcfe.
Transportation Expense.
Transportation expense for the three months ended June 30, 2011 decreased
to $3.6 million from $4.4 million in the prior year. Transportation expense per Mcfe for the three
months ended June 30, 2011 decreased 17% to $1.30 per Mcfe from $1.57 per Mcfe. The decrease on a
per unit basis is primarily the result of true up adjustments in the prior year.
Production Taxes.
Production taxes for the three months ended June 30, 2011 were $611,000, as
compared to prior year costs of $786,000. Production taxes as a percentage of oil and gas sales
were 3.6% and 5.3% for the three months ended June 30, 2011 and 2010, respectively.
Dry Hole Costs and Impairments.
We incurred dry hole and impairment costs of $273,000 for the
three months ended June 30, 2011 compared to $29.9 million for the comparable period a year ago.
During the three months ended June 30, 2010, dry hole and impairment costs primarily related to
unproved property impairments of $24.6 million for the Columbia River Basin, Hingeline, Howard
Ranch, Bull Canyon, Garden Gulch, Delores River and Haynesville shale prospects and a $4.8 million
impairment of our Paradox pipeline.
Depreciation, Depletion, Amortization and Accretion.
Depreciation, depletion and amortization
expense decreased 13% to $10.5 million for the three months ended June 30, 2011, as compared to
$12.1 million for the comparable year earlier period. Depletion expense for the three months ended
June 30, 2011 decreased to $9.8 million from $11.2 million for the three months ended June 30, 2010
primarily due to higher reserves as a result of our recent drilling and completion activity in the
Vega Area. Accordingly, our depletion rate decreased from $4.03 per Mcfe for the three months
ended June 30, 2010 to $3.54 per Mcfe for the current year period.
General and Administrative Expense.
General and administrative expense decreased 39% to $6.5
million for the three months ended June 30, 2011, as compared to $10.6 million for the comparable
prior year period. The decrease in general and administrative expenses is attributed to a decrease
in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as
a result of attrition and a reduction in force since the second quarter of 2010 resulting in lower
cash compensation expense.
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Table of Contents
Interest Expense and Financing Costs, Net.
Interest expense and financing costs, net increased 3%
to $8.0 million for the three months ended June 30, 2011, as compared to $7.8 million for the
comparable year earlier period. The increase is primarily related to a decrease in interest income
between comparable periods.
Realized Loss on Derivative Instruments, Net.
During the three months ended June 30, 2011, we
recognized a $5.0 million loss associated with settlements on derivative contracts. Included in
this loss was $3.3 million paid to settle a portion of our oil derivative contracts outstanding
from July 2011 to December 2013 as a requirement to the amended MBL Credit Agreement completed in
conjunction with the 2011 Wapiti Transaction. During the three months ended June 30, 2010, we
recognized a $601,000 loss associated with settlements on derivative contracts.
Unrealized Gain on Derivative Instruments, Net.
We recognize mark-to-market gains or losses in
current earnings instead of deferring those amounts in accumulated other comprehensive income.
Accordingly, we recognized $8.3 million of unrealized gains on derivative instruments in other
income and expense during the three months ended June 30, 2011 compared to $3.7 million of
unrealized gains for the comparable prior year period.
Income Tax Expense (Benefit).
Due to our continued losses, we were required by the “more likely
than not” threshold for assessing the realizability of deferred tax assets to record a valuation
allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax
expense (benefit) for the three months ended June 30, 2011 and 2010 of ($3.9 million) and $203,000,
respectively, relates primarily to DHS, as no benefit was provided for our net operating losses.
Included in the three months ended June 30, 2011 was a current tax benefit related to a tax refund
received as a result of a tax law change that allowed us to carry-back operating losses to a period
in which we previously paid tax.
For the three months ended June 30, 2011, we recorded a tax benefit of $3.9 million due to a
non-cash income tax benefit related to gains from discontinued oil and gas operations. Generally
accepted accounting principles, or GAAP, require all items be considered, including items recorded
in discontinued operations, in determining the amount of tax benefit that results from a loss from
continuing operations that should be allocated to continuing operations. In accordance with GAAP,
we recorded a tax benefit on our loss from continuing operations, which was exactly offset by
income tax expense on discontinued operations.
Discontinued Operations.
During the third quarter of 2010, we closed the 2010 Wapiti Transaction
to sell all or a portion of our interest in various non-core assets primarily located in Colorado,
Texas, and Wyoming for gross proceeds of $130.0 million. During the three months ended June 30,
2011, we closed the 2011 Wapiti Transaction, selling the remaining portion of our interests in
non-core assets located in Texas and Wyoming for gross cash proceeds of approximately $43.2
million. In accordance with accounting standards, the results of operations relating to these
properties have been reflected as discontinued operations for all periods presented.
In separate transactions, we sold our interest in the Howard Ranch field and the Laurel Ridge field
and have included these properties as discontinued operations as well.
During the three months ended March 31, 2011, DHS engaged transaction advisors to commence a
strategic alternatives process, focused on a sale of DHS or substantially all of its assets. As
such, in accordance with accounting standards, the results of operations relating to DHS have been
reflected as discontinued operations.
