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 September 30, 2010
| 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
(State or other jurisdiction of incorporation or organization) |
84-1060803
(I.R.S. Employer Identification No.) |
|
370 17th Street, Suite 4300
Denver, Colorado (Address of principal executive offices) |
80202 (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
o
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 | |||
| (Do not check if a smaller reporting company) |
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
285,216,209 shares of common stock, $.01 par value per share, were outstanding as of November 1,
2010.
INDEX
| Page No. | ||||
| PART I FINANCIAL INFORMATION | ||||
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| Item 1. Consolidated Financial Statements | ||||
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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
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Unaudited)
| September 30, | December 31, | |||||||
| 2010 | 2009 | |||||||
| (In thousands, except share data) | ||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 14,197 | $ | 61,918 | ||||
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Short-term restricted deposits
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100,000 | 100,000 | ||||||
|
Trade accounts receivable, net of allowance for doubtful
accounts of $2,348 and $100, respectively
|
15,594 | 16,654 | ||||||
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Property sale purchase price receivable
|
17,750 | — | ||||||
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Deposits and prepaid assets
|
945 | 3,103 | ||||||
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Inventories
|
3,965 | 5,588 | ||||||
|
Derivative instruments
|
1,165 | — | ||||||
|
Other current assets
|
3,385 | 5,189 | ||||||
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||||||||
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Total current assets
|
157,001 | 192,452 | ||||||
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||||||||
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Property and equipment:
|
||||||||
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Oil and gas properties, successful efforts method of accounting:
|
||||||||
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Unproved
|
235,612 | 280,844 | ||||||
|
Proved
|
867,036 | 1,379,920 | ||||||
|
Drilling and trucking equipment
|
174,445 | 177,762 | ||||||
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Pipeline and gathering systems
|
97,696 | 92,064 | ||||||
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Other
|
15,573 | 16,154 | ||||||
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|
||||||||
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Total property and equipment
|
1,390,362 | 1,946,744 | ||||||
|
Less accumulated depreciation and depletion
|
(512,677 | ) | (800,501 | ) | ||||
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||||||||
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Net property and equipment
|
877,685 | 1,146,243 | ||||||
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||||||||
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|
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Long-term assets:
|
||||||||
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Long-term restricted deposit
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100,000 | 100,000 | ||||||
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Investments in unconsolidated affiliates
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3,208 | 7,444 | ||||||
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Deferred financing costs
|
2,109 | 3,017 | ||||||
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Other long-term assets
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6,352 | 8,329 | ||||||
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||||||||
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Total long-term assets
|
111,669 | 118,790 | ||||||
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||||||||
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Total assets
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$ | 1,146,355 | $ | 1,457,485 | ||||
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LIABILITIES AND EQUITY
|
||||||||
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Current liabilities:
|
||||||||
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Credit facility — Delta
|
$ | 21,500 | $ | — | ||||
|
Credit facility — DHS
|
71,590 | 83,268 | ||||||
|
Installment payable on property acquisition
|
99,785 | 97,874 | ||||||
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Accounts payable
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32,410 | 44,225 | ||||||
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Offshore litigation payable
|
— | 13,877 | ||||||
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Other accrued liabilities
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17,510 | 13,459 | ||||||
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Derivative instruments
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— | 19,497 | ||||||
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Total current liabilities
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242,795 | 272,200 | ||||||
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||||||||
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Long-term liabilities:
|
||||||||
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Installment payable on property acquisition, net of current portion
|
97,244 | 95,381 | ||||||
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7% Senior notes
|
149,666 | 149,609 | ||||||
|
3
3
/
4
% Senior convertible notes
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107,431 | 104,008 | ||||||
|
Credit facility — Delta
|
— | 124,038 | ||||||
|
Asset retirement obligations
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3,942 | 7,654 | ||||||
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Derivative instruments
|
65 | 7,475 | ||||||
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Total long-term liabilities
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358,348 | 488,165 | ||||||
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Commitments and contingencies
|
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Equity:
|
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Preferred stock, $.01 par value:
|
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authorized
3,000,000 shares, none issued
|
— | — | ||||||
|
Common stock, $.01 par value: authorized 600,000,000 shares,
issued 285,637,000 shares at September 30, 2010 and
282,548,000 shares at December 31, 2009
|
2,856 | 2,825 | ||||||
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Additional paid-in capital
|
1,630,357 | 1,625,035 | ||||||
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Treasury stock at cost; 33,000 shares at September 30, 2010
and 42,000 shares at December 31, 2009
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(31 | ) | (268 | ) | ||||
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Accumulated deficit
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(1,087,616 | ) | (939,010 | ) | ||||
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Total Delta stockholders’ equity
|
545,566 | 688,582 | ||||||
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Non-controlling interest
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(354 | ) | 8,538 | |||||
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Total equity
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545,212 | 697,120 | ||||||
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Total liabilities and equity
|
$ | 1,146,355 | $ | 1,457,485 | ||||
|
|
||||||||
See accompanying notes to consolidated financial statements.
1
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(Unaudited)
| Three Months Ended | ||||||||
| September 30, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands, except per share amounts) | ||||||||
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Revenue:
|
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Oil and gas sales
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$ | 20,233 | $ | 19,059 | ||||
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Contract drilling and trucking fees
|
15,204 | 2,538 | ||||||
|
Loss on offshore litigation award and property sales, net
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(1 | ) | (150 | ) | ||||
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Total revenue
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35,436 | 21,447 | ||||||
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Operating expenses:
|
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Lease operating expense
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5,969 | 6,809 | ||||||
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Transportation expense
|
3,388 | 2,028 | ||||||
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Production taxes
|
996 | 717 | ||||||
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Exploration expense
|
368 | 891 | ||||||
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Dry hole costs and impairments
|
(262 | ) | 53,407 | |||||
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Depreciation, depletion, amortization and accretion — oil and gas
|
14,410 | 20,065 | ||||||
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Drilling and trucking operating expenses
|
12,041 | 2,818 | ||||||
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Depreciation and amortization — drilling and trucking
|
4,801 | 5,545 | ||||||
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General and administrative
|
10,345 | 9,953 | ||||||
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Executive severance expense, net
|
(674 | ) | — | |||||
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Total operating expenses
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51,382 | 102,233 | ||||||
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Operating loss
|
(15,946 | ) | (80,786 | ) | ||||
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Other income and (expense):
|
||||||||
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Interest expense and financing costs, net
|
(9,310 | ) | (9,706 | ) | ||||
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Other income (expense), net
|
(36 | ) | 220 | |||||
|
Realized gain (loss) on derivative instruments, net
|
(418 | ) | 370 | |||||
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Unrealized gain (loss) on derivative instruments, net
|
7,124 | (5,923 | ) | |||||
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Loss from unconsolidated affiliates
|
(90 | ) | (454 | ) | ||||
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|
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|
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Total other expense
|
(2,730 | ) | (15,493 | ) | ||||
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Loss from continuing operations before income taxes and
discontinued operations
|
(18,676 | ) | (96,279 | ) | ||||
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Income tax expense
|
86 | 265 | ||||||
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Loss from continuing operations
|
(18,762 | ) | (96,544 | ) | ||||
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|
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Discontinued operations:
|
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Income (loss) from results of operations and sale of discontinued operations, net of tax
|
29,495 | (4,429 | ) | |||||
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|
||||||||
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Net income (loss)
|
10,733 | (100,973 | ) | |||||
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|
||||||||
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Less net loss attributable to non-controlling interest
|
3,209 | 4,146 | ||||||
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|
||||||||
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Net income (loss) attributable to Delta common stockholders
|
$ | 13,942 | $ | (96,827 | ) | |||
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Amounts attributable to Delta common stockholders:
|
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Loss from continuing operations
|
$ | (15,553 | ) | $ | (92,398 | ) | ||
|
Income (loss) from discontinued operations, net of tax
|
29,495 | (4,429 | ) | |||||
|
|
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Net income (loss)
|
$ | 13,942 | $ | (96,827 | ) | |||
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|
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|
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Basic income (loss) attributable to Delta common stockholders per common share:
|
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Loss from continuing operations
|
$ | (0.06 | ) | $ | (0.34 | ) | ||
|
Discontinued operations
|
0.11 | (0.01 | ) | |||||
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|
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Net income (loss)
|
$ | 0.05 | $ | (0.35 | ) | |||
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|
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|
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Diluted income (loss) attributable to Delta common stockholders per common share:
|
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Loss from continuing operations
|
$ | (0.05 | ) | $ | (0.34 | ) | ||
|
Discontinued operations
|
0.10 | (0.01 | ) | |||||
|
|
||||||||
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Net income (loss)
|
$ | 0.05 | $ | (0.35 | ) | |||
|
|
||||||||
See accompanying notes to consolidated financial statements.
2
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(Unaudited)
| Nine Months Ended | ||||||||
| September 30, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands, except per share amounts) | ||||||||
|
Revenue:
|
||||||||
|
|
||||||||
|
Oil and gas sales
|
$ | 74,734 | $ | 56,786 | ||||
|
Contract drilling and trucking fees
|
36,200 | 9,425 | ||||||
|
Gain (loss) on offshore litigation award and property sales, net
|
(539 | ) | 31,054 | |||||
|
|
||||||||
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|
||||||||
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Total revenue
|
110,395 | 97,265 | ||||||
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|
||||||||
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|
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Operating expenses:
|
||||||||
|
|
||||||||
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Lease operating expense
|
20,903 | 21,273 | ||||||
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Transportation expense
|
11,195 | 6,653 | ||||||
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Production taxes
|
3,760 | 3,217 | ||||||
|
Exploration expense
|
952 | 2,422 | ||||||
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Dry hole costs and impairments
|
30,859 | 161,471 | ||||||
|
Depreciation, depletion, amortization and accretion — oil and gas
|
45,540 | 62,992 | ||||||
|
Drilling and trucking operating expenses
|
28,053 | 10,416 | ||||||
|
Depreciation and amortization — drilling and trucking
|
15,599 | 17,512 | ||||||
|
General and administrative
|
33,372 | 31,545 | ||||||
|
Executive severance expense, net
|
(674 | ) | 3,739 | |||||
|
|
||||||||
|
|
||||||||
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Total operating expenses
|
189,559 | 321,240 | ||||||
|
|
||||||||
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|
||||||||
|
Operating loss
|
(79,164 | ) | (223,975 | ) | ||||
|
|
||||||||
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|
||||||||
|
Other income and (expense):
|
||||||||
|
|
||||||||
|
Interest expense and financing costs, net
|
(29,426 | ) | (41,907 | ) | ||||
|
Other income (expense), net
|
(207 | ) | 1,630 | |||||
|
Realized gain (loss) on derivative instruments, net
|
(5,132 | ) | 370 | |||||
|
Unrealized gain (loss) on derivative instruments, net
|
28,072 | (27,034 | ) | |||||
|
Income (loss) from unconsolidated affiliates
|
893 | (3,324 | ) | |||||
|
|
||||||||
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|
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Total other expense
|
(5,800 | ) | (70,265 | ) | ||||
|
|
||||||||
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|
||||||||
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Loss from continuing operations before income taxes and
discontinued operations
|
(84,964 | ) | (294,240 | ) | ||||
|
|
||||||||
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Income tax expense (benefit)
|
564 | (53 | ) | |||||
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|
||||||||
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|
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Loss from continuing operations
|
(85,528 | ) | (294,187 | ) | ||||
|
|
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Discontinued operations:
|
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|
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Loss from results of operations and sale of discontinued operations, net of tax
|
(72,212 | ) | (16,702 | ) | ||||
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|
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|
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Net loss
|
(157,740 | ) | (310,889 | ) | ||||
|
|
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Less net loss attributable to non-controlling interest
|
9,134 | 16,191 | ||||||
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|
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|
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Net loss attributable to Delta common stockholders
|
$ | (148,606 | ) | $ | (294,698 | ) | ||
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|
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|
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Amounts attributable to Delta common stockholders:
|
||||||||
|
Loss from continuing operations
|
$ | (76,394 | ) | $ | (277,996 | ) | ||
|
Loss from discontinued operations, net of tax
|
(72,212 | ) | (16,702 | ) | ||||
|
|
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Net loss
|
$ | (148,606 | ) | $ | (294,698 | ) | ||
|
|
||||||||
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|
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Basic income (loss) attributable to Delta common stockholders per common share:
|
||||||||
|
Loss from continuing operations
|
$ | (0.28 | ) | $ | (1.47 | ) | ||
|
Discontinued operations
|
(0.26 | ) | (0.08 | ) | ||||
|
|
||||||||
|
Net loss
|
$ | (0.54 | ) | $ | (1.55 | ) | ||
|
|
||||||||
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|
||||||||
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Diluted income (loss) attributable to Delta common stockholders per common share:
|
||||||||
|
Loss from continuing operations
|
$ | (0.28 | ) | $ | (1.47 | ) | ||
|
Discontinued operations
|
(0.26 | ) | (0.08 | ) | ||||
|
|
||||||||
|
Net loss
|
$ | (0.54 | ) | $ | (1.55 | ) | ||
|
|
||||||||
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)
(Unaudited)
| Additional | Accu- | Total Delta | Non- | |||||||||||||||||||||||||||||||||
| Common stock | paid-in | Treasury stock | mulated | stockholders’ | controlling | Total | ||||||||||||||||||||||||||||||
| Shares | Amount | capital | Shares | Amount | deficit | equity | interest | equity | ||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||
|
Balance, December 31, 2009
|
282,548 | $ | 2,825 | $ | 1,625,035 | 42 | $ | (268 | ) | $ | (939,010 | ) | $ | 688,582 | $ | 8,538 | $ | 697,120 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||||||
|
Net loss
|
— | — | — | — | — | (148,606 | ) | (148,606 | ) | (9,134 | ) | (157,740 | ) | |||||||||||||||||||||||
|
Employee vesting of treasury stock held by
subsidiary
|
— | — | — | (13 | ) | 194 | — | 194 | (194 | ) | — | |||||||||||||||||||||||||
|
Issuance of vested stock
|
5,653 | 56 | (56 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||||
|
Shares repurchased for withholding taxes
|
(911 | ) | (9 | ) | (736 | ) | 4 | 43 | — | (702 | ) | — | (702 | ) | ||||||||||||||||||||||
|
Forfeiture of restricted shares
|
(1,653 | ) | (16 | ) | 16 | — | — | — | — | — | — | |||||||||||||||||||||||||
|
Executive severance — stock-based awards
forfeited
|
— | — | (2,274 | ) | — | — | — | (2,274 | ) | — | (2,274 | ) | ||||||||||||||||||||||||
|
Stock based compensation
|
— | — | 8,372 | — | — | — | 8,372 | 436 | 8,808 | |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||||||
|
Balance, September 30, 2010
|
285,637 | $ | 2,856 | $ | 1,630,357 | 33 | $ | (31 | ) | $ | (1,087,616 | ) | $ | 545,566 | $ | (354 | ) | $ | 545,212 | |||||||||||||||||
See accompanying notes to consolidated financial statements.