34
Table of Contents
The following table shows the oil and gas segment and drilling segment revenues and expenses
included in discontinued operations for the above mentioned oil and gas properties for the three
months ended June 30, 2011 and 2010 (in thousands):
| Three Months Ended | Three Months Ended | |||||||||||||||||||||||
| June 30, 2011 | June 30, 2010 | |||||||||||||||||||||||
| Oil & Gas | Drilling | Total | Oil & Gas | Drilling | Total | |||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||||||
|
Oil and gas sales
|
$ | 4,594 | $ | — | $ | 4,594 | $ | 13,504 | $ | — | $ | 13,504 | ||||||||||||
|
Contract drilling and trucking fees
(1)
|
— | 12,129 | 12,129 | — | 11,064 | 11,064 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total Revenues
|
4,594 | 12,129 | 16,723 | 13,504 | 11,064 | 24,568 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||||||||||
|
Lease operating expense
|
1,307 | — | 1,307 | 2,943 | — | 2,943 | ||||||||||||||||||
|
Transportation expense
|
12 | — | 12 | 799 | — | 799 | ||||||||||||||||||
|
Production taxes
|
321 | — | 321 | 792 | — | 792 | ||||||||||||||||||
|
Depreciation, depletion, amortization
and accretion — oil and gas
|
1,286 | — | 1,286 | 9,605 | — | 9,605 | ||||||||||||||||||
|
Impairment provision
(2)
|
— | — | — | 93,064 | — | 93,064 | ||||||||||||||||||
|
Drilling and trucking operating expenses
(3)
|
— | 9,406 | 9,406 | — | 8,123 | 8,123 | ||||||||||||||||||
|
Depreciation and amortization —
drilling and trucking
(4)
|
— | — | — | — | 5,226 | 5,226 | ||||||||||||||||||
|
General and administrative expense
|
— | 1,051 | 1,051 | — | 992 | 992 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total operating expenses
|
2,926 | 10,457 | 13,383 | 107,203 | 14,341 | 121,544 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Operating income (loss)
|
1,668 | 1,672 | 3,340 | (93,699 | ) | (3,277 | ) | (96,976 | ) | |||||||||||||||
|
|
||||||||||||||||||||||||
|
Other income and (expense):
|
||||||||||||||||||||||||
|
Interest expense and financing costs, net
|
— | (2,091 | ) | (2,091 | ) | — | (1,775 | ) | (1,775 | ) | ||||||||||||||
|
Other income (expense)
|
— | 124 | 124 | — | (410 | ) | (410 | ) | ||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total other income and (expense)
|
— | (1,967 | ) | (1,967 | ) | — | (2,185 | ) | (2,185 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Income (loss) from discontinued operations
|
1,668 | (295 | ) | 1,373 | (93,699 | ) | (5,462 | ) | (99,161 | ) | ||||||||||||||
|
Income tax benefit
(5)
|
(615 | ) | — | (615 | ) | — | — | — | ||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Income (loss) from results of operations of discontinued
operations, net of tax
|
1,053 | (295 | ) | 758 | (93,699 | ) | (5,462 | ) | (99,161 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
Gain on sales of discontinued operations, net of tax
(6)
|
5,645 | 2,917 | 8,562 | — | — | — | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Gain (loss) from results of operations and sale of discontinued
operations, net of tax
|
$ | 6,698 | $ | 2,622 | $ | 9,320 | $ | (93,699 | ) | $ | (5,462 | ) | $ | (99,161 | ) | |||||||||
|
|
||||||||||||||||||||||||
| (1) |
Contract Drilling and Trucking Fees
. Contract drilling and trucking fees
for the three months ended June 30, 2011 increased to $12.1 million compared to $11.1 million
in the prior year. The increase is the result of improved third party rig utilization in the
three months ended June 30, 2011 resulting from an increased industry demand attributable to
improved commodity prices.
|
|
| (2) |
Impairment provision
. In accordance with accounting standards, the
impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction
with the 2010 Wapiti Transaction were reflected as discontinued operations.
|
|
| (3) |
Drilling and Trucking Operations
. Drilling expense increased to $9.4
million for the three months ended June 30, 2011 compared to $8.1 million for the comparable
prior year period. This increase is due to improved third party rig utilization during the
current year period.
|
|
| (4) |
Depreciation and Amortization — Drilling and Trucking
. Depreciation and
amortization expense — drilling decreased to zero for the three months ended June 30, 2011 as
compared to $5.2 million for the comparable year earlier period. The decrease is due to not
recording depreciation expense beginning in March 2011 in accordance with accounting rules
related to the asset held for sale treatment of DHS.
|
|
| (5) |
Income tax benefit
. For the three months ended June 30, 2011, we recorded
a tax benefit of $3.9 million due to a non-cash income tax benefit related to gains from
discontinued oil and gas operations. Generally accepted accounting principles, or GAAP,
require all items be considered, including items recorded in discontinued operations, in
determining the amount of tax benefit that results from a loss from continuing operations that
should be allocated to continuing operations. In accordance with GAAP, we recorded a tax
benefit on our loss from continuing operations, which was exactly offset by income tax expense
on discontinued operations.
|
|
| (6) |
Gain on sales of discontinued operations — oil and gas
. On June 28, 2011,
we closed on a transaction with Wapiti Oil & Gas to sell our remaining interests in various
non-core assets primarily located in Texas and Wyoming (the “2011 Wapiti Transaction”) for
gross cash proceeds of approximately $43.2 million. In accordance with accounting standards,
we recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for
the three months ended June 30, 2011 that is reflected in discontinued operations.
Gain on
sales of discontinued operations — drilling
. In June 2011, DHS sold substantially all of its
Chapman Trucking assets for $3.3 million in proceeds and a gain of $2.9 million. Proceeds were
used to reduce DHS bank debt.
|
35
Table of Contents
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
Net Loss Attributable to Delta Common Stockholders.
Net loss attributable to Delta common
stockholders was $28.8 million, or $1.03 per diluted common share, for the six months ended June
30, 2011, compared to a net loss attributable to Delta common stockholders of $162.5 million, or
$5.90 per diluted common share, for the six months ended June 30, 2010. There were a number of
items affecting comparability between periods including dry hole costs and impairments, operating
expenses, unrealized gains and losses on derivative instruments, and discontinued operations.
Explanations of significant items affecting comparability between periods are discussed by
financial statement caption below.
Oil and Gas Sales
. During the six months ended June 30, 2011, oil and gas sales were consistent
between periods at $34.6 million, as compared to $34.5 million for the comparable period a year
earlier. The slight increase in oil and gas sales was the result of a 38% increase in oil prices,
offset by a 3% decrease in gas prices, and a 1% decrease in production. The average natural gas
price received during the six months ended June 30, 2011 decreased to $5.31 per Mcf compared to
$5.49 per Mcf for the year earlier period. The average oil price received during the six months
ended June 30, 2011 increased to $82.31 per Bbl compared to $59.60 per Bbl for the year earlier
period.
Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the six months ended
June 30, 2011 and 2010 are as follows:
| Six Months Ended | ||||||||
| June 30, | ||||||||
| 2011 | 2010 | |||||||
|
Production — Continuing Operations:
|
||||||||
|
Oil (Mbbl)
|
77 | 85 | ||||||
|
Gas (Mmcf)
|
5,323 | 5,352 | ||||||
|
Total Production (Mmcfe) — Continuing Operations
|
5,784 | 5,864 | ||||||
|
|
||||||||
|
Average Price — Continuing Operations:
|
||||||||
|
Oil (per barrel)
|
$ | 82.31 | $ | 59.60 | ||||
|
Gas (per Mcf)
|
$ | 5.31 | $ | 5.49 | ||||
|
|
||||||||
|
Costs (per Mcfe) — Continuing Operations:
|
||||||||
|
Lease operating expense
|
$ | 1.20 | $ | 1.80 | ||||
|
Transportation expense
|
$ | 1.31 | $ | 1.30 | ||||
|
Production taxes
|
$ | 0.25 | $ | 0.29 | ||||
|
Depletion expense
|
$ | 3.67 | $ | 3.81 | ||||
|
|
||||||||
|
Realized derivative losses (per Mcfe)
|
$ | (0.94 | ) | $ | (0.80 | ) | ||
Lease Operating Expense.
Lease operating expenses for the six months ended June 30, 2011
decreased 34% to $7.0 million as compared to $10.5 million in the year earlier period. The decrease is primarily due to lower
water handling costs in the Vega Area as a result of the resumption of development activities and
improved water handling facilities. As a result, lease operating expense per Mcfe in the
Vega Area declined from $1.74 per Mcfe for the six months ended June 30, 2010 to
$0.88 per Mcfe for the six months ended June 30, 2011. Overall, lease
operating expense per Mcfe from continuing operations for the six months ended June 30, 2011 decreased to $1.20 per Mcfe from
$1.80 per Mcfe for the comparable year earlier period.
Transportation Expense.
Transportation expense for the six months ended June 30, 2011 and 2010
was $7.6 million. Transportation expense per Mcfe for the six months ended June 30, 2011 increased
slightly to $1.31 per Mcfe from $1.30 per Mcfe.
Production Taxes.
Production taxes for the six months ended June 30, 2011 were $1.5 million, or
14% lower than prior year costs of $1.7 million. Production taxes as a percentage of oil and gas
sales were 4.2% and 4.9% for the six months ended June 30, 2011 and 2010, respectively. The
decrease in the 2011 percentage was primarily due to a decrease in the effective Colorado severance
tax rate.
36
Table of Contents
Dry Hole Costs and Impairments.
We incurred dry hole and impairment costs of $416,000 for the six
months ended June 30, 2011 compared to $30.2 million for the comparable period a year ago. During
the six months ended June 30, 2010, dry hole and impairment costs primarily related to unproved
property impairments of $25.5 million for the Columbia River Basin, Hingeline, Howard Ranch, Bull
Canyon, Garden Gulch, Delores River and Haynesville shale prospects and a $4.8 million impairment
of our Paradox pipeline.
Depreciation, Depletion, Amortization and Accretion.
Depreciation, depletion and amortization
expense decreased 6% to $22.5 million for the six months ended June 30, 2011, as compared to $23.9
million for the comparable year earlier period. Depletion expense for the six months ended June 30,
2011 was $21.2 million compared to $22.3 million for the six months ended June 30, 2010. Our
depletion rate decreased from $3.81 per Mcfe for the six months ended June 30, 2010 to $3.67 per
Mcfe for the current year period primarily due to higher reserves as a result of our recent
drilling and completion activity in the Vega Area.
General and Administrative Expense.
General and administrative expense decreased 37% to $13.1
million for the six months ended June 30, 2011, as compared to $20.9 million for the comparable
prior year period. The decrease in general and administrative expenses is attributed to a decrease
in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as
a result of attrition and a reduction in force during 2010 resulting in lower cash compensation
expense.
Interest Expense and Financing Costs, Net.
Interest and financing costs, net decreased 10% to
$14.8 million for the six months ended June 30, 2011, as compared to $16.5 million for the
comparable year earlier period. The decrease is primarily related to lower average outstanding
Delta and DHS credit facility balances during the first half of 2011 as compared to the first half
of 2010.
Realized Loss on Derivative Instruments, Net.
During the six months ended June 30, 2011, we
recognized a $5.5 million loss associated with settlements on derivative contracts compared to a
$4.7 million loss for the comparable prior year period. Included in the June 30, 2011 loss was
$3.3 million paid to settle a portion of our oil derivative contracts outstanding from July 2011 to
December 2013 as a requirement to the amended MBL Credit Agreement completed in conjunction with
the 2011 Wapiti Transaction.
Unrealized Gain (Loss) on Derivative Instruments, Net
. We recognize mark-to-market gains or
losses in current earnings instead of deferring those amounts in accumulated other comprehensive
income. Accordingly, we recognized $2.6 million of unrealized losses on derivative instruments in
other income and expense during the six months ended June 30, 2011 compared to a gain of $20.9
million for the comparable prior year period.
Income Tax Expense (Benefit).
Due to our continued losses, we were required by the “more likely
than not” threshold for assessing the realizability of deferred tax assets, to record a valuation
allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax
expense (benefit) for the six months ended June 30, 2011 and 2010 of $(4.6 million) and $478,000,
respectively, relates primarily to DHS, as no benefit was provided for our net operating losses.
Included in the six months ended June 30, 2011 was a current tax benefit related to a tax refund
received as a result of a tax law change that allowed us to carry-back operating losses to a period
in which we previously paid tax.
For the six months ended June 30, 2011, we recorded a tax benefit of $4.8 million due to a non-cash
income tax benefit related to gains from discontinued oil and gas operations. Generally accepted
accounting principles, or GAAP, require all items be considered, including items recorded in
discontinued operations, in determining the amount of tax benefit that results from a loss from
continuing operations that should be allocated to continuing operations. In accordance with GAAP,
we recorded a tax benefit on our loss from continuing operations, which was exactly offset by
income tax expense on discontinued operations. Our net deferred tax position at June 30, 2011 is
not impacted by this tax allocation.
Discontinued Operations.
During the third quarter of 2010, we closed the 2010 Wapiti Transaction
to sell all or a portion of our interest in various non-core assets primarily located in Colorado,
Texas, and Wyoming for gross proceeds of $130.0 million. During the three months ended June 30,
2011, we closed the 2011 Wapiti Transaction, selling the remaining portion of our interests in
non-core assets located in Texas and Wyoming for gross cash proceeds of approximately $43.2
million. In accordance with accounting standards, the results of operations relating to these
properties have been reflected as discontinued operations for all periods presented.
In separate transactions, we sold our interest in the Howard Ranch field and the Laurel Ridge field
and have included these properties as discontinued operations as well.
37
Table of Contents
During the three months ended March 31, 2011, DHS engaged transaction advisors to commence a
strategic alternatives process, focused on a sale of DHS or substantially all of its assets. As
such, in accordance with accounting standards, the results of operations relating to DHS have been
reflected as discontinued operations.