4
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Unaudited)
| Nine Months Ended | ||||||||
| September 30, | ||||||||
| 2010 | 2009 | |||||||
| (In thousands) | ||||||||
|
Cash flows from operating activities:
|
||||||||
|
Net loss
|
$ | (157,740 | ) | $ | (310,889 | ) | ||
|
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
|
||||||||
|
Basis in offshore properties recovered through litigation
|
— | 17,647 | ||||||
|
Loss on property sales
|
— | |||||||
|
(Gain) loss on sale of drilling rig
|
— | (1,663 | ) | |||||
|
Depreciation, depletion, amortization and accretion — oil and gas
|
45,540 | 62,992 | ||||||
|
Depreciation and amortization — drilling and trucking
|
15,599 | 17,512 | ||||||
|
Depreciation, depletion, amortization and accretion — discontinued operations
|
13,837 | 19,477 | ||||||
|
Stock based compensation
|
8,808 | 7,433 | ||||||
|
Executive severance payable in common stock
|
— | 1,700 | ||||||
|
Executive severance — stock-based awards forfeited
|
(2,274 | ) | (2,820 | ) | ||||
|
Amortization of deferred financing costs
|
7,156 | 10,029 | ||||||
|
Accretion of discount on installments payable
|
3,774 | 5,582 | ||||||
|
Increase in allowance for bad debt
|
1,437 | — | ||||||
|
Unrealized (gain) loss on derivative instruments, net
|
(28,072 | ) | 27,034 | |||||
|
Dry hole costs and impairments
|
30,859 | 161,471 | ||||||
|
Impairments — discontinued operations
|
92,162 | — | ||||||
|
Gain on sale of discontinued operations
|
(28,372 | ) | — | |||||
|
Loss on sale of drilling, trucking and other assets
|
786 | — | ||||||
|
(Income) loss from unconsolidated affiliates
|
(893 | ) | 3,660 | |||||
|
Deferred income tax expense (benefit)
|
564 | (53 | ) | |||||
|
Other
|
43 | (66 | ) | |||||
|
Net changes in operating assets and liabilities:
|
||||||||
|
(Increase) decrease in trade accounts receivable
|
(318 | ) | 16,869 | |||||
|
Decrease in deposits and prepaid assets
|
(242 | ) | 3,638 | |||||
|
Increase in inventories
|
— | (655 | ) | |||||
|
(Increase) decrease in other current assets
|
919 | (2,576 | ) | |||||
|
Decrease in accounts payable
|
(20,627 | ) | (18,751 | ) | ||||
|
Increase (decrease) in other accrued liabilities and offshore litigation payable
|
(8,904 | ) | 2,588 | |||||
|
|
||||||||
|
|
||||||||
|
Net cash provided by (used in) operating activities
|
(25,958 | ) | 20,159 | |||||
|
|
||||||||
|
|
||||||||
|
Cash flows from investing activities:
|
||||||||
|
Additions to property and equipment
|
(24,959 | ) | (143,675 | ) | ||||
|
Additions to drilling and trucking equipment
|
(1,322 | ) | (1,648 | ) | ||||
|
Proceeds from sale of oil and gas properties
|
115,180 | — | ||||||
|
Proceeds from sale of drilling assets and other fixed assets
|
601 | 8,247 | ||||||
|
Proceeds from sale of unconsolidated affiliate
|
3,879 | — | ||||||
|
Investment in unconsolidated affiliates
|
— | 295 | ||||||
|
Proceeds from escrow deposit
|
1,380 | — | ||||||
|
(Increase) decrease in other long-term assets
|
81 | (419 | ) | |||||
|
|
||||||||
|
|
||||||||
|
Net cash provided by (used in) investing activities
|
94,840 | (137,200 | ) | |||||
|
|
||||||||
|
|
||||||||
|
Cash flows from financing activities:
|
||||||||
|
Proceeds from borrowings
|
86,500 | 77,000 | ||||||
|
Repayments of borrowings
|
(200,716 | ) | (259,017 | ) | ||||
|
Payment of deferred financing costs
|
(1,641 | ) | (2,272 | ) | ||||
|
Proceeds from sale of offshore litigation contingent payment rights
|
— | 25,000 | ||||||
|
Repurchase of offshore litigation contingent payment rights
|
— | (25,000 | ) | |||||
|
Stock issued for cash, net
|
— | 246,918 | ||||||
|
Shares repurchased for withholding taxes
|
(746 | ) | (380 | ) | ||||
|
|
||||||||
|
|
||||||||
|
Net cash provided by (used in) financing activities
|
(116,603 | ) | 62,249 | |||||
|
|
||||||||
|
|
||||||||
|
Net decrease in cash and cash equivalents
|
(47,721 | ) | (54,792 | ) | ||||
|
|
||||||||
|
Cash at beginning of period
|
61,918 | 65,475 | ||||||
|
|
||||||||
|
|
||||||||
|
Cash at end of period
|
$ | 14,197 | $ | 10,683 | ||||
|
|
||||||||
|
|
||||||||
|
Supplemental cash flow information:
|
||||||||
|
Cash paid for interest and financing costs
|
$ | 17,177 | $ | 27,607 | ||||
|
|
||||||||
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 Nine Months Ended September 30, 2010 and 2009
(Unaudited)
Three and Nine Months Ended September 30, 2010 and 2009
(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,
2009. 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, 2009, previously filed with the SEC.
(2) Going Concern
The accompanying financial statements have been prepared assuming the Company will continue as a
going concern.
The Company experienced a net loss attributable to Delta common stockholders of $148.6 million for
the nine months ended September 30, 2010, and as of September 30, 2010 had a working capital
deficiency of $85.8 million, including $21.5 million outstanding under Delta’s Second Amended and
Restated Credit Agreement (the “Credit Agreement” or the “credit facility”) which is due on January
15, 2011 and $71.6 million outstanding under the credit agreement of DHS Drilling Company (“DHS”),
the Company’s 49.8% subsidiary, which is due on August 31, 2011. In addition, the holders of the
Company’s $115.0 million principal amount of 3
3
/
4
% Senior Convertible Notes due 2037 have the right
to require the Company to purchase all or a portion of such notes on May 1, 2012 (or thereafter on
each May 1 in 2017, 2022, 2027 and 2032). The ongoing losses, near term credit maturities, and
working capital deficiency raise substantial doubt about the Company’s ability to continue as a
going concern.
As of and for the nine months ended September 30, 2010, the Company was in compliance with
covenants under its credit facility related to its financial ratios, maximum cash on hand and
accounts payable. The Company had $13.5 million of availability under its credit agreement based
upon the $35.0 million borrowing base in effect at September 30, 2010, and had cash on hand of
$14.2 million.
On April 1, 2010, DHS amended its existing credit facility with Lehman Commercial Paper, Inc.
(“LCPI”) and renegotiated certain terms of the agreement, to, among other changes more fully
described in Note 7, “Long Term Debt,” bring DHS into compliance with the terms of the agreement,
amend the principal repayment schedule, adjust the interest rate, and eliminate or amend certain
financial covenants. The DHS facility is non-recourse to Delta.
6
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(2) Going Concern, Continued
The Company does not currently have the liquidity necessary to repay the borrowings under its
credit facility due on January 15, 2011. Further, in accordance with the current terms of Delta’s
credit facility, the Company is limited to capital expenditures of $18.5 million for the quarter
ending December 31, 2010 (based on the original limitation of $10.0 million for the quarter ending
December 31, 2010 plus $8.5 million carried forward from the quarter ended September 30, 2010).
In November 2009, the Company retained Morgan Stanley and Evercore Partners to evaluate and advise
the Board of Directors on strategic alternatives to enhance shareholder value, including but not
limited to the sale of some or all of the Company’s assets, entering into partnerships or joint
ventures, or the sale of the entire Company.
On July 23, 2010, the Company entered into a definitive Purchase and Sale Agreement with Wapiti Oil
& Gas, L.L.C. to sell various non-core assets (the “Wapiti Transaction”) for cash proceeds of
$130.0 million. Also on July 23, 2010, the Company and its credit facility banks entered into the
Fourth Amendment to the Second Amended and Restated Credit Agreement (the “Fourth Amendment”)
whereby the requisite banks consented to the Wapiti Transaction, subject to specified terms and
conditions, including, among other amendments, that the net proceeds from the transaction be used
to pay down the balance outstanding under the credit facility and that the borrowing base be
reduced to $35.0 million upon consummation of the Wapiti Transaction. Additional amendments to the
credit facility are described in Note 7, “Long Term Debt.” The Wapiti Transaction closed on July
30, 2010 with approximately $108.5 million used to reduce amounts outstanding under the credit
facility, $3.7 million used to pay transaction related costs, and $17.8 million paid into escrow
pending the receipt of third party consents required to transfer ownership of certain properties
involved in the Wapiti Transaction. The funds in escrow were released in October 2010 and were used
to further reduce amounts outstanding under the Company’s credit facility (see Note 14, “Subsequent
Events”). The proceeds from the Wapiti Transaction allowed the Company to substantially reduce its
outstanding debt and when combined with the post Wapiti Transaction borrowing base, provided the
liquidity necessary to fund the Company’s third and fourth quarter 2010 development plan. Under the
credit facility there are no further scheduled or special borrowing base redeterminations before
the maturity of the facility in January 2011, and thus, management anticipates having adequate
liquidity to fund operations. As noted below, the Company is in the process of refinancing the
existing credit facility.
The Wapiti Transaction was a part of a competitive process initiated in conjunction with Delta’s
previously announced strategic alternatives process. This process was concluded with the
completion of the Wapiti Transaction and the Company’s focus has returned to creating value with
its core assets through operations. The Board of Directors may reevaluate the renewal of the
strategic alternatives process at a later time.
Taking into consideration the assets sold and proceeds received to date as a result of the
strategic alternatives process, the Company will need to raise additional cash capital or complete
the refinancing of its existing credit facility with new or existing lenders in order to pay its
outstanding borrowings under the credit facility which are due January 15, 2011. As such, the
Company expects to replace the existing
facility prior to its maturity, although it is expected that the interest terms and covenant
7
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(2) Going Concern, Continued
requirements will be more expensive and
restrictive, respectively, than the current facility’s
rates and terms. The initial term of any new credit
facility is expected to provide for maturity prior to May 1, 2012, when the holders
of the Company’s $115.0 million principal amount of 3
3
/
4
% Senior Convertible Notes have the right to
require the Company to purchase all or a portion of the notes. As a result, it is anticipated that
prior to May 1, 2012, the Company will need to obtain additional capital in order to repay any
amounts outstanding under any new credit facility and to purchase any 3
3
/
4
% Senior Convertible Notes
required by the holders of such notes to be purchased by the Company.
There can be no assurance that the actions undertaken by the Company will be sufficient to repay
the obligations under the credit agreement when due, or, if not sufficient, or if additional
defaults occur, that the lenders will be willing to waive the defaults or amend the agreement. In
addition, there can be no assurance that cash flow from operations and other sources of liquidity,
including asset sales or joint venture or other industry partnerships, will be sufficient to meet
contractual, operating and capital obligations including those under any replacement credit
facility. 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.
(3) Summary of Significant Accounting Policies
|
Principles of Consolidation and Basis of Presentation
|
The consolidated financial statements include the accounts of 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
and through the date of the Wapiti Transaction, PGR Partners, LLC. The Company includes its
proportionate share of assets, liabilities, revenues and expenses from these entities in its
consolidated financial statements. As Amber Resources Company of Colorado (“Amber”) is in a net
shareholders’ deficit position for the periods presented, the Company has recognized 100% of
Amber’s earnings/losses for all periods presented. The Company does not have any off-balance sheet
financing arrangements (other than operating leases) or any unconsolidated special purpose
entities.
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 and where there is no continuing involvement, during the nine months ended September 30, 2010
have been reclassified to income (loss) from discontinued operations for all periods presented.
Such reclassifications had no effect on net loss attributable to Delta common stockholders.
|
Cash Equivalents
|
Cash equivalents consist of money market funds and certificates of deposit. The Company considers
all highly liquid investments with maturities at the date of acquisition of three months or less to
be cash equivalents.
8
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
|
Inventories
|
Inventories consist of pipe and other production equipment not yet in use. Inventories are stated
at the lower of cost (principally first-in, first-out) or estimated net realizable value. During
the three months ended June 30, 2009, the Company recorded an impairment of $4.3 million to the
carrying value of its inventories, which is reflected in the accompanying consolidated statements
of operations for the nine months ended September 30, 2009 as a component of dry hole costs and
impairments.
|
Revenue Recognition
|
|
Oil and Gas
|
Revenues are recognized when title to the products transfers to the purchaser. The Company follows
the “sales method” of accounting for its natural gas and crude oil revenue. Under that method, the
Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers. A
liability is recognized only to the extent that the Company has an imbalance on a specific property
greater than the expected remaining proved reserves. As of September 30, 2010 and December 31,
2009, the Company’s aggregate natural gas and crude oil imbalances were not material to its
consolidated financial statements.
|
Drilling and Trucking
|
The Company earns its contract drilling revenues under daywork or turnkey contracts. The Company
recognizes revenues on daywork contracts for the days completed based on the dayrate specified in
the contract. Turnkey contracts are accounted for on a percentage-of-completion basis. The costs
of drilling the Company’s own oil and gas properties are capitalized in oil and gas properties as
the expenditures are incurred. Trucking and hauling revenues are recognized based on either an
hourly rate or a fixed fee per mile depending on the type of vehicle, the services performed, and
the contract terms.
|
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, 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 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.
9
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
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 at least annually, or more frequently 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.
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 nine months ended September 30, 2010, the expected future undiscounted cash flows of the
assets exceeded the carrying value of the corresponding asset and as such no impairment provision
was recognized. As a result of such assessment, the Company recorded an impairment provision to
proved properties of $1.9 million for the three months ended September 30, 2009 and $3.1 million
for the nine months ended September 30, 2009. The impairment provisions for the three and nine
months ended September 30, 2009 are included within dry hole costs and impairments in the
accompanying statement of operations.
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. As a result of such assessment, the Company recorded impairment provisions
attributable to unproved properties of zero and $20.6 million for the three months ended September
30, 2010 and 2009, respectively, and $22.5 million and $103.6 million for the nine months ended
September 30, 2010 and 2009, respectively. The $22.5 million impairment for the nine months ended
September 30, 2010 included $11.4 million related to the Company’s Columbia River Basin leasehold,
$5.0 million related to the Company’s Hingeline leasehold, $3.8 million related to the Company’s
Haynesville leasehold, $1.6 million related to the Company’s Delores River leasehold and $661,000
related to the Company’s Howard Ranch leasehold. For the three months ended September 30, 2009,
the Company also recorded an impairment of $10.5 million to reduce the Company’s Vega area land
carrying value to its estimated fair value. Lastly, the Company recorded impairments of $4.8
million and $1.9 million to reduce the Paradox pipeline carrying value to its estimated fair value
during the three months ended June 30, 2010 and 2009, respectively. These impairment provisions are
included within dry hole costs and impairments in the accompanying statements of operations for the
three and nine months ended September 30, 2010 and 2009.
10
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
During the remainder of 2010, 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.
|
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. The following is a reconciliation of the Company’s asset retirement obligations from
January 1, 2010 to September 30, 2010 (in thousands):
|
Asset retirement obligation — January 1, 2010
|
$ | 10,539 | ||
|
Accretion expense
|
365 | |||
|
Change in estimate
|
(188 | ) | ||
|
Obligations incurred (from new wells)
|
282 | |||
|
Obligations assumed
|
— | |||
|
Obligations on sold properties
|
(4,034 | ) | ||
|
Obligations settled
|
(1,044 | ) | ||
|
|
||||
|
Asset retirement obligation — September 30, 2010
|
5,920 | |||
|
Less: current portion of asset retirement obligation
|
(1,978 | ) | ||
|
|
||||
|
Long-term asset retirement obligation
|
$ | 3,942 | ||
|
|
||||
|
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
September 30, 2010 comprehensive income was $10.7 million and for the three months ended September
30, 2009 comprehensive loss was $101.0 million. For the nine months ended September 30, 2010 and
2009, comprehensive loss was $157.7 million and $310.9 million, respectively.
|
Financial Instruments
|
The Company periodically enters into commodity price risk transactions to manage its exposure to
oil and gas price volatility. These transactions may take the form of futures contracts, collar
agreements, swaps or options. The purpose of the hedges 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 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.
At September 30, 2010, 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
11
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
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 September 30, 2010:
| Net Fair Value | ||||||||||||||||||||
| Remaining | Asset (Liability) at | |||||||||||||||||||
| Commodity | Volume | Fixed Price | Term | Index Price | September 30, 2010 | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Crude oil
|
1,000 | Bbls / Day 1 | $ | 52.25 | Oct ’10 - Dec ’10 | NYMEX — WTI | $ | (2,600 | ) | |||||||||||
|
Crude oil
|
500 | Bbls / Day | $ | 57.70 | Jan ’11 - Dec ’11 | NYMEX — WTI | (4,404 | ) | ||||||||||||
|
Natural gas
|
6,000 | MMBtu / Day | $ | 5.720 | Oct ’10 - Dec ’10 | NYMEX — HHUB | 977 | |||||||||||||
|
Natural gas
|
15,000 | MMBtu / Day | $ | 4.105 | Oct ’10 - Dec ’10 | CIG | 705 | |||||||||||||
|
Natural gas
|
5,367 | MMBtu / Day | $ | 3.973 | Oct ’10 - Dec ’10 | CIG | 187 | |||||||||||||
|
Natural gas
|
12,000 | MMBtu / Day | $ | 5.150 | Jan ’11 - Dec ’11 | CIG | 5,006 | |||||||||||||
|
Natural gas
|
3,253 | MMBtu / Day | $ | 5.040 | Jan ’11 - Dec ’11 | CIG | 1,229 | |||||||||||||
|
|
||||||||||||||||||||
|
|
$ | 1,100 | ||||||||||||||||||
|
|
||||||||||||||||||||
| 1 |
As a result of the closing of the Wapiti Transaction, for the period from October to
December 2010, derivative contract volumes were anticipated to exceed physical production volumes
in certain months. Accordingly, in October 2010, the Company partially terminated its November and
December 2010 derivatives for a cost of $729,000 to reduce the hedged volume from 1,000 barrels per
day to 625 barrels per day.
|
The pre-credit risk adjusted fair value of the Company’s net derivative assets as of September
30, 2010 was $617,000. A credit risk adjustment of $483,000 to the fair value of the derivatives
increased the reported amount of the net derivative assets on the Company’s consolidated balance
sheet to $1.1 million.