The following table shows the oil and gas segment and drilling segment revenues and expenses
included in discontinued operations for the above mentioned oil and gas properties for the six
months ended June 30, 2011 and 2010 (in thousands):
| Six Months Ended | Six Months Ended | |||||||||||||||||||||||
| June 30, 2011 | June 30, 2010 | |||||||||||||||||||||||
| Oil & Gas | Drilling | Total | Oil & Gas | Drilling | Total | |||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||||||
|
Oil and gas sales
|
$ | 9,935 | $ | — | $ | 9,935 | $ | 28,295 | $ | — | $ | 28,295 | ||||||||||||
|
Contract drilling and trucking fees
(1)
|
— | 26,393 | 26,393 | — | 20,996 | 20,996 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total Revenues
|
9,935 | 26,393 | 36,328 | 28,295 | 20,996 | 49,291 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||||||||||
|
Lease operating expense
|
2,517 | — | 2,517 | 6,654 | — | 6,654 | ||||||||||||||||||
|
Transportation expense
|
22 | — | 22 | 1,443 | — | 1,443 | ||||||||||||||||||
|
Production taxes
|
404 | — | 404 | 1,568 | — | 1,568 | ||||||||||||||||||
|
Depreciation, depletion, amortization
and accretion — oil and gas
|
2,795 | — | 2,795 | 21,046 | — | 21,046 | ||||||||||||||||||
|
Impairment provision
(2)
|
— | — | — | 93,064 | — | 93,064 | ||||||||||||||||||
|
Drilling and trucking operating expenses
(3)
|
— | 22,507 | 22,507 | — | 16,012 | 16,012 | ||||||||||||||||||
|
Depreciation and amortization —
drilling and trucking
(4)
|
— | 2,669 | 2,669 | — | 10,798 | 10,798 | ||||||||||||||||||
|
General and administrative expense
|
— | 2,084 | 2,084 | — | 2,129 | 2,129 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Total operating expenses
|
5,738 | 27,260 | 32,998 | 123,775 | 28,939 | 152,714 | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Operating income (loss)
|
4,197 | (867 | ) | 3,330 | (95,480 | ) | (7,943 | ) | (103,423 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
Other income and (expense):
|
||||||||||||||||||||||||
|
Interest expense and financing costs, net
|
— | (4,129 | ) | (4,129 | ) | — | (3,632 | ) | (3,632 | ) | ||||||||||||||
|
Other income (expense)
|
— | (428 | ) | (428 | ) | — | (349 | ) | (349 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
Total other income and (expense)
|
— | (4,557 | ) | (4,557 | ) | — | (3,981 | ) | (3,981 | ) | ||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Income (loss) from discontinued operations
|
4,197 | (5,424 | ) | (1,227 | ) | (95,480 | ) | (11,924 | ) | (107,404 | ) | |||||||||||||
|
Income tax benefit
(5)
|
(1,550 | ) | — | (1,550 | ) | — | — | — | ||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Income (loss) from results of operations of discontinued
operations, net of tax
|
2,647 | (5,424 | ) | (2,777 | ) | (95,480 | ) | (11,924 | ) | (107,404 | ) | |||||||||||||
|
|
||||||||||||||||||||||||
|
Gain on sales of discontinued operations
(6)
|
5,645 | 2,917 | 8,562 | — | — | — | ||||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
||||||||||||||||||||||||
|
Gain (loss) from results of operations and sale of discontinued
operations, net of tax
|
$ | 8,292 | $ | (2,507 | ) | $ | 5,785 | $ | (95,480 | ) | $ | (11,924 | ) | $ | (107,404 | ) | ||||||||
|
|
||||||||||||||||||||||||
| (1) |
Contract Drilling and Trucking Fees
. Contract drilling and trucking fees
for the six months ended June 30, 2011 increased to $26.4 million compared to $21.0 million in
the prior year. The increase is the result of improved third party rig utilization in the six
months ended June 30, 2011 resulting from an increased industry demand attributable to
improved commodity prices.
|
|
| (2) |
Impairment provision
. In accordance with accounting standards, the
impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction
with the 2010 Wapiti Transaction were reflected as discontinued operations.
|
|
| (3) |
Drilling and Trucking Operations
. Drilling expense increased to $22.5
million for the six months ended June 30, 2011 compared to $16.0 million for the comparable
prior year period. This increase is due to improved third party rig utilization during the
current year period.
|
|
| (4) |
Depreciation and Amortization — Drilling and Trucking
. Depreciation and
amortization expense — drilling decreased to $2.7 million for the six months ended June 30,
2011 as compared to $10.8 million for the comparable year earlier period. The decrease is due
to not recording depreciation expense beginning in March 2011 in accordance with accounting
rules related to the asset held for sale treatment of DHS.
|
|
| (5) |
Income tax benefit
. For the six months ended June 30, 2011, we recorded a
tax benefit of $4.8 million due to a non-cash income tax benefit related to gains from
discontinued oil and gas operations. Generally accepted accounting principles, or GAAP,
require all items be considered, including items recorded in discontinued operations, in
determining the amount of tax benefit that results from a loss from continuing operations that
should be allocated to continuing operations. In accordance with GAAP, we recorded a tax
benefit on our loss from continuing operations, which was exactly offset by income tax expense
on discontinued operations. Our net deferred tax position at June 30, 2011 is not impacted by
this tax allocation.
|
|
| (6) |
Gain on sales of discontinued operations — oil and gas
. On June 28, 2011,
we closed on a transaction with Wapiti Oil & Gas to sell its remaining interests in various
non-core assets primarily located in Texas and Wyoming (the “2011 Wapiti Transaction”) for
gross cash proceeds of approximately $43.2 million. In accordance with accounting standards,
we recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for
the six months ended June 30, 2011 that is reflected in discontinued operations.
Gain on sales
of discontinued operations — drilling
. In June 2011, DHS sold substantially all of its
Chapman Trucking assets for $3.3 million in proceeds and a gain of $2.9 million. Proceeds
were used to reduce DHS bank debt.
|
38
Table of Contents
Historical Cash Flow
Our cash provided by (used in) operating activities increased to $112,000 provided by operating
activities for the six months ended June 30, 2011 from cash used in operating activities of $23.3
million for the six months ended June 30, 2010. The significant increase in operating cash flow is
primarily the result of changes in working capital. Our net cash provided by investing activities
increased to $8.0 million for the six months ended June 30, 2011 compared to net cash used in
investing activities of $12.1 million for the comparable prior year period primarily due to a
significant increase in proceeds received from the sale of oil and gas properties partially offset
by an increase in drilling and completion cost. Cash used in financing activities increased to
$18.4 million for the six months ended June 30, 2011 from cash used in financing activities of
$15.5 million for the six months ended June 30, 2010. During the six months ended June 30, 2011,
we made net bank debt payments of $17.4 million. During the six months ended June 30, 2010, we made
net bank debt payments of $14.2 million.
Capital and Exploration Expenditures
Our capital and exploration expenditures for the six months ended June 30, 2011 and 2010 were as
follows (in thousands):
| 2011 | 2010 | |||||||
|
CAPITAL AND EXPLORATION EXPENDITURES:
|
||||||||
|
|
||||||||
|
Property acquisitions:
|
||||||||
|
Unproved
|
$ | 24 | $ | 285 | ||||
|
Proved
|
— | — | ||||||
|
Oil and gas properties
|
31,266 | 18,917 | ||||||
|
Drilling and trucking equipment
|
821 | 995 | ||||||
|
Pipeline and gathering systems
|
(39 | ) | 5,764 | |||||
|
|
||||||||
|
Total
(1)
|
$ | 32,072 | $ | 25,961 | ||||
|
|
||||||||
| (1) |
Capital expenditures in the table above are presented on an accrual basis.
Additions to property and equipment in the consolidated statement of cash flows reflect
capital expenditures on a cash basis, when payments are made.
|
Contractual and Long-term Debt Obligations
7% Senior Unsecured Notes, due 2015
On March 15, 2005, we issued 7% senior unsecured notes for an aggregate amount of $150.0 million
which pay interest semi-annually on April 1 and October 1 and mature in 2015. The notes were issued
at 99.50% of par and the associated discount is being amortized to interest expense over the term
of the notes. The indenture governing the notes contains various restrictive covenants that may
limit our ability to, among other things, incur additional indebtedness, make certain investments,
sell assets, consolidate, merge or transfer all or substantially all of our assets and the assets
of our restricted subsidiaries. These covenants may limit management’s discretion in operating our
business.