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 September 30, 2010 (in thousands):
| Derivatives Not Designated as | ||||||||
| Hedging Instruments | Balance Sheet Classification | Fair Value | ||||||
|
Commodity Swaps
|
Derivative Instruments — Current Assets, net | $ | 1,165 | |||||
|
Commodity Swaps
|
Derivative Instruments — Long-Term Liabilities, net | (65 | ) | |||||
|
|
||||||||
|
Total
|
$ | 1,100 | ||||||
|
|
||||||||
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 nine months ended September 30, 2010 (in thousands):
| Amount of Gain | ||||||||
| Derivatives Not Designated as | Location of Gain (Loss) Recognized in | (Loss) Recognized in | ||||||
| Hedging Instruments | Income on Derivatives | Income on Derivatives | ||||||
|
Commodity Swaps
|
Realized Loss on Derivative Instruments, net — Other Income and (Expense) | $ | (5,132 | ) | ||||
|
Commodity Swaps
|
Unrealized Gain on Derivative Instruments, net — Other Income and (Expense) | 28,072 | ||||||
|
|
||||||||
|
|
$ | 22,940 | ||||||
|
|
||||||||
12
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
Executive Severance Agreements
On May 26, 2009, the Company’s then Chairman of the Board of Directors and Chief Executive Officer,
Roger A. Parker, resigned from the Company. In conjunction with Mr. Parker’s resignation, Delta
entered into a Severance Agreement, effective as of the close of business on May 26, 2009, whereby
Mr. Parker resigned from his positions as Chairman of the Board, Chief Executive Officer and as a
director of Delta, as well as his positions as a director, officer and employee of Delta’s
subsidiaries. In consideration for Mr. Parker’s resignation and his agreement to (a) relinquish all
his rights under his employment agreement, his change-in-control agreement, certain stock
agreements, bonuses relating to past and pending transactions benefiting Delta, and any other
interests he might claim arising from his efforts as Chairman of our Board of Directors and/or
Chief Executive Officer, and (b) stay on as a consultant to facilitate an orderly transition and to
assist in certain pending transactions, Delta agreed to pay Mr. Parker $4,700,000 in cash, issue to
him 1,000,000 shares of Delta common stock, pay him the aggregate of any accrued unpaid salary,
vacation days and reimbursement of his reasonable business expenses incurred through the effective
date of the agreement, and provide to him insurance benefits similar to his pre-resignation
benefits for a thirty-six month period. The Severance Agreement also contained mutual releases and
non-disparagement provisions, as well as other customary terms.
The table below summarizes the total executive severance expense included in the accompanying
statements of operations for the nine months ended September 30, 2009 (in thousands):
|
Cash consideration — immediately available funds
|
$ | 1,812 | ||
|
Cash consideration — rabbi trust
|
2,888 | |||
|
Stock consideration — rabbi trust
|
1,700 | |||
|
|
||||
|
Subtotal
|
6,400 | |||
|
Performance shares forfeited
|
(2,293 | ) | ||
|
Retention stock forfeited
|
(525 | ) | ||
|
Health, medical and other benefits payable
|
75 | |||
|
Legal costs and other expenses
|
82 | |||
|
|
||||
|
Total executive severance expense
|
$ | 3,739 | ||
|
|
||||
In accordance with the terms of the Severance Agreement, Mr. Parker received a portion of the
cash consideration in immediately available funds, and the remaining cash consideration and the
shares were deposited in a rabbi trust and distributed to Mr. Parker on November 27, 2009. The
assets of the rabbi trust were required to be consolidated into the financial statements until
disbursed.
Equity compensation costs previously recorded in the consolidated financial statements related to
performance shares forfeited prior to their derived service period being completed and retention
stock forfeited prior to vesting as a result of the Severance Agreement were reversed and reflected
as a reduction of executive severance expense.
All transactions associated with the Parker Severance Agreement were recorded in fiscal year 2009.
13
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
On July 6, 2010, John Wallace, the then President, Chief Operating Officer and a Director of the
Company, resigned from all of his positions as director, officer and employee of the Company and
any of its subsidiaries. In conjunction with such resignation, the Company entered into a
severance agreement with Mr. Wallace pursuant to which he agreed to (a) relinquish certain rights
under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses
relating to past and pending transactions benefiting Delta, and certain other interests he might
claim arising from his efforts in his previous capacities with the Company and its subsidiaries,
and (b) make himself reasonably available to answer questions to facilitate an orderly transition.
Under the terms of his severance arrangement, the Company paid Mr. Wallace a lump sum of
$1,600,000, paid him his salary for the full month in which his resignation occurred and for his
accrued vacation days, reimbursed him for his reasonable business expenses incurred through the
effective date of the agreement, and agreed to provide to him insurance benefits similar to his
pre-resignation benefits for the period in which Mr. Wallace is entitled to receive COBRA coverage
under applicable law. The severance agreement also contained mutual releases and non-disparagement
provisions, as well as other customary terms.
The table below summarizes the total executive severance expense included in the accompanying
statements of operations for the nine months ended September 30, 2010 (in thousands):
|
Cash consideration — immediately available funds
|
$ | 1,600 | ||
|
Performance shares forfeited
|
(2,274 | ) | ||
|
|
||||
|
Total executive severance expense (benefit)
|
$ | (674 | ) | |
|
|
||||
Equity compensation costs previously recorded in the consolidated financial statements related
to performance shares forfeited prior to their derived service period being completed as a result
of the severance agreement were reversed and reflected as a reduction of executive severance
expense.
|
Stock Based Compensation
|
The Company recognizes the cost of share based payments over the period the employee provides
service and includes such costs in general and administrative expense in the statements of
operations.
|
Income (Loss) from Unconsolidated Affiliates
|
Income (loss) from unconsolidated affiliates includes the Company’s share of earnings or losses
from equity method investments. During the nine months ended September 30, 2010, Delta Oilfield
Tank Company (“DOTC”) reported continuing losses from operations which, if recorded, would have
created a deficit in the investment in DOTC. In accordance with accounting standards, the Company
did not recognize its share of the losses for the nine months ended September 30, 2010 as the
Company is not obligated to make future capital contributions to DOTC. During the quarter ended
June 30, 2009, the Company recorded a $2.1 million impairment provision to its investment in DOTC
and a $917,000 impairment provision to its investment in the entity that was expected to operate
the Paradox pipeline. These impairment provisions are included within income (loss) from
unconsolidated affiliates for the nine months ended September 30, 2009.
During the nine months ended September 30, 2010, the Company sold its 50% interest in Ally
Equipment, LLC for $1.5 million, including $250,000 received during the third quarter and five
$250,000 quarterly installments to be paid each quarter end commencing on December 31, 2010. The
Company recognized a loss of $522,000 on the transaction which is included as a component of income
(loss) from unconsolidated affiliates for the three months and nine months ended September 30,
2010.
14
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
At December 31, 2009, the Company owned a 5% interest in Collbran Valley Gas Gathering, LLC
(“CVGG”) which operates a pipeline in the Piceance Basin through which the Company transports its
produced gas to the sales point. During the fourth quarter of 2009, the Company recorded an
impairment of its investment in CVGG to reduce the carrying value to its fair value of $3.5
million. In January 2010, the Company divested its 5% interest in CVGG for cash proceeds of $3.5
million (and a subsequent adjustment of an additional $129,000), plus an additional $2.0 million of
proceeds contingent on volume deliveries through the CVGG system of Delta gas between January 1,
2010 and June 30, 2011. Based on current production levels, the Company is not likely to earn the
contingent consideration without the initiation of a continuous drilling program which could only
be undertaken with additional funding beyond the Company’s existing capital resources.
|
Income Taxes
|
The Company uses 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 future tax
consequences attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases and net operating loss and tax
credit carry-forwards. Deferred tax assets and liabilities are measured using enacted income tax
rates expected to apply to taxable income in the years in which those differences are expected to
be recovered or settled. The effect on deferred tax assets and liabilities of a change in income
tax rates is recognized in the results of operations in the period that includes the enactment
date. The realizability of deferred tax assets is evaluated based on a “more likely than not”
standard, and to the extent this threshold is not met, a valuation allowance is recorded. The
Company is currently providing a full valuation allowance on its net deferred tax assets, including
the net deferred tax assets of DHS.
|
Income (Loss) per Common Share
|
Basic income (loss) per share is computed by dividing net income (loss) attributed to common stock
by the weighted average number of common shares outstanding during each period, excluding treasury
shares. Diluted income (loss) per share is computed by adjusting the average number of common
shares outstanding for the dilutive effect, if any, of convertible preferred stock, convertible
debt, stock options, restricted stock and warrants. (See Note 11, “Earnings Per Share”).
|
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.
15
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(3) Summary of Significant Accounting Policies, Continued
|
Recently Issued and Adopted Accounting Pronouncements
|
In January 2010, the FASB issued Accounting Standards Update No. 2010-06,
Improving Disclosures
about Fair Value Measurements
(“ASU 2010-06”), which provides amendments to FASB ASC Topic 820,
Fair Value Measurements and Disclosures.
The objective of ASU 2010-06 is to provide more robust
disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii)
the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements,
and (iv) significant transfers between Levels 1, 2 and 3. ASU 2010-06 is effective for fiscal
years and interim periods beginning after December 15, 2009. The Company adopted ASU 2010-06
effective January 1, 2010, which did not have an impact on its consolidated financial statements,
other than additional disclosures.
(4) Oil and Gas Properties
|
Unproved Undeveloped Offshore California Properties
|
The Company previously owned direct and indirect ownership interests ranging from 2.49% to
100% in five unproved undeveloped offshore California oil and gas properties. Delta and its 92%
owned subsidiary, Amber, were among twelve plaintiffs in a lawsuit that was filed in the United
States Court of Federal Claims in Washington, D.C. alleging that the U.S. government materially
breached the terms of forty undeveloped federal leases, some of which are part of its offshore
California properties. During 2009, the Company received net proceeds of $95.8 million after
overrides and conveyed its leases back to the United States. Accordingly, the Company no longer
has any remaining unproved undeveloped offshore California property interests.
2010
— Divestitures
During the nine months ended September 30, 2010, the Company divested of its interests in certain
non-core properties for gross proceeds of $965,000 and the assumption of plugging and abandonment
obligations. Proved reserves attributable to these properties were insignificant.
The Company considered the total purchase price in the Wapiti Transaction and allocated the
purchase price to the properties using internal discounted cash flow calculations based upon the
Company’s estimates of reserves and determined that impairment provisions of $93.2 million related
to proved properties and $3.0 million related to unproved properties were required to be recognized
during the three months ended June 30, 2010. Based upon the applicable accounting standards, $4.0
million of the impairment provision is included within dry hole costs and impairments in the
accompanying statements of operations and the remaining $92.2 million is included within loss on
sale of discontinued operations.
|
Discontinued Operations
|
In accordance with accounting standards, the results of operations and impairment loss relating to
certain of the Wapiti Transaction properties have been reflected as discontinued operations.
Properties associated with the Wapiti Transaction in which the Company only sold half of its
interest continue to be reported as a component of continuing operations. The fields classified as
discontinued operations are fields in which the Company sold all of its interest including the
Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as the Company’s interest in
its wholly-owned subsidiary Piper Petroleum. In a separate transaction, during the three months
ended September 30, 2010, the Company sold its interest in the Howard Ranch field and has included
this property as discontinued operations as well.
16
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(4) Oil and Gas Properties, Continued
The following table shows the total oil and gas segment revenues and expenses included in
discontinued operations for the above mentioned oil and gas properties for the three and nine
months ended September 30, 2010 and 2009 (in thousands):
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
|
Revenues
|
$ | 1,344 | $ | 2,475 | $ | 9,623 | $ | 8,255 | ||||||||
|
|
||||||||||||||||
|
Operating expenses:
|
||||||||||||||||
|
|
||||||||||||||||
|
Lease operating expense
|
429 | 757 | 2,676 | 3,740 | ||||||||||||
|
Transportation expense
|
181 | 60 | 1,459 | 1,196 | ||||||||||||
|
Production taxes
|
116 | 438 | 611 | 544 | ||||||||||||
|
Depreciation, depletion, amortization and accretion
|
33 | 5,649 | 13,837 | 19,477 | ||||||||||||
|
Impairment provision
|
— | — | 92,162 | — | ||||||||||||
|
|
||||||||||||||||
|
Total operating expenses
|
759 | 6,904 | 110,745 | 24,957 | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Income (loss) from discontinued operations
|
585 | (4,429 | ) | (101,122 | ) | (16,702 | ) | |||||||||
|
Income tax expense
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Income (loss) from results of operations of
discontinued properties, net of tax
|
585 | (4,429 | ) | (101,122 | ) | (16,702 | ) | |||||||||
|
|
||||||||||||||||
|
Gain on sale of discontinued operations
|
28,910 | — | 28,910 | — | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Total gain (loss) from discontinued operations
|
$ | 29,495 | $ | (4,429 | ) | $ | (72,212 | ) | $ | (16,702 | ) | |||||
|
|
||||||||||||||||
On July 30, 2010, the Company closed on the Wapiti Transaction for cash proceeds of $130.0
million, with approximately $108.5 million used to reduce amounts outstanding under the credit
facility, $3.7 million used to pay transaction related costs, and $17.8 million initially paid into
escrow pending the receipt of third party consents required to transfer ownership of certain
properties involved in the Wapiti Transaction. The escrowed proceeds were received in October
2010. The Company recognized a gain on sale for the closing of the Wapiti Transaction in the three
months ended September 30, 2010 of $29.6 million. The recognized gain is subject to revision for
normal and customary purchase price adjustments as provided for under the purchase and sale
agreement.
On August 27, 2010, the Company closed on the Howard Ranch sale for cash proceeds of $550,000. The
Company recognized a loss on sale of $687,000, which is subject to revision for normal and
customary purchase price adjustments as provided for under the purchase and sale agreement.
(5) DHS Drilling
On September 30, 2010, the Company owned a 49.8% ownership interest in DHS. The remaining interest
is owned by Chesapeake Energy Corporation, 47.2%, and 3% by DHS executive officers and management.
Delta has the right to use all of the DHS rigs on a priority basis.
17
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(5) DHS Drilling, Continued
The carrying value of DHS’s drilling rigs and related equipment is assessed for impairment whenever
circumstances indicate an impairment may exist. During the quarter ended June 30, 2009, the fleet
rig utilization rate declined approximately 68% from the first quarter of 2009 and the average
period end contract day rate declined by approximately 29% from the first quarter of 2009. In
addition, DHS’s efforts to market spare equipment and observations at industry auctions indicated
that with industry-wide active rig counts in decline, spare equipment values had declined. As a
result of these indicators of possible impairment, an analysis was performed and an impairment
provision of $6.5 million was recorded to reduce the carrying value of three drilling rigs and
other spare rig equipment to their respective fair values. No such impairment provisions were
recorded during the three and nine months ended September 30, 2010 as rig utilization has continued
to improve throughout 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
$3,713,000 has been invoiced to DPM for the project with $1,588,000 being collected to date. The
balance of $2,125,000 has been reserved as a doubtful account due to concerns regarding collection.
Legal action is being taken to collect the amount owed to DHS and the rig is in the Casper, Wyoming
yard for minor reconditioning. In addition, another DHS customer has filed bankruptcy during the
quarter and its balance of $104,000 has been reserved as a doubtful account as well.
(6) 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 and gas commodity swap contracts valued using both
quoted prices for identically traded contracts and observable market data for similar contracts
(NYMEX WTI oil, NYMEX Henry Hub gas and CIG gas 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 nine months
ended September 30, 2010 and 2009.
18
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(6) Fair Value Measurements, Continued
The following table lists the Company’s fair value measurements by hierarchy as of September 30,
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) | |||||||||
|
Recurring
|
||||||||||||
|
Derivative assets
|
$ | — | $ | 1,100 | $ | — | ||||||
|
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 installments payable are
recorded in the accompanying consolidated financial statements as current and long-term liabilities
at a discounted value. The discount is being accreted on the effective interest method over the
term of the installments, including accretion of $1.3 million and $1.9 million for the three months
ended September 30, 2010 and 2009, respectively, and accretion of $3.8 million and $5.6 million for
the nine months ended September 30, 2010 and 2009, respectively. On October 28, 2010, the Company
paid the second of three installments payable related to the transaction (see Note 14, “Subsequent
Events”).
|
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
September 30, 2010 (See Note 12, “Guarantor Financial Information”). The fair value of the
Company’s senior unsecured notes at September 30, 2010 was approximately $109.5 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 (the “Notes”) for net proceeds of $111.6 million after underwriters’
discounts and commissions of approximately $3.4 million. The 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 Notes, including $1.2 million and
$1.1 million of accretion for the three months ended September 30, 2010 and 2009, respectively, and
$3.4 million and $3.3 million of accretion for the nine months ended September 30, 2010 and 2009,
respectively. Combined with the amortization of debt discount, the Notes had an effective interest
rate of approximately 7.8% and 7.6% with total interest costs of $2.2 million for each of the three
months ended September 30, 2010 and 2009, respectively, and interest costs of $6.6 million and $6.5
million for the nine months ended September 30, 2010 and 2009, respectively. The fair value of the
Notes at September 30, 2010 was approximately $88.3 million.
19
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(7) Long Term Debt, Continued
|
Credit Facility — Delta
|
On July 23, 2010, Delta entered into the Fourth Amendment to the Second Amended and Restated Credit
Agreement, with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that
are party to its credit agreement in which, among other changes, the requisite lenders consented to
the Wapiti Transaction, subject to specified terms and conditions, including that the net proceeds
from the transaction be used to pay down the balance outstanding under the credit facility and that
the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. The
Fourth Amendment eliminated all scheduled or special borrowing base redeterminations prior to the
maturity of the facility in January 2011. In addition, the Fourth Amendment imposed capital
expenditures limitations of $18.0 million for the quarter ending September 30, 2010, $10.0 million
for the quarter ending December 31, 2010, and $2.0 million for the period from January 1, 2011 to
January 15, 2011, provided that any excess of the limitation over the amount of actual expenditures
may be carried forward from an earlier specified period to a subsequent specified period. The
Fourth Amendment added a maximum cash on hand covenant which limits the Company’s cash and cash
equivalents to $10.0 million at any time, with any excess above such limit required to be used to
pay down borrowings under the credit facility within three business days. Finally, the Fourth
Amendment requires cash disbursements for general and administrative expenses to be within a 10%
variance of projected general and administrative expenses provided to the lending banks in
conjunction with the execution of the Fourth Amendment.
The Company was in compliance with its financial ratio covenants, capital expenditures, cash on
hand and accounts payable limitations under the Credit Agreement as of September 30, 2010. Based on
the Company’s current operating projections, the Company believes it will remain in compliance with
the debt covenants through its maturity in January 2011. However, there can be no assurance that
the actions undertaken by the Company will be sufficient to repay the obligations under the credit
agreement when due, or, if not sufficient, or if additional defaults occur, that the lenders will
be willing to waive the defaults or amend the agreement.
Borrowings under the credit facility were $21.5 million at September 30, 2010, with remaining
availability of $13.5 million.
Because the credit facility matures in January 2011, the debt is classified as a current liability
in the September 30, 2010 consolidated balance sheet.
20
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(7) Long Term Debt, Continued
|
Credit Facility — DHS
|
On April 1, 2010, DHS amended its existing credit facility with LCPI and renegotiated certain terms
of the agreement including obtaining waivers for all covenant violations through March 31, 2010.
The terms of the amended agreement required principal payments of $7,677,713 paid on April 1, 2010
and $2,000,000 paid on each of May 1, 2010, August 1, 2010 and November 1, 2010, with a remaining
$2,000,000 principal payment due on January 1, 2011, and a $5,000,000 principal payment due on each
of April 1, 2011 and July 1, 2011 with the remaining balance of $57,589,787 due at maturity (August
31, 2011). In addition to the required payments, DHS may be required to prepay any remaining
outstanding principal with the “Net Cash Proceeds from any Asset Sale,” as defined by the credit
facility, and any such prepayment shall be applied to, first, prepay the immediately succeeding
Scheduled Installment in full, second, prepay all interest payable on the immediately succeeding
Interest Payment Date in full, third, pay the second succeeding Scheduled Installment in full and
fourth, prepay the remaining principal balance of the remaining loans. DHS is also required to
prepay the principal amount of the loans in an amount equal to 75% of the “Excess Cash Flow,” as
defined by the credit facility, for such fiscal quarter. The only financial covenant remaining in
the DHS credit agreement is a minimum EBITDA covenant of $1,000,000 for the three months ending
September 30, 2010 and $1,500,000 for each subsequent quarter. In addition, the amendment imposed
capital expenditures limitations of $1,200,000 for any fiscal quarter. Notwithstanding the
$1,200,000 per quarter limitation on capital expenditures, the amendment imposes aggregate capital
expenditure limitations of $3,500,000 for fiscal year 2010 and $2,330,137 for fiscal year 2011.
The interest rate has been adjusted to LIBOR plus 625 basis points, subject to a LIBOR floor rate
of 2.75%. DHS was in compliance with its amended minimum EBITDA covenant and capital expenditures
limitation for the three months ended September 30, 2010.
Because the credit facility matures in August 2011, the debt is classified as a current liability
in the September 30, 2010 consolidated balance sheet.
(8) Commitments and Contingencies
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.
The Company is currently engaged in arbitration with 212 Resources Corporation (“212”) with regard
to a dispute involving a May 18, 2008 Oil and Gas Fluid Processing Agreement (the “Agreement”)
between 212 and the Company. The Agreement requires 212 to design, construct, and operate “Mobile
Pods” to treat and discharge to surface waters fluid produced by the Company’s oil and gas
operations in compliance with applicable law and permits, and requires the Company to pay 212
approximately $500,000 per month commencing on the earlier of the date that such Mobile Pod is (a)
first Available, or (b) first used to provide the contemplated services. The term “Available,” as
used in the Agreement, means the first date that a Mobile Pod is mechanically capable of providing
the contemplated services (or would have been mechanically capable of providing such services but
for the Company’s failure to perform any of its obligations under the Agreement). On October 27,
2009, 212 filed a Demand for Arbitration and Statement of Claim and alleged that the Company
delayed the performance of its duty to obtain permits and construct the site under the Agreement.
212 contends, in essence, that the Company delayed obtaining permits for the operation of the
Mobile Pods and that the Company owes the monthly fee for the Mobile Pods for the period commencing
on October 1, 2009. The Company has denied 212’s claims and
21
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(8) Commitments and Contingencies, Continued
contends, in essence, that 212 has still not demonstrated that the Mobile Pods are capable of
treating and discharging to surface waters fluid produced by the Company’s oil and gas operations
in compliance with applicable law and permits. The Company has also filed counterclaims. The
matter is currently set for arbitration on November 29, 2010, but the Company has filed a motion
seeking a delay of the hearing for a time sufficient to obtain and analyze a variety of test
results to determine whether or not the operation of the Mobile Pods complies with applicable law
and permits. While the Company believes it has meritorious defenses to 212’s claims and has valid
counterclaims, the Company is unable to predict the ultimate outcome of the arbitration.
The Company’s indirect, 49.8% owned affiliate DHS Drilling Company (“DHS”) and certain of its
officers and employees, among others, have been notified by the Office of the Inspector General of
the Export-Import Bank of the United States and the U.S. Department of Justice that they are the
subject of an investigation in connection with a loan guaranty sought from the Export-Import Bank
in the first quarter of 2010 of a loan from a Mexican bank to a DHS customer in Mexico. DHS has
cooperated and will continue to cooperate with the investigation, which is currently in its initial
stages. This investigation is subject to uncertainties and, as such, DHS is unable to estimate the
nature of any possible loss or range of loss that may result. DHS and the Company may also be
responsible to indemnify certain officers and employees in connection with their individual
defenses relating to the investigation.
(9) Stockholders’ Equity
|
Preferred Stock
|
The Company has 3,000,000 shares of preferred stock authorized, issuable from time to time in one
or more series. As of September 30, 2010 and December 31, 2009, no shares of preferred stock were
outstanding.
|
Common Stock
|
During the three months ended March 31, 2010, the Company issued 480,778 fully vested shares to the
non-employee members of the Board of Directors in consideration for their service on the Board for
the year ended December 31, 2009. On September 16, 2010, the Company granted 5.1 million shares of
non-vested common stock to certain employees. The shares vest in full on July 1, 2011.
22
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(9) Stockholders’ Equity, Continued
|
Treasury Stock
|
During 2008, DHS implemented a retention bonus plan whereby certain key managers of DHS were
granted shares of Delta common stock, one-third of which vest on each one year anniversary of the
grant date. In addition, similar incentive grants were made to DHS executives during 2008. The
shares of Delta common stock used to fund the grants were proportionally provided by Delta’s
issuance of new shares to DHS employees and Chesapeake’s contribution to DHS of Delta shares
purchased in the open market. The Delta shares contributed by Chesapeake are recorded at
historical cost in the accompanying consolidated balance sheet as treasury stock and will be
carried as such until the shares vest. The Delta shares contributed by Delta are treated as
non-vested stock issued to employees and therefore recorded as additions to additional paid in
capital over the vesting period. Compensation expense is recorded on all such grants over the
vesting period.
|
Stock Based Compensation
|
The Company recognized stock compensation included in general and administrative expense as follows
(in thousands):
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
|
Non-vested stock
|
$ | 1,716 | $ | 2,436 | $ | 8,187 | $ | 5,371 | ||||||||
|
Stock options
|
109 | — | 109 | — | ||||||||||||
|
Performance shares
|
131 | 358 | 512 | 2,062 | ||||||||||||
|
|
||||||||||||||||
|
Total
|
$ | 1,956 | $ | 2,794 | $ | 8,808 | $ | 7,433 | ||||||||
|
|
||||||||||||||||
The Company recognizes the cost of share based payments over the period during which the
employee provides service. During the three months ended September 30, 2010, the Company issued
250,000 fully vested stock options at an exercise price of $0.79 per share to the Company’s Chief
Executive Officer. Other than the stock option issuance during the third quarter of 2010, the
Company had not issued stock options since July 2005 and as all prior outstanding stock options are
fully vested, no compensation cost was recognized with respect to stock options in the 2009 periods
shown in the table above. Exercise prices for options outstanding under the Company’s various
plans as of September 30, 2010 ranged from $0.79 to $15.34 per share. At September 30, 2010, there
was no unrecognized compensation cost related to stock options as all outstanding options are
vested. At September 30, 2010, the Company had 1,608,000 options outstanding at a weighted average
exercise price of $7.25 per share. At September 30, 2010, the Company had 7,775,000 non-vested
shares outstanding and 80,000 performance shares outstanding. At September 30, 2010, the total
unrecognized compensation cost related to the performance shares and
the non-vested portion of
restricted stock was $9.3
million which is expected to be recognized over a weighted average period of 1.1 years.
23
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(10) Income Taxes
Income tax expense (benefit) attributable to loss from continuing operations was approximately
$86,000 and $265,000 for the three months ended September 30, 2010 and 2009, respectively, and
$564,000 and $(53,000) for the nine months ended September 30, 2010 and 2009, respectively.
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 in order to recognize deferred tax assets and a valuation
allowance has been recorded for the Company’s net deferred tax assets at September 30, 2010.
During the three and nine months ended September 30, 2010, DHS recorded net operating losses and as
of September 30, 2010 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.
During the remainder of 2010 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 nine months ended September 30, 2010 and 2009, no adjustments were recognized
for uncertain tax benefits.
(11) 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 | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
|
Net income (loss) attributable to Delta
common stockholders
|
$ | 13,942 | $ | (96,827 | ) | $ | (148,606 | ) | $ | (294,698 | ) | |||||
|
|
||||||||||||||||
|
Basic weighted-average common shares outstanding
|
275,306 | 275,465 | 275,437 | 189,740 | ||||||||||||
|
Add: dilutive effects of stock options and
unvested stock grants
|
6,757 | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Diluted weighted-average common shares outstanding
|
282,063 | 275,465 | 275,437 | 189,740 | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Net income (loss) per common share attributable to
Delta common stockholders
|
||||||||||||||||
|
Basic
|
$ | 0.05 | $ | (0.35 | ) | $ | (0.54 | ) | $ | (1.55 | ) | |||||
|
|
||||||||||||||||
|
Diluted
|
$ | 0.05 | $ | (0.35 | ) | $ | (0.54 | ) | $ | (1.55 | ) | |||||
|
|
||||||||||||||||
24
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(11) Earnings Per Share, Continued
Potentially dilutive securities excluded from the calculation of diluted shares outstanding include
the following (in thousands):
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
|
Stock issuable upon conversion of convertible notes
|
3,790 | 3,790 | 3,790 | 3,790 | ||||||||||||
|
Stock options
|
1,608 | 1,428 | 1,608 | 1,428 | ||||||||||||
|
Performance share grants
|
— | 150 | 80 | 150 | ||||||||||||
|
Non-vested restricted stock
|
— | 1,270 | 7,775 | 1,270 | ||||||||||||
|
|
||||||||||||||||
|
Total potentially dilutive securities
|
5,398 | 6,638 | 13,253 | 6,638 | ||||||||||||
|
|
||||||||||||||||
(12) Guarantor Financial Information
On March 15, 2005, Delta issued $150.0 million of 7% senior notes (“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 (“Convertible Notes”). Both the Senior Notes and the Convertible Notes are
guaranteed by all of the Company’s wholly-owned subsidiaries (“Guarantors”). 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 (“Non-guarantors”) 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 September 30, 2010 and December 31, 2009, the condensed consolidated statements of operations
for the three and nine months ended September 30, 2010 and 2009, and the condensed consolidated
statements of cash flows for the nine months ended September 30, 2010 and 2009 (in thousands). 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.