3
3
/
4
% Senior Convertible Notes, due 2037
On April 25, 2007, we issued $115.0 million aggregate principal amount of 3
3
/
4
% Senior Convertible
Notes due 2037 for net proceeds of $111.6 million after underwriters’ discounts and commissions of
approximately $3.4 million. The remaining discount will be amortized through May 1, 2012 when the
holders of the convertible notes can first require us to purchase all or a portion of the
convertible notes. The convertible notes bear interest at a rate of 3
3
/
4
% per annum, payable
semi-annually in arrears, on May 1 and November 1 of each year. Combined with the amortization of
debt discount, the convertible notes have an effective interest rate of approximately 7.9% and 7.7%
with total interest costs of $2.3 million and $2.2 million for the three months ended June 30, 2011
and 2010, respectively, and interest costs of $4.5 million and $4.4 million for the six months
ended June 30, 2011 and 2010, respectively. The convertible notes will mature on May 1, 2037 unless
earlier converted, redeemed or repurchased. The holders of the convertible notes have the right to
require us to purchase all or a portion of the convertible notes on May 1, 2012, May 1, 2017, May
1, 2022, May 1, 2027, and May 1, 2032. The convertible notes will be convertible at the holder’s
option, in whole or in part, at an initial conversion rate of 3.296 shares of common stock per
$1,000 principal amount of convertible notes (equivalent to a conversion price of approximately
$303.40 per share) at any time prior to the close of business on the business day immediately
preceding the final maturity date of the convertible notes, subject to prior repurchase of the
convertible notes. The conversion rate may be adjusted from
39
Table of Contents
time to time in certain instances. Upon
conversion of a note, we will have the option to deliver shares of
our common stock, cash or a combination of cash and shares of our common stock for the convertible
notes surrendered. In addition, following certain fundamental changes that occur prior to maturity,
we will increase the conversion rate for a holder who elects to convert its convertible notes in
connection with such fundamental changes by a number of additional shares of common stock. Although
the convertible notes do not contain any financial covenants, the convertible notes contain
covenants that require us to properly make payments of principal and interest, provide certain
reports, certificates and notices to the trustee under various circumstances, cause our
wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the
convertible notes may be presented or surrendered for payment, continue our corporate existence,
pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.
Credit Facility — Delta
The MBL Credit Agreement, as amended, provides for a revolving loan and a term loan, each with a
maturity date of January 31, 2012, as described above. The MBL Credit Agreement includes terms and
covenants that place limitations on certain types of activities, including restrictions or
requirements with respect to additional debt, liens, asset sales, hedging activities, investments,
dividends, mergers and acquisitions, and includes various financial covenants.
Under certain conditions, amounts outstanding under the credit facility may be accelerated.
Bankruptcy and insolvency events with respect to us or certain of our subsidiaries (excluding DHS)
would result in an automatic acceleration of the indebtedness under the credit facility. Subject to
notice and cure periods in certain cases, other events of default under the credit facility would
result in acceleration of the indebtedness at the option of the lending banks. Such other events of
default include non-payment, breach of warranty, non-performance of obligations under the credit
facility (including financial covenants), default on other indebtedness, certain pension plan
events, certain adverse judgments, change of control, and a failure of the liens securing the
credit facility.
This facility is secured by a first and prior lien to the lending bank on most of our oil and gas
properties, certain related equipment, and oil and gas inventory.
Credit Facility — DHS
DHS did not pay its scheduled principal and interest payments due on January 1, April 1 and July 1,
2011 and as a result, entered into a forbearance agreement, as amended, that currently expires on
August 8, 2011. In conjunction with the forbearance agreement, the January 3 and April 1 missed
interest payments were capitalized to the principal balance of the loan on April 1, 2011 and the
July 1 interest payment was capitalized to the principal balance of the loan on July 1, 2011, and
the loan now bears interest at the default rate of 11% per annum. The DHS credit agreement
financial covenants require a minimum EBITDA of $1.5 million per quarter and a capital expenditures
limitation of $1.2 million for any fiscal quarter and $2.3 million in the aggregate for fiscal year
2011. DHS was not in compliance with its minimum EBITDA covenant and capital expenditures
limitation for the six months ended June 30, 2011. The DHS credit facility debt of $69.9 million at
June 30, 2011 is included in the accompanying consolidated balance sheets as a component of
liabilities related to assets held for sale. The DHS credit facility is non-recourse to Delta.
Other Contractual Obligations
Our asset retirement obligation arises from the costs necessary to plug and abandon our oil and gas
wells. The majority of the expenditures related to this obligation will not occur during the next
five years.
We lease our corporate office in Denver, Colorado under an operating lease which will expire in
2014. Our average yearly payments approximate $1.2 million over the term of the lease. We have
additional operating lease commitments which represent office equipment leases and lease
obligations primarily relating to field vehicles and equipment.
We had a net derivative liability of $5.6 million at June 30, 2011. The ultimate settlement amounts
of these derivative instruments are unknown because they are subject to continuing market
fluctuations. See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for more
information regarding our derivative instruments.
40
Table of Contents
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations were based on 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 3 to
our consolidated financial statements. 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, 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 our 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. Oil and gas
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 the proper classification of wells designated as developmental or exploratory which will
ultimately determine the proper accounting treatment of the costs incurred. The results from a
drilling operation can take considerable time to analyze, and the determination that commercial
reserves have been discovered requires both judgment and industry experience. Wells may be
completed that are assumed to be productive and actually deliver 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 costs incurred to select development locations within an oil and gas field are
typically considered development costs and are 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 we are entering a new exploratory area in hopes of finding a gas and oil
field that will be the focus of future development drilling activity. The initial exploratory wells
may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in
additional exploration expenses when incurred.
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, the availability and cost of capital to
develop the reserves, 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.
41
Table of Contents
Impairment of Gas and Oil Properties
We review our oil and gas properties for impairment quarterly or whenever events and circumstances
indicate a decline in the recoverability of their carrying value. We estimate the expected future
cash flows of our developed proved properties and compare such future cash flows to the carrying
amount of the proved properties to determine if the carrying amount is recoverable. If the
carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying
amount of the oil and gas properties to their fair value. The factors used to determine fair value
include, but are not limited to, estimates of proved reserves, future commodity pricing, future
production estimates, anticipated capital expenditures and production costs, 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 us to record an
impairment of the recorded book values associated with gas and oil properties. For proved
properties, the review consists of a comparison of the carrying value of the asset with the asset’s
expected future undiscounted cash flows without interest costs. For the six months ended June 30,
2011 and 2010, the expected future undiscounted cash flows of the assets exceeded the carrying
value of the corresponding asset and as such no impairment provisions were recognized.
For unproved properties, the need for an impairment charge is based on our plans for future
development and other activities impacting the life of the property and our ability to recover our
investment. When we believe the costs of the unproved property are no longer recoverable, an
impairment charge is recorded based on the estimated fair value of the property. For the six
months ended June 30, 2011 and 2010, no significant impairments were recorded.
During the remainder of 2011, we are continuing to evaluate certain proved and unproved properties
on which favorable or unfavorable results or fluctuations in commodity prices may cause us to
revise in future periods our estimates of future cash flows from those properties. Such revisions
of estimates could require us to record an impairment provision in the period of such revisions.