25
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(12) Guarantor Financial Information, Continued
September 30, 2010
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
Current assets
|
$ | 140,921 | $ | 298 | $ | 15,782 | $ | — | $ | 157,001 | ||||||||||
|
|
||||||||||||||||||||
|
Property and equipment:
|
||||||||||||||||||||
|
Oil and gas properties
|
1,083,550 | — | 19,215 | (117 | ) | 1,102,648 | ||||||||||||||
|
Drilling rigs and trucking equipment
|
594 | — | 173,851 | — | 174,445 | |||||||||||||||
|
Other
|
78,871 | 32,617 | 1,781 | — | 113,269 | |||||||||||||||
|
|
||||||||||||||||||||
|
Total property and equipment
|
1,163,015 | 32,617 | 194,847 | (117 | ) | 1,390,362 | ||||||||||||||
|
|
||||||||||||||||||||
|
Accumulated depletion and depreciation
|
(371,084 | ) | (28,702 | ) | (112,891 | ) | — | (512,677 | ) | |||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net property and equipment
|
791,931 | 3,915 | 81,956 | (117 | ) | 877,685 | ||||||||||||||
|
|
||||||||||||||||||||
|
Investment in subsidiaries
|
3,570 | — | — | (3,570 | ) | — | ||||||||||||||
|
Other long-term assets
|
109,136 | 2,407 | 126 | — | 111,669 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total assets
|
$ | 1,045,558 | $ | 6,620 | $ | 97,864 | $ | (3,687 | ) | $ | 1,146,355 | |||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Current liabilities
|
$ | 162,543 | $ | (27 | ) | $ | 80,279 | $ | — | $ | 242,795 | |||||||||
|
|
||||||||||||||||||||
|
Long-term liabilities:
|
||||||||||||||||||||
|
Long-term debt, derivative instruments
and deferred taxes
|
352,605 | 1,801 | — | — | 354,406 | |||||||||||||||
|
Asset retirement obligations
|
3,942 | — | — | — | 3,942 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total long-term liabilities
|
356,547 | 1,801 | — | — | 358,348 | |||||||||||||||
|
|
||||||||||||||||||||
|
Total Delta stockholders’ equity
|
526,822 | 4,846 | 17,585 | (3,687 | ) | 545,566 | ||||||||||||||
|
|
||||||||||||||||||||
|
Non-controlling interest
|
(354 | ) | — | — | — | (354 | ) | |||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total equity
|
526,468 | 4,846 | 17,585 | (3,687 | ) | 545,212 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total liabilities and equity
|
$ | 1,045,558 | $ | 6,620 | $ | 97,864 | $ | (3,687 | ) | $ | 1,146,355 | |||||||||
|
|
||||||||||||||||||||
26
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(12) Guarantor Financial Information, Continued
Condensed Consolidated Balance Sheet
December 31, 2009
December 31, 2009
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
|
Current assets
|
$ | 160,408 | $ | 448 | $ | 31,596 | $ | — | $ | 192,452 | ||||||||||
|
|
||||||||||||||||||||
|
Property and equipment:
|
||||||||||||||||||||
|
Oil and gas properties
|
1,529,920 | 592 | 130,837 | (585 | ) | 1,660,764 | ||||||||||||||
|
Drilling rigs and trucking equipment
|
594 | — | 177,168 | — | 177,762 | |||||||||||||||
|
Other
|
73,383 | 32,916 | 1,919 | — | 108,218 | |||||||||||||||
|
|
||||||||||||||||||||
|
Total property and equipment
|
1,603,897 | 33,508 | 309,924 | (585 | ) | 1,946,744 | ||||||||||||||
|
|
||||||||||||||||||||
|
Accumulated depletion and depreciation
|
(652,432 | ) | (24,040 | ) | (124,029 | ) | — | (800,501 | ) | |||||||||||
|
|
||||||||||||||||||||
|
Net property and equipment
|
951,465 | 9,468 | 185,895 | (585 | ) | 1,146,243 | ||||||||||||||
|
|
||||||||||||||||||||
|
Investment in subsidiaries
|
80,058 | — | — | (80,058 | ) | — | ||||||||||||||
|
Other long-term assets
|
114,820 | 3,787 | 183 | — | 118,790 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total assets
|
$ | 1,306,751 | $ | 13,703 | $ | 217,674 | $ | (80,643 | ) | $ | 1,457,485 | |||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Current liabilities
|
$ | 179,302 | $ | 319 | $ | 92,579 | $ | — | $ | 272,200 | ||||||||||
|
|
||||||||||||||||||||
|
Long-term liabilities:
|
||||||||||||||||||||
|
Long-term debt, derivative instruments
and deferred taxes
|
478,710 | 1,801 | — | — | 480,511 | |||||||||||||||
|
Asset retirement obligations
|
7,358 | 11 | 285 | — | 7,654 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total long-term liabilities
|
486,068 | 1,812 | 285 | — | 488,165 | |||||||||||||||
|
|
||||||||||||||||||||
|
Total Delta stockholders’ equity
|
632,843 | 11,572 | 124,810 | (80,643 | ) | 688,582 | ||||||||||||||
|
|
||||||||||||||||||||
|
Non-controlling interest
|
8,538 | — | — | — | 8,538 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total equity
|
641,381 | 11,572 | 124,810 | (80,643 | ) | 697,120 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total liabilities and equity
|
$ | 1,306,751 | $ | 13,703 | $ | 217,674 | $ | (80,643 | ) | $ | 1,457,485 | |||||||||
|
|
||||||||||||||||||||
27
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(12) Guarantor Financial Information, Continued
Three Months Ended September 30, 2010
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
Total revenue
|
$ | 20,232 | $ | — | $ | 15,204 | $ | — | $ | 35,436 | ||||||||||
|
|
||||||||||||||||||||
|
Operating expenses:
|
||||||||||||||||||||
|
Oil and gas expenses
|
10,353 | — | — | — | 10,353 | |||||||||||||||
|
Exploration expense
|
368 | — | — | — | 368 | |||||||||||||||
|
Dry hole costs and impairments
|
(291 | ) | 29 | — | — | (262 | ) | |||||||||||||
|
Depreciation and depletion
|
14,410 | — | 4,801 | — | 19,211 | |||||||||||||||
|
Drilling and trucking operating expenses
|
— | — | 12,041 | — | 12,041 | |||||||||||||||
|
General and administrative
|
7,834 | 12 | 2,499 | — | 10,345 | |||||||||||||||
|
Executive severance expense, net
|
(674 | ) | — | — | — | (674 | ) | |||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total operating expenses
|
32,000 | 41 | 19,341 | — | 51,382 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Operating loss
|
(11,768 | ) | (41 | ) | (4,137 | ) | — | (15,946 | ) | |||||||||||
|
|
||||||||||||||||||||
|
Other income and (expense)
|
(449 | ) | 6 | (2,287 | ) | — | (2,730 | ) | ||||||||||||
|
Income tax expense
|
(86 | ) | — | — | — | (86 | ) | |||||||||||||
|
Discontinued operations
|
61,715 | (304 | ) | (31,916 | ) | — | 29,495 | |||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net income (loss)
|
49,412 | (339 | ) | (38,340 | ) | — | 10,733 | |||||||||||||
|
|
||||||||||||||||||||
|
Less income (loss) attributable to
non-controlling interest
|
3,209 | — | — | — | 3,209 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net income (loss) attributable to
Delta common stockholders
|
$ | 52,621 | $ | (339 | ) | $ | (38,340 | ) | $ | — | $ | 13,942 | ||||||||
|
|
||||||||||||||||||||
Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2009
Three Months Ended September 30, 2009
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
Total revenue
|
$ | 18,909 | $ | — | $ | 2,589 | $ | (51 | ) | $ | 21,447 | |||||||||
|
|
||||||||||||||||||||
|
Operating expenses:
|
||||||||||||||||||||
|
Oil and gas expenses
|
9,554 | — | — | — | 9,554 | |||||||||||||||
|
Exploration expense
|
891 | — | — | — | 891 | |||||||||||||||
|
Dry hole costs and impairments
|
53,407 | — | — | — | 53,407 | |||||||||||||||
|
Depreciation and depletion
|
20,014 | 51 | 5,545 | — | 25,610 | |||||||||||||||
|
Drilling and trucking operations
|
— | — | 2,891 | (73 | ) | 2,818 | ||||||||||||||
|
General and administrative
|
8,945 | 32 | 976 | — | 9,953 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total operating expenses
|
92,811 | 83 | 9,412 | (73 | ) | 102,233 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Operating income (loss)
|
(73,902 | ) | (83 | ) | (6,823 | ) | 22 | (80,786 | ) | |||||||||||
|
|
||||||||||||||||||||
|
Other income and (expenses)
|
(14,004 | ) | 5 | (1,494 | ) | — | (15,493 | ) | ||||||||||||
|
Income tax benefit (expense)
|
(265 | ) | — | — | — | (265 | ) | |||||||||||||
|
Discontinued operations
|
(1,905 | ) | 64 | (2,588 | ) | — | (4,429 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss
|
(90,076 | ) | (14 | ) | (10,905 | ) | 22 | (100,973 | ) | |||||||||||
|
|
||||||||||||||||||||
|
Less loss attributable to non-controlling interest
|
4,146 | — | — | — | 4,146 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net income (loss) attributable to
Delta common stockholders
|
$ | (85,930 | ) | $ | (14 | ) | $ | (10,905 | ) | $ | 22 | $ | (96,827 | ) | ||||||
|
|
||||||||||||||||||||
28
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2010
Nine Months Ended September 30, 2010
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
Total revenue
|
$ | 74,118 | $ | 77 | $ | 36,995 | $ | (795 | ) | $ | 110,395 | |||||||||
|
|
||||||||||||||||||||
|
Operating expenses:
|
||||||||||||||||||||
|
Oil and gas expenses
|
35,858 | — | — | — | 35,858 | |||||||||||||||
|
Exploration expense
|
952 | — | — | — | 952 | |||||||||||||||
|
Dry hole costs and impairments
|
25,439 | 4,834 | 586 | — | 30,859 | |||||||||||||||
|
Depreciation and depletion
|
45,538 | 2 | 15,663 | (64 | ) | 61,139 | ||||||||||||||
|
Drilling and trucking operating expenses
|
— | — | 28,666 | (613 | ) | 28,053 | ||||||||||||||
|
General and administrative
|
28,635 | 41 | 4,696 | — | 33,372 | |||||||||||||||
|
Executive severance expense, net
|
(674 | ) | — | — | — | (674 | ) | |||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total operating expenses
|
135,748 | 4,877 | 49,611 | (677 | ) | 189,559 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Operating loss
|
(61,630 | ) | (4,800 | ) | (12,616 | ) | (118 | ) | (79,164 | ) | ||||||||||
|
|
||||||||||||||||||||
|
Other income and (expense)
|
465 | — | (6,265 | ) | — | (5,800 | ) | |||||||||||||
|
Income tax expense
|
(564 | ) | — | — | — | (564 | ) | |||||||||||||
|
Discontinued operations
|
20,845 | (200 | ) | (92,857 | ) | — | (72,212 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss
|
(40,884 | ) | (5,000 | ) | (111,738 | ) | (118 | ) | (157,740 | ) | ||||||||||
|
|
||||||||||||||||||||
|
Less loss attributable to
non-controlling interest
|
9,134 | — | — | — | 9,134 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss attributable to
Delta common stockholders
|
$ | (31,750 | ) | $ | (5,000 | ) | $ | (111,738 | ) | $ | (118 | ) | $ | (148,606 | ) | |||||
|
|
||||||||||||||||||||
Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2009
Nine Months Ended September 30, 2009
| Guarantor | Non-Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Entities | Entities | Eliminations | Consolidated | ||||||||||||||||
|
Total revenue
|
$ | 87,840 | $ | — | $ | 12,409 | $ | (2,984 | ) | $ | 97,265 | |||||||||
|
|
||||||||||||||||||||
|
Operating expenses:
|
||||||||||||||||||||
|
Oil and gas expenses
|
31,143 | — | — | — | 31,143 | |||||||||||||||
|
Exploration expense
|
2,422 | — | — | — | 2,422 | |||||||||||||||
|
Dry hole costs and impairments
|
153,067 | 1,896 | 6,508 | — | 161,471 | |||||||||||||||
|
Depreciation and depletion
|
62,830 | 162 | 18,091 | (579 | ) | 80,504 | ||||||||||||||
|
Drilling and trucking operations
|
— | — | 12,238 | (1,822 | ) | 10,416 | ||||||||||||||
|
General and administrative
|
28,191 | 67 | 3,287 | — | 31,545 | |||||||||||||||
|
Executive severance expense, net
|
3,739 | — | — | — | 3,739 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Total operating expenses
|
281,392 | 2,125 | 40,124 | (2,401 | ) | 321,240 | ||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Operating income (loss)
|
(193,552 | ) | (2,125 | ) | (27,715 | ) | (583 | ) | (223,975 | ) | ||||||||||
|
|
||||||||||||||||||||
|
Other income and (expenses)
|
(64,831 | ) | 25 | (5,459 | ) | — | (70,265 | ) | ||||||||||||
|
Income tax benefit (expense)
|
(741 | ) | — | 794 | — | 53 | ||||||||||||||
|
Discontinued operations
|
(8,476 | ) | 178 | (8,404 | ) | — | (16,702 | ) | ||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss
|
(267,600 | ) | (1,922 | ) | (40,784 | ) | (583 | ) | (310,889 | ) | ||||||||||
|
|
||||||||||||||||||||
|
Less loss attributable to non-controlling interest
|
16,191 | — | — | — | 16,191 | |||||||||||||||
|
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
Net loss attributable to
Delta common stockholders
|
$ | (251,409 | ) | $ | (1,922 | ) | $ | (40,784 | ) | $ | (583 | ) | $ | (294,698 | ) | |||||
|
|
||||||||||||||||||||
29
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(12) Guarantor Financial Information, Continued
Nine Months Ended September 30, 2010
| Guarantor | Non-Guarantor | |||||||||||||||
| Issuer | Entities | Entities | Consolidated | |||||||||||||
|
Cash provided by (used in):
|
||||||||||||||||
|
Operating activities
|
$ | (40,857 | ) | $ | (665 | ) | $ | 15,564 | $ | (25,958 | ) | |||||
|
Investing activities
|
97,888 | 622 | (3,670 | ) | 94,840 | |||||||||||
|
Financing activities
|
(104,450 | ) | — | (12,153 | ) | (116,603 | ) | |||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Net increase (decrease) in cash and
cash equivalents
|
(47,419 | ) | (43 | ) | (259 | ) | (47,721 | ) | ||||||||
|
|
||||||||||||||||
|
Cash at beginning of the period
|
58,533 | 74 | 3,311 | 61,918 | ||||||||||||
|
|
||||||||||||||||
|
Cash at the end of the period
|
$ | 11,114 | $ | 31 | $ | 3,052 | $ | 14,197 | ||||||||
|
|
||||||||||||||||
Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2009
Nine Months Ended September 30, 2009
| Guarantor | Non-Guarantor | |||||||||||||||
| Issuer | Entities | Entities | Consolidated | |||||||||||||
|
Cash provided by (used in):
|
||||||||||||||||
|
Operating activities
|
$ | 15,662 | $ | 154 | $ | 4,343 | $ | 20,159 | ||||||||
|
Investing activities
|
(140,056 | ) | (227 | ) | 3,083 | (137,200 | ) | |||||||||
|
Financing activities
|
72,749 | — | (10,500 | ) | 62,249 | |||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Net decrease in cash and
cash equivalents
|
(51,645 | ) | (73 | ) | (3,074 | ) | (54,792 | ) | ||||||||
|
|
||||||||||||||||
|
Cash at beginning of the period
|
60,993 | 151 | 4,331 | 65,475 | ||||||||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Cash at the end of the period
|
$ | 9,348 | $ | 78 | $ | 1,257 | $ | 10,683 | ||||||||
|
|
||||||||||||||||
30
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(13) 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. Following is a
summary of segment results for the three and nine months ended September 30, 2010 and 2009:
| Inter-segment | ||||||||||||||||
| Oil and Gas | Drilling | Eliminations | Consolidated | |||||||||||||
| (In thousands) | ||||||||||||||||
|
Three Months Ended September 30, 2010
|
||||||||||||||||
|
Revenues from external customers
|
$ | 20,232 | $ | 15,204 | $ | — | $ | 35,436 | ||||||||
|
Inter-segment revenues
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Total revenues
|
$ | 20,232 | $ | 15,204 | $ | — | $ | 35,436 | ||||||||
|
|
||||||||||||||||
|
Operating loss
|
$ | (11,836 | ) | $ | (4,110 | ) | $ | — | $ | (15,946 | ) | |||||
|
|
||||||||||||||||
|
Other income (expense)
|
(442 | ) | (2,288 | ) | — | (2,730 | ) | |||||||||
|
|
||||||||||||||||
|
Loss from continuing operations, before tax
|
$ | (12,278 | ) | $ | (6,398 | ) | $ | — | $ | (18,676 | ) | |||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Three Months Ended September 30, 2009
|
||||||||||||||||
|
Revenues from external customers
|
$ | 18,909 | $ | 2,538 | $ | — | $ | 21,447 | ||||||||
|
Inter-segment revenues
|
— | 51 | (51 | ) | — | |||||||||||
|
|
||||||||||||||||
|
Total revenues
|
$ | 18,909 | $ | 2,589 | $ | (51 | ) | $ | 21,447 | |||||||
|
|
||||||||||||||||
|
Operating loss
|
$ | (74,043 | ) | $ | (6,765 | ) | $ | 22 | $ | (80,786 | ) | |||||
|
|
||||||||||||||||
|
Other income (expense)
|
(13,995 | ) | (1,498 | ) | — | (15,493 | ) | |||||||||
|
|
||||||||||||||||
|
Loss from continuing operations, before tax
|
$ | (88,038 | ) | $ | (8,263 | ) | $ | 22 | $ | (96,279 | ) | |||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Nine Months Ended September 30, 2010
|
||||||||||||||||
|
Revenues from external customers
|
$ | 74,195 | $ | 36,200 | $ | — | $ | 110,395 | ||||||||
|
Inter-segment revenues
|
— | 795 | (795 | ) | — | |||||||||||
|
|
||||||||||||||||
|
Total revenues
|
$ | 74,195 | $ | 36,995 | $ | (795 | ) | $ | 110,395 | |||||||
|
|
||||||||||||||||
|
Operating loss
|
$ | (67,111 | ) | $ | (11,935 | ) | $ | (118 | ) | $ | (79,164 | ) | ||||
|
|
||||||||||||||||
|
Other income (expense)
|
469 | (6,269 | ) | — | (5,800 | ) | ||||||||||
|
|
||||||||||||||||
|
Loss from continuing operations, before tax
|
$ | (66,642 | ) | $ | (18,204 | ) | $ | (118 | ) | $ | (84,964 | ) | ||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
Nine Months Ended September 30, 2009
|
||||||||||||||||
|
Revenues from external customers
|
$ | 87,840 | $ | 9,425 | $ | — | $ | 97,265 | ||||||||
|
Inter-segment revenues
|
— | 2,984 | (2,984 | ) | — | |||||||||||
|
|
||||||||||||||||
|
Total revenues
|
$ | 87,840 | $ | 12,409 | $ | (2,984 | ) | $ | 97,265 | |||||||
|
|
||||||||||||||||
|
Operating loss
|
$ | (195,794 | ) | $ | (27,598 | ) | $ | (583 | ) | $ | (223,975 | ) | ||||
|
|
||||||||||||||||
|
Other income (expense)
|
(64,806 | ) | (5,459 | ) | — | (70,265 | ) | |||||||||
|
|
||||||||||||||||
|
Loss from continuing operations, before tax
|
$ | (260,600 | ) | $ | (33,057 | ) | $ | (583 | ) | $ | (294,240 | ) | ||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
September 30, 2010:
|
||||||||||||||||
|
Total Assets
|
$ | 1,137,370 | $ | 77,650 | $ | (68,665 | ) | $ | 1,146,355 | |||||||
|
|
||||||||||||||||
|
|
||||||||||||||||
|
December 31, 2009:
|
||||||||||||||||
|
Total Assets
|
$ | 1,440,529 | $ | 104,287 | $ | (87,331 | ) | $ | 1,457,485 | |||||||
|
|
||||||||||||||||
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.