Commodity Derivative Instruments and Hedging Activities
We may periodically enter into commodity derivative contracts or fixed-price physical contracts to
manage our exposure to oil, natural gas, and natural gas liquids price volatility. We primarily
utilize futures contracts, swaps or options, which are generally placed with major financial
institutions or with counterparties of high credit quality that we believe represent minimal credit
risks.
All derivative instruments are recorded on the balance sheet at fair value which must be estimated
using complex valuation models. We recognize mark-to-market gains and losses in current earnings
instead of deferring those amounts in accumulated other comprehensive income. The fair value of
our oil derivative instruments was a liability of $2.4 million, the fair value of our gas
derivative instruments was an asset of $1.6 million, and the fair value of our natural gas liquids
derivative instruments was a liability of $4.8 million at June 30, 2011. We classify the fair value
amounts of derivative assets and liabilities executed under master netting arrangements as net
derivative assets or net derivative liabilities, whichever the case may be, by commodity and master
netting counterparty. The discount rates used to determine the fair value of these derivative
instruments include a measure of non-performance risk by both Delta and the counterparty, and,
accordingly, the liability reflected is less than the actual cash expected to be paid upon
settlement based on forward prices as of June 30, 2011. The pre-credit risk adjusted fair value of
our net derivative liabilities as of June 30, 2011 was $6.9 million. A credit risk adjustment of
$1.3 million to the fair value of the derivatives caused the reported amount of the net derivative
liabilities on our consolidated balance sheet to be $5.6 million.
42
Table of Contents
Asset Retirement Obligation
We account for our asset retirement obligations under applicable FASB guidance which requires
entities to record the fair value of a liability for retirement obligations of acquired assets. Our
asset retirement obligations arise from the plugging and abandonment liabilities for our oil and
gas wells. The fair value is estimated based on a variety of assumptions including discount and
inflation rates and estimated costs and timing to plug and abandon wells.
Deferred Tax Asset Valuation Allowance
We use the asset and liability method of accounting for income taxes. Under the asset and liability
method, deferred tax assets and liabilities are recognized for the estimated future tax effects
attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax
benefit depends on the existence of sufficient taxable income within the carryback/carryforward
period to absorb future deductible temporary differences or a carryforward. In assessing the
realizability of deferred tax assets, management must consider whether it is more likely than not
that some portion or all of the deferred tax assets will not be realized. Management considers all
available evidence (both positive and negative) in determining whether a valuation allowance is
required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected
future taxable income and tax planning strategies in making this assessment, and judgment is
required in considering the relative weight of negative and positive evidence. As a result of
management’s current assessment, we maintain a significant valuation allowance against our deferred
tax assets. We will continue to monitor facts and circumstances in our reassessment of the
likelihood that operating loss carryforwards and other deferred tax attributes will be utilized
prior to their expiration. As a result, we may determine that the deferred tax asset valuation
allowance should be increased or decreased. Such changes would impact net income through offsetting
changes in income tax expense or benefit.
| Item 3. |
Quantitative and Qualitative Disclosures About Market Risk
|
Market Rate and Price Risk
We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of
our expected production through the use of derivatives, which may from time to time include
costless collars, swaps, or puts. The level of our hedging activity and the duration of the
instruments employed depend upon our view of market conditions, available hedge prices and our
operating strategy. We use hedges to limit the risk of fluctuating cash flows that fund our capital
expenditure program. We also may use hedges in conjunction with acquisitions to achieve expected
economic returns during the payout period.
The following table summarizes our open derivative contracts at June 30, 2011:
| Net Fair Value | ||||||||||||||||||||||||
| Remaining | Asset (Liability) at | |||||||||||||||||||||||
| Commodity | Volume | Fixed Price | Term | Index Price | June 30, 2011 | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
Crude oil
|
192 | Bbls / Day | $ | 57.70 | Jul ’11 - Dec ’11 | NYMEX – WTI | $ | (1,307 | ) | |||||||||||||||
|
Crude oil
|
79 | Bbls / Day | $ | 91.05 | Jul ’11 - Dec ’11 | NYMEX – WTI | (68 | ) | ||||||||||||||||
|
Crude oil
|
230 | Bbls / Day | $ | 91.05 | Jan ’12 - Dec ’12 | NYMEX – WTI | (632 | ) | ||||||||||||||||
|
Crude oil
|
162 | Bbls / Day | $ | 91.05 | Jan ’13 - Dec ’13 | NYMEX – WTI | (444 | ) | ||||||||||||||||
|
Natural gas
|
12,000 | MMBtu / Day | $ | 5.150 | Jul ’11 - Dec ’11 | CIG | 2,064 | |||||||||||||||||
|
Natural gas
|
3,253 | MMBtu / Day | $ | 5.040 | Jul ’11 - Dec ’11 | CIG | 494 | |||||||||||||||||
|
Natural gas
|
12,052 | MMBtu / Day | $ | 4.440 | Jan ’12 - Dec ’12 | CIG | (66 | ) | ||||||||||||||||
|
Natural gas
|
10,301 | MMBtu / Day | $ | 4.440 | Jan ’13 - Dec ’13 | CIG | (890 | ) | ||||||||||||||||
|
Natural gas liquids
(1)
|
35,406 | Gallons / Day | $ | 0.913 | Jul ’11 - Dec ’11 | MT. BELVIEU | (1,698 | ) | ||||||||||||||||
|
Natural gas liquids
(1)
|
30,617 | Gallons / Day | $ | 0.832 | Jan ’12 - Dec ’12 | MT. BELVIEU | (2,317 | ) | ||||||||||||||||
|
Natural gas liquids
(1)
|
12,286 | Gallons / Day | $ | 0.767 | Jan ’13 - Dec ’13 | MT. BELVIEU | (741 | ) | ||||||||||||||||
|
|
||||||||||||||||||||||||
|
|
$ | (5,605 | ) | |||||||||||||||||||||
|
|
||||||||||||||||||||||||
| (1) |
Natural gas liquids includes purity ethane, propane, natural gasoline,
normal butane and isobutene derivatives and the weighted average price is used.
|
43
Table of Contents
Assuming production and the percent of oil and gas sold remained unchanged for the six
months ended June 30, 2011, a hypothetical 10% decline in the average market price we realized
during the six months ended June 30, 2011 on unhedged production would reduce our oil and natural
gas revenues by approximately $4.4 million.
Interest Rate Risk
We were subject to interest rate risk on $15.0 million of variable rate debt obligations at June
30, 2011. The annual effect of a 10% change in interest rates on the debt would be approximately
$190,000.
| Item 4. |
Controls and Procedures
|
Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our principal
executive officer and principal financial officer, we conducted an evaluation of the effectiveness
of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e)
under the Exchange Act. Based on this evaluation, our management, including our principal executive
officer and our principal financial officer, concluded that our disclosure controls and procedures
were effective as of June 30, 2011, to ensure that information required to be disclosed by us in
the reports filed or submitted by us under the Exchange Act (i) is recorded, processed, summarized
and reported within the time period specified in SEC rules and forms, and (ii) is accumulated and
communicated to our management, including our principal executive officer and our principal
financial officer, as appropriate to allow appropriate decisions on a timely basis regarding
required disclosure.