31
Table of Contents
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
(14) Subsequent Events
On October 28, 2010, the Company paid the second of three installments payable related to its
February 2008 acquisition of leasehold interests in the Piceance Basin from EnCana Oil & Gas (USA)
Inc. The $100.0 million payment was funded with restricted cash on hand. The remaining $100
million installment is payable on November 1, 2011. This remaining installment is collateralized by
a letter of credit that is backed by restricted deposits held by the letter of credit issuer.
On October 29, 2010, $17.75 million of Wapiti Transaction proceeds originally escrowed at closing
pending the receipt of third party consents and exercise of rights of first refusals were released
from escrow. Of the total amount escrowed, $15.9 million was released on Delta’s behalf and paid
directly to JPMorgan to reduce amounts outstanding under the credit facility. The remaining $1.9
million was released to Wapiti because a right of first refusal held by a third party was
exercised. The sale of the right of first refusal properties to the third party was consummated on
October 26, 2010, at which time Delta received sales proceeds of $1.9 million, before normal and
customary purchase price adjustments.
32
Table of Contents
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 strategic plans; our expectations with respect to
replacing our existing credit facility with a new credit facility; operating strategies;
anticipated borrowing capacity; our expectation that we will have adequate cash from operations,
credit facility borrowings and other capital sources to satisfy our obligations under our Second
Amended and Restated Credit Agreement, as amended, and to meet future debt service, capital
expenditure and working capital requirements; anticipated utilization of joint venture and
partnership structures; acquisition and divestiture strategies; completion and drilling program
expectations, processes and emphasis; oil and gas reserve estimates (including estimates of future
net revenues associated with such reserves and the present value of such future net revenues);
availability of capital to develop our reserves; estimates of future production of oil and natural
gas; marketing of oil and natural gas; expected future revenues and earnings, and results of
operations; future capital, development and exploration expenditures (including the amount and
nature thereof); nonpayment of dividends; expectations regarding competition and our competitive
advantages; 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; 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 “Risk Factors” in our annual report on Form 10-K, 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:
| • |
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 Second Amended and Restated Credit Agreement, as amended, 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 or similar industry 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 availability of borrowings under our credit facility and the ability to obtain a new or
replacement credit facility;
|
33
Table of Contents
| • |
the impact of current economic and financial conditions on our ability to raise capital;
|
||
| • |
the over-supply of natural gas in the U.S. as a result of aggressive development activity;
|
||
| • |
a contraction in the demand for natural gas in the U.S. as a result of depressed general
economic conditions;
|
||
| • |
the ability and willingness of our joint venture partners to fund their obligations to pay
a portion of our future drilling and completion costs;
|
||
| • |
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;
|
||
| • |
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.
34
Table of Contents
Recent Developments
| • |
On July 23, 2010, we entered into a definitive Purchase and Sale Agreement with Wapiti Oil
& Gas, L.L.C. (“Wapiti”) to sell various non-core assets (the “Wapiti Transaction”) for cash
proceeds of $130.0 million. The Wapiti Transaction closed on July 30, 2010 and all amounts
escrowed at the original closing pending third party consents or rights of first refusal were
received by October 28, 2010.
|
||
| • |
Also on July 23, 2010, we entered into the Fourth Amendment to the Second Amended and
Restated Credit Agreement (the “Fourth Amendment”) whereby the requisite banks consented to
the Wapiti Transaction, subject to specified terms and conditions, including, among others,
that the net proceeds from the Wapiti Transaction be used to pay down the balance outstanding
under the credit facility and that the borrowing base be reduced to $35.0 million upon
consummation of the Wapiti Transaction. Additional amendments to the credit facility are
described in Note 7, “Long Term Debt” to the accompanying consolidated financial statements.
The proceeds from the Wapiti Transaction allowed us to substantially reduce our outstanding
debt and when combined with the post-Wapiti Transaction borrowing base, provide the liquidity
necessary to fund our third and fourth quarter 2010 development plan. There are no scheduled
or special borrowing base redeterminations before the maturity of the facility in January
2011 and thus we anticipate having adequate liquidity to fund operations. As noted below, we
are in the process of refinancing the existing credit facility.
|
||
| • |
On April 1, 2010, DHS Drilling Company (“DHS”), the Company’s 49.8% subsidiary, amended
its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain
terms of the agreement, to, among other changes more fully described in Note 7, “Long Term
Debt” to the accompanying financial statements, bring DHS into compliance with the terms of
the agreement, amend the principal repayment schedule, adjust the interest rate, and
eliminate or amend certain financial covenants.
|
2010 Overview
Beginning in November 2009, we were engaged with Morgan Stanley and Evercore Partners to analyze
various alternatives to enhance stockholder value, including a sale of some or all of our assets,
entering into partnerships or joint ventures, or the sale of the entire company.
As a result of the strategic process described above, on July 30, 2010, we completed the $130.0
million sale of certain non-core properties to Wapiti. In conjunction with the completion of this
transaction, we repaid $108.5 million of amounts borrowed under our credit facility, our credit
facility borrowing base was reduced to $35.0 million and capital expenditure limitations under the
credit facility for the third and fourth quarters of 2010 were set at $18.0 million and $10.0
million, respectively.
The Wapiti Transaction was a part of a competitive process initiated in conjunction with the
strategic alternatives process. This process has been concluded and our focus has returned to
creating value with our core assets through operations. The Board of Directors may reevaluate the
renewal of the strategic alternatives process at a later time.
Based on current commodity prices, the Wapiti Transaction, and our amended credit facility terms,
we intend to focus capital expenditures for the remainder of 2010 on completing nine previously
drilled wells and drilling a deeper well to evaluate potential below the Williams Fork formation in
the Vega Area. The capital expenditure limitations provided for in conjunction with our borrowing
base redetermination are expected to be adequate to allow for the funding of these development
plans. Based on this level of development and considering production sold in the Wapiti
Transaction, we expect oil and gas equivalent production for the remainder of 2010 to range between
3.25 Bcfe and 3.55 Bcfe. These plans may be adjusted from time to time depending on commodity
prices, status of our credit facility refinancing efforts or other factors.
35
Table of Contents
Liquidity and Capital Resources
On July 30, 2010, we completed the $130.0 million sale of certain non-core properties to Wapiti,
and paid down $108.5 million of the amount outstanding under our Credit Agreement as discussed
below.
On July 23, 2010, we entered into the Fourth Amendment to the Second Amended and Restated Credit
Agreement (as amended, the “Credit Agreement”), with JPMorgan Chase Bank, N.A., as agent, and
certain of the financial institutions that are party to the Credit Agreement in which, among other
changes, the requisite lenders consented to the Wapiti Transaction, subject to specified terms and
conditions, including that the net proceeds from the transaction be used to pay down the balance
outstanding under the Credit Agreement and that the borrowing base be reduced to $35.0 million upon
consummation of the Wapiti Transaction. The Fourth Amendment eliminated all scheduled or special
borrowing base redeterminations prior to the maturity of the facility in January 2011. In
addition, the Fourth Amendment imposed capital expenditures limitations of $18.0 million for the
quarter ending September 30, 2010, $10.0 million for the quarter ending December 31, 2010, and $2.0
million for the period from January 1, 2011 to January 15, 2011, provided that any excess of the
limitation over the amount of actual expenditures may be carried forward from an earlier specified
period to a subsequent specified period. The Fourth Amendment added a maximum cash on hand
covenant which limits our cash and cash equivalents to $10.0 million at any time, with any excess
above such limit required to be used to pay down borrowings under the credit facility within three
business days. Finally, the Fourth Amendment requires cash disbursements for general and
administrative expenses to be within a 10% variance of projected general and administrative
expenses provided to the lending banks in conjunction with the execution of the Fourth Amendment.
We were in compliance with the financial ratio, capital expenditures, maximum cash and accounts
payables covenants under the Credit Agreement at September 30, 2010, and have been, and are in
compliance with the additional covenants outlined above through the date hereof.
On April 1, 2010 DHS amended its existing credit facility with Lehman Commercial Paper, Inc. and
renegotiated certain terms of the agreement, as described in “Recent Developments” above.
Our accompanying financial statements have been prepared assuming we will continue as a going
concern. We experienced a net loss attributable to Delta common stockholders of $148.6 million for
the nine months ended September 30, 2010, and as of September 30, 2010 had a working capital
deficiency of $85.8 million, including $21.5 million outstanding under Delta’s credit facility
which matures on January 15, 2011 and $71.6 million outstanding under DHS’s credit agreement which
matures on August 31, 2011. In addition, the holders of our $115.0 million principal amount of 3
3
/
4
%
Senior Convertible Notes due 2037 have the right to require us to purchase all or a portion of such
notes on May 1, 2012 (or thereafter on each May 1 in 2017, 2022, 2027 and 2032). The ongoing
losses, near term credit maturities, and working capital deficiency raise substantial doubt about
our ability to continue as a going concern.
Taking into consideration the assets sold and proceeds received to date as a result of the
strategic evaluation process, we will need to raise additional cash or refinance our existing
credit facility with new or existing lenders in order to pay our outstanding borrowings under the
Credit Agreement which are due January 15, 2011. As such, we expect to replace the existing facility prior to its
maturity, although it is expected that the interest terms and covenant requirements will be more
expensive and restrictive, respectively, than the current facility’s rates and terms. The initial
term of any new credit facility is expected to
provide for maturity prior to May 1, 2012, when the holders of our $115.0 million principal amount
of 3
3
/
4
% Senior Convertible Notes have the right to require us to purchase all or a portion of the
notes. As a result, it is anticipated that prior to May 1, 2012, we will need to obtain additional
capital in order to repay any amounts outstanding under any new credit facility and to purchase any
3
3
/
4
% Senior Convertible Notes required by the holders of such notes to be purchased by us.
We experienced a net loss attributable to Delta common stockholders of $148.6 million for the nine
months ended September 30, 2010. During the nine months ended September 30, 2010, we had an
operating loss of $79.2 million, net cash used in operating activities of $26.0 million and net
cash used in financing activities of $116.6 million.
36
Table of Contents
During the nine months ended September 30, 2010, we had cash provided by investing activities of
$94.8 million, net of $25.0 million invested in oil and gas development activities. At September
30, 2010, we had $14.2 million in cash and remaining availability under the Credit Agreement of
approximately $13.5 million, total assets of $1.1 billion and a debt to capitalization ratio of
39.1%. Debt, excluding installments payable on property acquisition which are secured by restricted
cash deposits, at September 30, 2010 totaled $350.2 million, comprised of $93.1 million of bank
debt ($21.5 million of our indebtedness under our Credit Agreement and $71.6 million of DHS credit
facility indebtedness, all of which is classified as current in the accompanying consolidated
financial statements), $149.7 million of senior notes and $107.4 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.
As of October 29, 2010, 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 October
29, 2010, 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.”
Other than in connection with the refinancing and repayment of our debt as discussed above, our
future cash requirements are largely dependent upon the number and timing of projects included in
our capital development plan, most of which are discretionary. We have historically addressed our
long-term liquidity requirements through the issuance of debt and equity securities when market
conditions permit, through cash provided by operating activities, sales of oil and gas properties,
and through borrowings under our credit facility.
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. We are unable to predict with any degree of
certainty the prices we will receive for our future oil and gas production and the success of our
exploration and development activities in generating additional production.
There can be no assurance that the actions undertaken by us will be sufficient to repay the
obligations under our credit facility, or, if not, or if additional defaults occur under that
facility, that the lenders will be willing to waive further defaults or amend the facility.
Although our current level of borrowing capacity under the Credit Agreement is expected to remain
the same through maturity because the Fourth Amendment provided that no scheduled or special
redetermination will occur prior to the maturity of the facility, there can be no assurance that
our current level of borrowing capacity will be maintained under a new credit agreement, or in the
event that we are unable to consummate a new facility, that we will be successful in negotiating an
extension to the Credit Agreement, or a replacement thereto, upon its scheduled maturity in January
2011. There can similarly be no assurance that DHS will be successful in negotiating an extension
to the DHS credit facility, or a replacement thereto, upon its scheduled maturity in August 2011.
In addition, there can be no assurance that results of operations and other sources of liquidity,
including asset sales, will be sufficient to meet contractual, operating and capital obligations.
Our financial statements do not include any adjustments that might result from the outcome of
uncertainty regarding our ability to raise additional capital, sell assets, or otherwise obtain
sufficient funds to meet our obligations or to continue as a going concern.
We continue to examine additional sources of long-term capital (including a restructured debt
facility, the issuance of debt instruments, sales of assets and joint venture financing), as well
as other potential corporate transactions. The availability of additional sources of capital,
which will impact our ability to execute our operating strategy and meet our liquidity challenges,
will depend upon a number of factors, many of which are beyond our control.
37
Table of Contents
Results of Operations
The following discussion and analysis relates to items that have affected our results of operations
for the three months ended September 30, 2010 and 2009. 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 September 30, 2010 Compared to Three Months Ended September 30, 2009
Net Income (Loss) Attributable to Delta Common Stockholders.
Net income attributable to Delta
common stockholders was $13.9 million, or $0.05 per diluted common share, for the three months
ended September 30, 2010, compared to a net loss attributable to Delta common stockholders of $96.8
million, or $0.35 per diluted common share, for the three months ended September 30, 2009. There
were a number of items affecting comparability between periods including contract drilling and
trucking fees and expenses, impairments, depletion expense, and unrealized gains and losses on
derivative instruments. Explanations of significant items affecting comparability between periods
are discussed by financial statement caption below.
Oil and Gas Sales.
During the three months ended September 30, 2010, oil and gas sales increased
6% to $20.2 million, as compared to $19.1 million for the comparable period a year earlier. The
increase was principally the result of a 79% increase in natural gas prices and a 12% increase in
oil prices, partially offset by a 23% decrease in production. The average natural gas price
received during the three months ended September 30, 2010 increased to $4.52 per Mcf compared to
$2.52 per Mcf for the year earlier period. The average oil price received during the three months
ended September 30, 2010 increased to $69.13 per Bbl compared to $61.89 per Bbl for the year
earlier period. The production decrease was primarily related to lower volumes as a result of the
sale to Wapiti.
Contract Drilling and Trucking Fees.
Contract drilling and trucking fees for the three months ended
September 30, 2010 increased to $15.2 million compared to $2.5 million in the prior year. The
increase is the result of improved third party rig utilization in the three months ended September
30, 2010 resulting from an increased industry demand attributable to improved commodity prices.
Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the three months ended
September 30, 2010 and 2009 are as follows:
| Three Months Ended | ||||||||
| September 30, | ||||||||
| 2010 | 2009 | |||||||
|
Production — Continuing Operations:
|
||||||||
|
Oil (Mbbl)
|
116 | 171 | ||||||
|
Gas (Mmcf)
|
2,694 | 3,370 | ||||||
|
Total Production (Mmcfe) — Continuing Operations
|
3,392 | 4,396 | ||||||
|
|
||||||||
|
Average Price — Continuing Operations:
|
||||||||
|
Oil (per barrel)
|
$ | 69.13 | $ | 61.89 | ||||
|
Gas (per Mcf)
|
$ | 4.52 | $ | 2.52 | ||||
|
|
||||||||
|
Costs (per Mcfe) — Continuing Operations:
|
||||||||
|
Lease operating expense
|
$ | 1.76 | $ | 1.55 | ||||
|
Transportation expense
|
$ | 1.00 | $ | 0.46 | ||||
|
Production taxes
|
$ | 0.29 | $ | 0.16 | ||||
|
Depletion expense
|
$ | 4.02 | $ | 4.40 | ||||
|
|
||||||||
|
Realized derivative gains (losses) (per Mcfe)
|
$ | (0.12 | ) | $ | 0.08 | |||
38
Table of Contents
Lease Operating Expense.
Lease operating expenses for the three months ended September 30,
2010 decreased to $6.0 million from $6.8 million in the year earlier period primarily due to lower
water handling costs in the Vega area
as a result of the resumption of development activities and due to the Wapiti sale. Lease
operating expense per Mcfe for the three months ended September 30, 2010 increased to $1.76 per
Mcfe from $1.55 per Mcfe. The quarter-over-quarter increase on a per unit basis was primarily due
to the effect of fixed costs spread over a 23% decline in production volumes.
Transportation Expense.
Transportation expense for the three months ended September 30, 2010
increased to $3.4 million from $2.0 million in the prior year. Transportation expense per Mcfe for
the three months ended September 30, 2010 increased 117% to $1.00 per Mcfe from $0.46 per Mcfe.
The increase on a per unit basis is primarily the result of changes to our Vega gas marketing
contract that went into effect in October 2009 whereby our gas is processed through a higher
efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area
from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.
Production Taxes.
Production taxes for the three months ended September 30, 2010 were $996,000,
as compared to prior year costs of $717,000. Production taxes as a percentage of oil and gas sales
were 4.9% and 3.8% for the three months ended September 30, 2010 and 2009, respectively.
Exploration Expense.
Exploration expense consists primarily of geological and geophysical costs
and delay lease rentals. Our exploration costs for the three months ended September 30, 2010 were
$368,000 compared to $891,000 for the comparable year earlier period. Exploration activities in
both periods primarily relate to delay rental payments.
Dry Hole Costs and Impairments.
We incurred dry hole costs and impairments of $(262,000) for the
three months ended September 30, 2010 as a result of minor cost true-ups compared to $53.4 million
for the comparable period a year ago. During the three months ended September 30, 2009, dry hole
and impairment costs primarily related to $31.0 million of dry hole costs associated with the Gray
31-23 in the Columbia River Basin, $20.4 million of impairments for unproved leaseholds in Columbia
River Basin and $1.9 million of impairments for proved leaseholds in Angleton.
Depreciation, Depletion, Amortization and Accretion — Oil and Gas.
Depreciation, depletion and
amortization expense decreased 28% to $14.4 million for the three months ended September 30, 2010,
as compared to $20.1 million for the comparable year earlier period. Depletion expense for the
three months ended September 30, 2010 decreased to $13.6 million from $19.3 million for the three
months ended September 30, 2009 due to lower production volumes and a decrease in the per unit
depletion rate. Our depletion rate decreased from $4.40 per Mcfe for the three months ended
September 30, 2009 to $4.02 per Mcfe for the current year period primarily due to the effect of
impairments recorded during late 2009 on high depletion rate properties.
Drilling and Trucking Operating Expenses.
Drilling expense increased to $12.0 million for the
three months ended September 30, 2010 compared to $2.8 million for the comparable prior year
period. This increase is due to additional third party rig utilization during the current year
period.
Depreciation and Amortization — Drilling and Trucking.
Depreciation and amortization expense —
drilling and trucking decreased to $4.8 million for the three months ended September 30, 2010, as
compared to $5.5 million for the comparable year earlier period. The decrease is due to the effect
on the depreciation rate of rig impairments recorded during 2009. Depreciation expense is recorded
on a straight line basis and is not impacted by changes in the utilization rate.
General and Administrative Expense.
General and administrative expense increased 3% to $10.3
million for the three months ended September 30, 2010, as compared to $10.0 million for the
comparable prior year period. The increase in general and administrative expenses is attributed to
costs associated with the strategic alternatives evaluation process and $1.4 million of allowance
for doubtful accounts recorded by DHS, partially offset by decreased non-cash stock compensation
expense related to restricted stock granted in December 2009 and by reduced staffing as a result of
reductions in force during the third quarter of 2010 resulting in lower cash compensation expense.
39
Table of Contents
Executive Severance Expense, Net.
On July 6, 2010, John Wallace, the then President, Chief
Operating Officer and a Director of the Company, resigned from all of his positions as director,
officer and employee of the Company and any of its subsidiaries. In conjunction with such
resignation, the Company entered into a severance agreement with Mr. Wallace pursuant to which he
agreed to (a) relinquish certain rights under his employment agreement, his change-in-control
agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting
Delta, and certain other interests he might claim arising from his efforts in his previous
capacities with the Company and its subsidiaries, and (b) make himself reasonably available to
answer questions to facilitate an orderly transition. Under the terms of his severance
arrangement, the Company paid Mr. Wallace a lump sum of $1,600,000, paid him his salary for the
full month in which his resignation occurred and for his accrued vacation days, reimbursed him for
his reasonable business expenses incurred through the effective date of the agreement, and agreed
to provide to him insurance benefits similar to his pre-resignation benefits for the period in
which Mr. Wallace is entitled to receive COBRA coverage under applicable law. The severance
agreement also contained mutual releases and non-disparagement provisions, as well as other
customary terms. In addition, $2.3 million of equity compensation costs previously recorded in the
consolidated financial statements related to performance shares forfeited prior to their derived
service period being completed as a result of the severance agreement were reversed and reflected
as a reduction of executive severance expense.
Interest Expense and Financing Costs, Net.
Interest expense and financing costs, net decreased 4%
to $9.3 million for the three months ended September 30, 2010, as compared to $9.7 million for the
comparable year earlier period. The decrease is primarily related to lower average outstanding
Delta and DHS credit facility balances coupled with lower interest rates during the third quarter
of 2010 as compared to the third quarter of 2009.
Realized Gain (Loss) on Derivative Instruments, Net.
During the three months ended September 30,
2010, we recognized a $418,000 loss associated with settlements on derivative contracts. During the
three months ended September 30, 2009, we recognized a $370,000 gain associated with settlements on
derivative contracts.
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 $7.1 million of unrealized gains on derivative instruments in
other income and expense during the three months ended September 30, 2010 compared to $5.9 million
of unrealized losses for the comparable prior year period.
Income (Loss) From Unconsolidated Affiliates.
Income (loss) from unconsolidated affiliates during
the three months ended September 30, 2010 and 2009 is comprised of our pro-rata share of net income
(loss) of our unconsolidated affiliates.
Income Tax Benefit (Expense).
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 for the three months ended September 30, 2010 and 2009 of $86,000 and $265,000,
respectively, relates only to DHS, as no benefit was provided for our net operating losses.
40
Table of Contents
Discontinued Operations.
The results of operations and impairment loss relating non-core
property interests sold in the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well
as our interest in our wholly-owned subsidiary Piper Petroleum have been reflected as discontinued
operations as a result of the sale to Wapiti. In a separate transaction, during the three
months ended September 30, 2010, we sold our interest in the Howard Ranch field which is also
included in discontinued operations.
The following table shows the total revenues and expenses included in discontinued operations for
the above mentioned oil and gas properties for the three months ended September 30, 2010 and 2009
(dollar amounts in thousands):
| Three Months Ended | ||||||||
| September 30, | ||||||||
| 2010 | 2009 | |||||||
|
Production — Discontinued Operations:
|
||||||||
|
Oil (Mbbl)
|
2 | 9 | ||||||
|
Gas (Mmcf)
|
251 | 688 | ||||||
|
Total Production (Mmcfe) — Discontinued Operations
|
262 | 741 | ||||||
|
|
||||||||
|
Revenues
|
$ | 1,344 | $ | 2,475 | ||||
|
|
||||||||
|
Operating expenses:
|
||||||||
|
|
||||||||
|
Lease operating expense
|
429 | 757 | ||||||
|
Transportation expense
|
181 | 60 | ||||||
|
Production taxes
|
116 | 438 | ||||||
|
Depreciation, depletion, amortization and accretion
|
33 | 5,649 | ||||||
|
Impairment provision
|
— | — | ||||||
|
|
||||||||
|
Total operating expenses
|
759 | 6,904 | ||||||
|
|
||||||||
|
|
||||||||
|
Income (Loss) from discontinued operations
|
585 | (4,429 | ) | |||||
|
Income tax expense
|
— | — | ||||||
|
|
||||||||
|
|
||||||||
|
Income (loss) from results of operations of
discontinued properties, net of tax
|
585 | (4,429 | ) | |||||
|
|
||||||||
|
Gain on sale of discontinued operations
|
28,910 | — | ||||||
|
|
||||||||
|
|
||||||||
|
Total income (loss) from discontinued operations
|
$ | 29,495 | $ | (4,429 | ) | |||
|
|
||||||||
On July 30, 2010, the Company closed on the sale of non-core properties to Wapiti for cash
proceeds of $130.0 million. We recognized a gain on sale for the closing of the Wapiti Transaction
in the three months ended September 30, 2010 of $29.6 million. The gain is subject to revision for
normal and customary purchase price adjustments as provided for under the purchase and sale
agreement. During the third quarter of 2010, we also sold our Howard Ranch properties for
$550,000. We recognized a loss on the sale of $687,000.
Non-Controlling Interest.
Non-controlling interest represents the minority investors’
proportionate share of the income or loss of DHS in which they hold an interest. During the three
months ended September 30, 2010 and 2009, DHS reported significant losses from low rig utilization
rates which resulted in a non-controlling interest credit to earnings.
41
Table of Contents
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
Net Loss Attributable to Delta Common Stockholders.
Net loss attributable to Delta common
stockholders was $148.6 million, or $0.54 per diluted common share, for the nine months ended
September 30, 2010, compared to a net loss attributable to Delta common stockholders of $294.7
million, or $1.55 per diluted common share, for the nine months ended September 30, 2009. There
were a number of items affecting comparability between periods including oil and gas sales,
contract drilling and trucking fees and expenses, gain on offshore litigation award, impairments,
depletion expense, interest and financial costs, and realized and unrealized gains and losses on
derivative instruments. Explanations of significant items affecting comparability between periods
are discussed by financial statement caption below.
Oil and Gas Sales
. During the nine months ended September 30, 2010, oil and gas sales increased
32% to $74.7 million, as compared to $56.8 million for the comparable period a year earlier. The
increase was principally the result of a 95% increase in natural gas prices and a 46% increase in
oil prices, partially offset by a 22% decrease in production. The average natural gas price
received during the nine months ended September 30, 2010 increased to $5.12 per Mcf compared to
$2.62 per Mcf for the year earlier period. The average oil price received during the nine months
ended September 30, 2010 increased to $70.16 per Bbl compared to $47.93 per Bbl for the year
earlier period.
Contract Drilling and Trucking Fees
. Contract drilling and trucking fees for the nine months ended
September 30, 2010 increased to $36.2 million compared to $9.4 million for the comparable year
earlier period. The increase is the result of improved third party rig utilization in the nine
months ended September 30, 2010 compared to the comparable year earlier period, resulting from an
increased industry demand attributable to improved commodity prices.
Gain (Loss) on Offshore Litigation Award and Property Sales, Net.
During the nine months ended
September 30, 2009, we recorded a $31.1 million gain for an offshore litigation award. During the
nine months ended September 30, 2010, we recorded a $539,000 loss primarily associated with the
divestiture of non-core properties. See Note 4, “Oil and Gas Properties,” to the accompanying
financial statements for information regarding our 2010 divestitures.
Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the nine months ended
September 30, 2010 and 2009 are as follows:
| Nine Months Ended | ||||||||
| September 30, | ||||||||
| 2010 | 2009 | |||||||
|
Production — Continuing Operations:
|
||||||||
|
Oil (Mbbl)
|
413 | 573 | ||||||
|
Gas (Mmcf)
|
8,931 | 11,186 | ||||||
|
Total Production (Mmcfe) — Continuing Operations
|
11,409 | 14,624 | ||||||
|
|
||||||||
|
Average Price — Continuing Operations:
|
||||||||
|
Oil (per barrel)
|
$ | 70.16 | $ | 47.93 | ||||
|
Gas (per Mcf)
|
$ | 5.12 | $ | 2.62 | ||||
|
|
||||||||
|
Costs (per Mcfe) — Continuing Operations:
|
||||||||
|
Lease operating expense
|
$ | 1.83 | $ | 1.45 | ||||
|
Transportation expense
|
$ | 0.98 | $ | 0.45 | ||||
|
Production taxes
|
$ | 0.33 | $ | 0.22 | ||||
|
Depletion expense
|
$ | 3.80 | $ | 4.16 | ||||
|
|
||||||||
|
Realized
derivative gains (losses) (per Mcfe)
|
$ | (0.45 | ) | $ | 0.03 | |||
42
Table of Contents
Lease Operating Expense.
Lease operating expenses for the nine months ended September 30,
2010 of $20.9 million was comparable to $21.3 million in the year earlier period due in part to the
Wapiti sale. Lease operating expense per Mcfe for the nine months ended September 30, 2010
increased to $1.83 per Mcfe from $1.45 per Mcfe for the comparable year earlier period. The
increase on a per unit basis was primarily due to the effect of fixed costs spread over a 22%
decline in production volumes.
Transportation Expense.
Transportation expense for the nine months ended September 30, 2010
increased to $11.2 million from $6.7 million in the prior year. Transportation expense per Mcfe
for the nine months ended September 30, 2010 increased to $0.98 per Mcfe from $0.45 per Mcfe. The
increase on a per unit basis is primarily the result of changes to our Vega gas marketing contract
that went into effect in October 2009 whereby our gas is processed through a higher efficiency
plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from
improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.
Production Taxes.
Production taxes for the nine months ended September 30, 2010 were $3.8
million, comparable to prior year costs of $3.2 million. Production taxes as a percentage of oil
and gas sales were 5.0% and 5.6% for the nine months ended September 30, 2010 and 2009,
respectively. The decrease in the 2010 percentage was primarily due to a decrease in the effective
Colorado severance tax rate.
Exploration Expense.
Exploration expense primarily consists of geological and geophysical costs
and delay lease rentals. Our exploration costs for the nine months ended September 30, 2010 were
$952,000, compared to $2.4 million for the comparable year earlier period. Current period
exploration activities primarily relate to delay rental payments, while the 2009 period was related
to delay rental payments and seismic acquisition costs.
Dry Hole Costs and Impairments.
We incurred dry hole and impairment costs of $30.9 million for
the nine months ended September 30, 2010 compared to $161.5 million for the comparable period a
year ago. During the nine months ended September 30, 2010, dry hole and impairment costs primarily
related to proved property impairments of $991,000 for the Opossum Hollow and Golden Prairie
fields, 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.