Internal Control over Financial Reporting
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
materially affect, our internal control over financial reporting.
| Item 1. |
Legal Proceedings
|
From time to time, we may be involved in litigation relating to claims arising out of our
operations in the normal course of our business. As of the date of this report, no legal
proceedings are pending against us that we believe individually or collectively could have a
materially adverse effect upon our financial condition, results of operations or cash flows, except
as follows:
Our indirect, 49.8% owned affiliate DHS and certain of its employees, among others, have been
notified by the Office of the Inspector General, Office of Investigations, of the Export-Import
Bank of the United States, and the U.S. Department of Justice, that DHS and certain of its and the
Company’s employees are the subject of an investigation in connection with a loan guarantee sought
from the Export-Import Bank in the first quarter of 2010 of a loan from a Mexican bank sought by a
DHS customer in Mexico. DHS has cooperated and will continue to cooperate with the investigation.
This investigation is subject to uncertainties, and, as such, DHS is unable to estimate the nature
of any possible liability that may result.
We formerly owned a 2.41934% working interest in OCS Lease 320 in the Sword Unit, offshore
California, and Amber Resources Company (“Amber”) formerly owned a 0.97953% working interest in the
same lease. Lease 320 was conveyed back to the United States at the conclusion of the previous
litigation with the government (
Amber Resources Co., et al. vs. United States,
Civ. Act. No. 2-30
filed in the United States Court of Federal Claims) when the courts determined that the government
had breached that lease (among others) and was liable to the working interest owners for damages;
however, the government now contends that the former working interest owners are still obligated to
permanently plug and abandon an exploratory well that was drilled on the lease and to clear the
well site. The former operator of the lease commenced litigation against the government in United
States District Court for the District of Columbia (
Noble Energy Corp. vs. Kenneth L. Salazar,
Secretary United States Department of the Interior, et al
No. 1:09-cv-02013-EGS) seeking a
declaratory judgment that the former working interest owners are not responsible for these costs as
a result of the government’s breach of the lease. On April 22, 2011, the Court entered a judgment
in favor of the government, ruling that the
44
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working interest owners jointly and severally share the
responsibility to permanently plug and abandon the subject well, and that this duty was not discharged by the government’s breach of contract. On May 11, 2011, the
former operator filed an appeal of this ruling to the United States of Appeals for the District of
Columbia Circuit. It is currently unknown whether or not the appeal will be successful, or what
the actual costs of decommissioning the well would be if the former working interest owners are
ultimately held liable. If the working interest owners are held liable, we and Amber would be
responsible for the payment of our respective proportionate shares of the cost.
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock, senior notes or convertible notes are described below and under “Risk Factors” in Item 1A of our 2010 Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC on March 16, 2011. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
The Company has announced that our board of directors has authorized the exploration of strategic alternatives.
The results and impact of our announcement to explore strategic alternatives, including the possible sale of the Company, are uncertain and may not solve our significant short-term liquidity issues.
In light of our significant near-term liquidity issues, on July 6, 2011, we announced the commencement of a formal process to pursue strategic alternatives, including the engagement of Macquarie Capital (USA) Inc. and Evercore Group LLC to act as our advisors, which could result in, among other things, a sale of the Company. There can be no assurance that the review of strategic alternatives will result in any agreement or transaction, or that if an agreement is executed, that a transaction will be consummated, or that, if a transaction is consummated, it will solve our significant short-term liquidity issues. We do not intend to disclose developments with respect to this review (whether or not material) unless and until the Board has approved a specific course of action or terminated the exploration of strategic alternatives. In connection with our exploration of strategic alternatives, we expect to incur expenses associated with identifying and evaluating strategic alternatives. The process of exploring strategic alternatives may be disruptive to our business operations. The inability to effectively manage the process and any resulting agreement or transaction could materially and adversely affect our business, financial condition or results of operations. In addition, perceived uncertainties as to our future may result in the loss of potential business opportunities and may make it more difficult to attract and retain qualified personnel and business partners.
The formal process initiated by our board of directors to pursue strategic alternatives may not result in a transaction.
While we commenced a formal process to pursue strategic alternatives, we emphasize that there can be no assurance that the process will result in any transaction, and that, if a transaction is consummated, there can be no assurance it will solve our significant short-term liquidity issues. Additionally, if a sale transaction or other transaction is announced and does not occur, to the extent that the current market price reflects an assumption that such a transaction would occur, our stock price may be adversely affected.
Our largest stockholder has the power to significantly influence the future of our Company.
As of August 1, 2011, our largest stockholder, Tracinda Corporation (“Tracinda”), beneficially owned approximately 9,379,800 shares of our common stock, or approximately 33% of the outstanding shares of our common stock. Pursuant to the Company Stock Purchase Agreement that we entered into with Tracinda on December 29, 2007, Tracinda has certain rights, including the right to designate a number of members of our Board of Directors proportional to their ownership in the Company and consent rights over certain types of actions, including amendments to our Certificate of Incorporation, creation or issuance of preferred stock, mergers or similar transactions, and transactions involving the sale of over 50% of our assets. Tracinda has designated three out of the eight members currently comprising our Board of Directors, one of whom serves as our Board Chairman. Consequently, Tracinda Corporation has the power to significantly influence matters requiring approval by our stockholders, including the election of directors, and the approval of mergers and other significant corporate transactions. This concentration of ownership may make it more difficult for other stockholders to effect substantial changes in our
45
Table of Contents
Company and may also have the effect of delaying, preventing or expediting, as the case may be, a change in control of our Company. Tracinda also has the right to sell its Delta stock if it chooses to do so. In the event that Tracinda sells all or a substantial portion of its Delta shares, it is possible that the market price of our stock could be adversely affected.
DHS has significant near-term liquidity issues. There is a significant risk that DHS will continue to not be able to meet its debt covenants under its credit facility.
As of June 30, 2011, DHS had only nine of its 18 rigs in operation and it expects to continue to incur liquidity pressures during 2011 based on its current cash flows and level of indebtedness. DHS is now highly leveraged relative to its cash flow and its senior lender, Lehman Commercial Paper, Inc., (“LCPI”), has filed for bankruptcy protection. DHS is in the process of attempting to procure amended financing terms from LCPI or alternative financing from other sources with more favorable debt terms, but there can be no assurance that its efforts will be successful. At June 30, 2011, DHS owed $71.9 million under its credit facility ($69.9 million principal and $2.0 million accrued interest) and was not in compliance with its financial covenants. DHS has not paid its scheduled principal and interest payments in 2011, and has entered into a series of forbearance agreements with LCPI, the most recent of which expires on August 8, 2011. In the event that DHS is not successful in obtaining alternative financing or making satisfactory arrangements with the LCPI bankruptcy trustee, it is likely that DHS will continue to be in default of its debt covenants under its credit facility unless and until market conditions improve significantly. In such event and upon expiration of the current forbearance agreement, all of the amounts due under the credit facility would become immediately due and payable if LCPI exercised its rights under the terms of the credit facility. All of the DHS rigs are pledged as collateral for the credit facility, and would be subject to foreclosure in the event of a default under the credit facility. The DHS credit facility is non-recourse to Delta. At June 30, 2011, Delta had a net credit investment of approximately $3.7 million in DHS. Subsequent to year-end, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of the company or substantially all of its assets. There can be no assurance that the terms offered by a potential buyer, if any, will be acceptable to the DHS shareholders. Additionally, the consummation of certain transactions are subject to the approval of LCPI and the proceeds received will be required to be used to pay down amounts outstanding under its DHS credit facility.
| Item 2. |
Unregistered Sales of Equity Securities and Use of Proceeds
|
The table below provides a summary of our purchases of our own common stock during the three months
ended June 30, 2011 (shares and price adjusted to reflect the July 13, 2011 1-for-10 reverse stock
split).
| Maximum Number | ||||||||||||||||
| Total Number of | (or Approximate Dollar | |||||||||||||||
| Shares (or Units) | Value) of Shares | |||||||||||||||
| Total Number of | Average Price | Purchased as Part of | (or Units) that May Yet | |||||||||||||
| Shares (or Units) | Paid Per Share | Publicly Announced | Be Purchased Under | |||||||||||||
| Period | Purchased (1) | (or Unit) (2) | Plans or Programs (3) | the Plans or Programs (3) | ||||||||||||
|
April 1 — April 30, 2011
|
679 | $ | 8.36 | — | — | |||||||||||
|
May 1 — May 31, 2011
|
— | — | — | — | ||||||||||||
|
June 1 — June 30, 2011
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Total
|
679 | $ | 8.36 | — | — | |||||||||||
|
|
||||||||||||||||
| (1) |
Consists of shares delivered back to us by employees and/or directors to satisfy tax
withholding obligations that arise upon the vesting of the stock awards. We, pursuant to
our equity compensation plans, give participants the opportunity to turn back to us the
number of shares from the award sufficient to satisfy the person’s tax withholding
obligations that arise upon the termination of restrictions.
|
|
| (2) |
The stated price does not include any commission paid.
|
|
| (3) |
These sections are not applicable as we have no publicly announced stock repurchase
plans.
|
| Item 5. |
Other Information
|
None.
46
Table of Contents
| Item 6. |
Exhibits.
|
Exhibits are as follows:
| 3.1 |
Certificate of Incorporation, as amended. Incorporated by reference to
Exhibit 3.1 to our Form 8-K filed July 13, 2011.
|
|||
|
|
||||
| 10.1 |
Purchase and Sale Agreement, dated June 15, 2011, among Delta Petroleum
Corporation and Wapiti Oil & Gas, L.L.C. Incorporated by reference to Exhibit
10.1 to our Form 8-K filed June 20, 2011.
|
|||
|
|
||||
| 10.2 |
Forbearance Agreement dated as of June 28, 2011 among DHS Holding
Company, DHS Drilling Company and Lehman Commercial Paper, Inc. Filed herewith
electronically.
|
|||
|
|
||||
| 10.3 |
Second Amendment to Third Amended and Restated Credit Agreement, dated June
28, 2011, between Delta Petroleum Corporation and Macquarie Bank Limited, as
administrative agent. Incorporated by reference to Exhibit 10.1 to our Form 8-K
filed June 29, 2011.
|
|||
|
|
||||
| 10.4 |
Forbearance Agreement dated as of August 3, 2011 among DHS Holding
Company, DHS Drilling Company and Lehman Commercial Paper, Inc. Filed herewith
electronically.
|
|||
|
|
||||
| 31.1 |
Certification of principal executive officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. Filed herewith electronically.
|
|||
|
|
||||
| 31.2 |
Certification of principal financial officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. Filed herewith electronically.
|
|||
|
|
||||
| 32.1 |
Certification of principal executive officer pursuant to 18 U.S.C. Section
1350. Filed herewith electronically.
|
|||
|
|
||||
| 32.2 |
Certification of principal financial officer pursuant to 18 U.S.C. Section
1350. Filed herewith electronically.
|
47
Table of Contents
SIGNATURES
Pursuant to the requirements 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/ Carl E. Lakey
Chief Executive Officer |
||||
|
|
||||||
|
|
By: | /s/ Kevin K. Nanke | ||||
|
|
||||||
|
|
Kevin K. Nanke, Treasurer and
Chief Financial Officer |
|||||
|
|
||||||
|
Date: August 4, 2011
|
||||||
48
Table of Contents
EXHIBIT INDEX:
| 3.1 |
Certificate of Incorporation, as amended. Incorporated by reference to
Exhibit 3.1 to our Form 8-K filed July 13, 2011.
|
|||
|
|
||||
| 10.1 |
Purchase and Sale Agreement, dated June 15, 2011, among Delta Petroleum
Corporation and Wapiti Oil & Gas, L.L.C. Incorporated by reference to Exhibit
10.1 to our Form 8-K filed June 20, 2011.
|
|||
|
|
||||
| 10.2 |
Forbearance Agreement dated as of June 28, 2011 among DHS Holding
Company, DHS Drilling Company and Lehman Commercial Paper, Inc. Filed herewith
electronically.
|
|||
|
|
||||
| 10.3 |
Second Amendment to Third Amended and Restated Credit Agreement, dated
June 28, 2011, between Delta Petroleum Corporation and Macquarie Bank Limited, as
administrative agent. Incorporated by reference to Exhibit 10.1 to our Form 8-K
filed June 29, 2011.
|
|||
|
|
||||
| 10.4 |
Forbearance Agreement dated as of August 3, 2011 among DHS Holding
Company, DHS Drilling Company and Lehman Commercial Paper, Inc. Filed herewith
electronically.
|
|||
|
|
||||
| 31.1 |
Certification of principal executive officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002. Filed herewith electronically.
|
|||
|
|
||||
| 31.2 |
Certification of principal financial officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002. Filed herewith electronically.
|
|||
|
|
||||
| 32.1 |
Certification of principal executive officer pursuant to 18 U.S.C.
Section 1350. Filed herewith electronically.
|
|||
|
|
||||
| 32.2 |
Certification of principal financial officer pursuant to 18 U.S.C.
Section 1350. Filed herewith electronically.
|
TABLE OF CONTENTS
Part I Financial InformationItem 1. Consolidated Financial StatementsItem 2. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 3. Quantitative and Qualitative Disclosures About Market RiskItem 4. Controls and ProceduresPart II Other InformationItem 1. Legal ProceedingsItem 1A. Risk FactorsItem 2. Unregistered Sales Of Equity Securities and Use Of ProceedsItem 5. Other InformationItem 6. Exhibits