We incurred dry hole costs and impairments of approximately $161.5 million for the nine months
ended September 30, 2009 primarily related to $103.6 million of impairments for unproved leaseholds
in Garden Gulch, Columbia River Basin, Haynesville, Lighthouse, Newton, Caballos Creek, and Opossum
Hollow, $6.5 million of DHS equipment and rigs impairments, $10.5 million of Vega surface acreage
impairments, $4.3 million of inventory impairments, $3.1 million of impairments for proved
leaseholds, a $1.9 million impairment of our Paradox pipeline and $31.0 million of dry hole costs
associated with the Gray 31-23 in the Columbia River Basin.
Depreciation, Depletion, Amortization and Accretion — Oil and Gas.
Depreciation, depletion and
amortization expense decreased 28% to $45.5 million for the nine months ended September 30, 2010,
as compared to $63.0 million for the comparable year earlier period. Depletion expense for the nine
months ended September 30, 2010 was $43.3 million compared to $60.8 million for the nine months
ended September 30, 2009. Our depletion rate decreased from $4.16 per Mcfe for the nine months
ended September 30, 2009 to $3.80 per Mcfe for the current year period primarily due to the effect
of impairments recorded during late 2009 on high depletion rate properties and Vega area proved
undeveloped reserves added as a result of higher Piceance gas prices.
Drilling and Trucking Operating Expenses
. Drilling expense increased to $28.1 million for the
nine months ended September 30, 2010 compared to $10.4 million for the comparable prior year
period. This increase is due to additional third party rig utilization during the current year
period.
Depreciation and Amortization — Drilling and Trucking.
Depreciation and amortization expense —
drilling decreased to $15.6 million for the nine months ended September 30, 2010, as compared to
$17.5 million for the comparable year earlier period. The decrease is due to the effect on the
depreciation rate of rig impairments recorded during 2009. Depreciation expense is recorded on a
straight line basis and is not impacted by changes in the utilization rate.
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General and Administrative Expense.
General and administrative expense increased 6% to $33.4
million for the nine months ended September 30, 2010, as compared to $31.5 million for the
comparable prior year period. The increase in general and administrative expenses is attributed to
costs associated with the strategic alternatives evaluation process, $1.4 million of allowance for
doubtful accounts recorded by DHS and by increased non-cash stock compensation expense, partially
offset by reduced staffing as a result of reductions in force during both the first half of 2009
and the third quarter of 2010 resulting in lower cash compensation expense.
Executive Severance Expense, Net.
On May 26, 2009, our then Chairman of the Board of Directors
and Chief Executive Officer, Roger A. Parker, resigned from Delta. In consideration for Mr.
Parker’s resignation and his agreement to (a) relinquish all his rights under his employment
agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and
pending transactions benefiting Delta, and any other interests he might claim arising from his
efforts as Chairman of our Board of Directors and/or Chief Executive Officer, and (b) stay on as a
consultant to facilitate an orderly transition and to assist in certain pending transactions, Delta
agreed to pay Mr. Parker $4,700,000 in cash, issue to him 1,000,000 shares of Delta common stock,
pay him the aggregate of any accrued unpaid salary, vacation days and reimbursement of his
reasonable business expenses incurred through the effective date of the agreement, and provide to
him insurance benefits similar to his pre-resignation benefits for a thirty-six month period. The
Severance Agreement also contained mutual releases and non-disparagement provisions, as well as
other customary terms.
On July 6, 2010, John Wallace, the then President, Chief Operating Officer and a Director of the
Company, resigned from all of his positions as director, officer and employee of the Company and
any of its subsidiaries. In conjunction with such resignation, the Company entered into a
severance agreement with Mr. Wallace pursuant to which he agreed to (a) relinquish certain rights
under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses
relating to past and pending transactions benefiting Delta, and certain other interests he might
claim arising from his efforts in his previous capacities with the Company and its subsidiaries,
and (b) make himself reasonably available to answer questions to facilitate an orderly transition.
Under the terms of his severance arrangement, the Company paid Mr. Wallace a lump sum of
$1,600,000, paid him his salary for the full month in which his resignation occurred and for his
accrued vacation days, reimbursed him for his reasonable business expenses incurred through the
effective date of the agreement, and agreed to provide to him insurance benefits similar to his
pre-resignation benefits for the period in which Mr. Wallace is entitled to receive COBRA coverage
under applicable law. The severance agreement also contained mutual releases and non-disparagement
provisions, as well as other customary terms. In addition, $2.3 million of equity compensation
costs previously recorded in the consolidated financial statements related to performance shares
forfeited prior to their derived service period being completed as a result of the severance
agreement were reversed and reflected as a reduction of executive severance expense.
Interest Expense and Financing Costs, Net.
Interest and financing costs, net decreased 30% to
$29.4 million for the nine months ended September 30, 2010, as compared to $41.9 million for the
comparable year earlier period. The decrease is primarily related to lower average outstanding
Delta and DHS credit facility balances coupled with lower interest rates during 2010 as compared to
2009. The decrease is also related to a greater write-off of unamortized deferred financing costs
and waiver fees related to the amendments to our credit facilities in 2009 compared to 2010. In
addition, the nine months ended September 30, 2009, included $1.0 million of interest expense
related to the repurchase from Tracinda of offshore litigation contingent payment rights and
$643,000 for the write off of previously unamortized deferred financing costs related to the DHS
credit agreement.
Realized Gain (Loss) on Derivative Instruments, Net.
During the nine months ended September 30,
2010, we recognized a $5.1 million loss associated with settlements on derivative contracts. During
the nine months ended September 30, 2009, we recognized a $370,000 gain associated with settlements
on derivative contracts.
Unrealized 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 $28.1 million of unrealized gains on derivative instruments in other
income and expense during the nine months ended September 30, 2010 compared to a loss of $27.0
million for the comparable prior year period.
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Income (Loss) From Unconsolidated Affiliates.
Loss from unconsolidated affiliates during the nine
months ended September 30, 2009 is primarily the result of $3.0 million of impairments recorded
related to two of our investments. Income from unconsolidated affiliates during the nine months
ended September 30, 2010 is comprised of our pro-rata share of net income of our unconsolidated
affiliates.
Income Tax Benefit (Expense).
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 nine months ended September 30, 2010 and 2009 of $564,000 and $(53,000),
respectively, relates only to DHS, as no benefit was provided for our net operating losses.
Discontinued Operations.
The results of operations and impairment loss relating non-core property
interests sold in the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as our
interest in our wholly-owned subsidiary Piper Petroleum have been reflected as discontinued
operations as a result of the sale to Wapiti. In a separate transaction, during the
three months ended September 30, 2010, the Company sold its interest in the Howard Ranch field
which is also included in discontinued operations.
The following table shows the total revenues and expenses included in discontinued
operations for the above mentioned oil and gas properties for the nine months ended September 30,
2010 and 2009 (dollar amounts in thousands):
| Nine Months Ended | ||||||||
| September 30, | ||||||||
| 2010 | 2009 | |||||||
|
Production — Discontinued Operations:
|
||||||||
|
Oil (Mbbl)
|
14 | 21 | ||||||
|
Gas (Mmcf)
|
1,903 | 2,404 | ||||||
|
Total Production (Mmcfe) — Discontinued Operations
|
1,987 | 2,531 | ||||||
|
|
||||||||
|
Revenues
|
$ | 9,623 | $ | 8,255 | ||||
|
|
||||||||
|
Operating expenses:
|
||||||||
|
|
||||||||
|
Lease operating expense
|
2,676 | 3,740 | ||||||
|
Transportation expense
|
1,459 | 1,196 | ||||||
|
Production taxes
|
611 | 544 | ||||||
|
Depreciation, depletion, amortization and accretion
|
13,837 | 19,477 | ||||||
|
Impairment provision
|
92,162 | — | ||||||
|
|
||||||||
|
Total operating expenses
|
110,745 | 24,957 | ||||||
|
|
||||||||
|
|
||||||||
|
Loss from discontinued operations
|
(101,122 | ) | (16,702 | ) | ||||
|
Income tax expense
|
— | — | ||||||
|
|
||||||||
|
|
||||||||
|
Loss from results of operations of
discontinued properties, net of tax
|
(101,122 | ) | (16,702 | ) | ||||
|
|
||||||||
|
Gain on sale of discontinued operations
|
28,910 | — | ||||||
|
|
||||||||
|
|
||||||||
|
Total loss from discontinued operations
|
$ | (72,212 | ) | $ | (16,702 | ) | ||
|
|
||||||||
On July 30, 2010, the Company closed on the sale of non-core properties to Wapiti for cash
proceeds of $130.0 million. We recognized a gain on sale for the closing of Wapiti Transaction in
the three months ended September 30, 2010 of $29.6 million. The gain is subject to revision for
normal and customary purchase price adjustments as provided for under the purchase and sale
agreement. During the third quarter of 2010, we also sold our Howard Ranch properties for
$550,000. We recognized a loss on the sale of $687,000.
Non-Controlling Interest.
Non-controlling interest represents the minority investors’ proportionate
share of the income or loss of DHS in which they hold an interest. During the nine months ended
September 30, 2010 and 2009, DHS reported significant losses from low rig utilization rates which
resulted in a non-controlling interest credit to earnings.
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Historical Cash Flow
Our cash flow from operating activities decreased from $20.2 million for the nine months ended
September 30, 2009 to cash used in operating activities of $26.0 million for the nine months ended
September 30, 2010. The significant decrease in cash flow is primarily the result of changes in
working capital and proceeds from the offshore litigation awarded in 2009 partially offset by
higher commodity prices. Our net cash provided by investing activities increased to $94.8 million
for the nine months ended September 30, 2010 compared to net cash used in investing activities of
$137.2 million for the comparable prior year period primarily due to our significant reduction in
drilling and acquisition activity and proceeds from the Wapiti Transaction. Cash provided by
financing activities decreased from $62.2 million for the nine months ended September 30, 2009 to
cash used in financing activities of $116.6 million for the current year period. During the nine
months ended September 30, 2010, we made net bank payments of $114.2 million. During the nine
months ended September 30, 2009, $246.9 million of cash was received from the issuance of stock and
we made net bank payments of $182.0 million.
Capital and Exploration Expenditures
Our capital and exploration expenditures for the nine months ended September 30, 2010 and 2009 were
as follows (in thousands):
| 2010 | 2009 | |||||||
|
CAPITAL AND EXPLORATION EXPENDITURES:
|
||||||||
|
|
||||||||
|
Property acquisitions:
|
||||||||
|
Unproved
|
$ | 388 | $ | 1,820 | ||||
|
Proved
|
— | — | ||||||
|
Oil and gas properties
|
27,199 | 51,236 | ||||||
|
Drilling and trucking equipment
|
2,048 | 4,139 | ||||||
|
Pipeline and gathering systems
|
6,895 | 9,491 | ||||||
|
|
||||||||
|
Total
(1)
|
$ | 36,530 | $ | 66,686 | ||||
|
|
||||||||
| 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 (the “Notes”) 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 Notes can first require us to purchase all or a portion of the Notes.
The 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 Notes have an
effective interest rate of approximately 7.8% and 7.6% with total interest costs of $2.2 million
for each of the three month periods ended September 30, 2010 and 2009, respectively, and interest
costs of $6.6 million and $6.5 million for the nine month periods ended September 30, 2010 and
2009, respectively. The Notes will mature
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on May 1, 2037 unless earlier converted, redeemed or
repurchased. The holders of the Notes have the right to require us 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. The Notes will be convertible at the holder’s option, in whole or in part, at an
initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes
(equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close
of business on the business day immediately preceding the final maturity date of the Notes, subject
to prior repurchase of the Notes. The conversion rate may be adjusted from 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 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 Notes in connection with such fundamental
changes by a number of additional shares of common stock. Although the Notes do not contain any
financial covenants, the 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 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
Pursuant to the Fourth Amendment dated as of July 23, 2010, among other changes more fully
described in Note 7, “Long Term Debt” to the accompanying financial statements, the borrowing base
under our Credit Agreement was reduced to $35.0 million upon the consummation of the Wapiti
Transaction.
The Fourth Amendment eliminated all scheduled or special borrowing base redeterminations prior to
the maturity of the facility in January 2011.
The 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 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 banks on most of our oil and gas
properties, certain related equipment, and oil and gas inventory.
Credit Facility — DHS
On April 1, 2010 DHS amended its existing credit facility with Lehman Commercial Paper, Inc. and
renegotiated certain terms of the agreement, to, among other changes more fully described in Note
7, “Long Term Debt” to the accompanying financial statements, bring DHS into compliance with the
terms of the agreement, amend the principal repayment schedule, adjust the interest rate, and
eliminate or amend certain financial covenants.
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 $1.3 million over the term of the lease. We have
additional operating lease
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commitments which represent office equipment leases and lease obligations primarily relating to
field vehicles and equipment.
We had a net derivative asset of $1.1 million at September 30, 2010. 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.
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.
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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.
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 nine months ended September
30, 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of
the corresponding asset and as such no impairment provision was 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.
As a result of such assessment, we recorded impairment provisions attributable to unproved
properties of $22.5 million for the nine months ended September 30, 2010. The $22.5 million
impairment included $11.4 million related to our Columbia River Basin leasehold, $5.0 million
related to our Hingeline leasehold, $3.8 million related to our Haynesville leasehold, $1.6 million
related to our Delores River leasehold and $661,000 related to our Howard Ranch leasehold. In
addition, we recorded an impairment of $4.8 million to reduce the Paradox pipeline carrying value
to its estimated fair value during the nine months ended September 30, 2010. These impairments are
included within dry hole costs and impairments in the accompanying statement of operations for the
nine months ended September 30, 2010.
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In addition to the impairment provisions discussed above, we utilized various fair value techniques
related to our Garden Gulch, Baffin Bay, DJ Basin, Caballos Creek, Opossum Hollow, Midway Loop, and
Newton fields, as well as our interest in our wholly owned subsidiary Piper Petroleum and unproved
acreage positions in the DJ Basin and South Texas assets which were held for sale at June 30, 2010
and determined that impairment provisions of $93.2 million related to proved properties and $3.0
million related to unproved properties were required to be recognized during the three months ended
June 30, 2010. Based upon the applicable accounting standards, $4.0 million of the impairment
provision is included within dry hole costs and impairments in the accompanying statement of
operations for the nine months ended September 30, 2010 and $92.2 million is included in loss from
discontinued operations for the nine months ended September 30, 2010.
During the remainder of 2010, 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 and natural gas 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. As of September 30,
2010, we had a total of seven oil and gas derivative contracts outstanding. The fair value of our
oil derivative instruments was a liability of $7.0 million and the fair value of our gas derivative
instruments was an asset of $8.1 million at September 30, 2010. 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 September 30, 2010. The pre-credit risk adjusted fair value of our net
derivative assets as of September 30, 2010 was $617,000. A credit risk adjustment of $483,000 to
the fair value of the derivatives caused the reported amount of the net derivative assets on our
consolidated balance sheet to be $1.1 million.
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
The Company uses 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
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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.
Recently Issued and Adopted Accounting Pronouncements
In January 2010, the FASB issued Accounting Standards Update No. 2010-06,
Improving Disclosures
about Fair Value Measurements
(“ASU 2010-06”), which provides amendments to FASB ASC Topic 820,
Fair Value Measurements and Disclosures.
The objective of ASU 2010-06 is to provide more robust
disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii)
the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements,
and (iv) significant transfers between Levels 1, 2 and 3. ASU 2010-06 is effective for fiscal
years and interim periods beginning after December 15, 2009. We adopted ASU 2010-06 effective
January 1, 2010, which did not have an impact on our consolidated financial statements, other than
additional disclosures.
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 September 30, 2010:
| Net Fair Value | ||||||||||||||||||||
| Remaining | Asset (Liability) at | |||||||||||||||||||
| Commodity | Volume | Fixed Price | Term | Index Price | September 30, 2010 | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Crude oil
|
1,000 | Bbls / Day 1 | $ | 52.25 | Oct ’10 - Dec ’10 | NYMEX — WTI | $ | (2,600 | ) | |||||||||||
|
Crude oil
|
500 | Bbls / Day | $ | 57.70 | Jan ’11 - Dec ’11 | NYMEX — WTI | (4,404 | ) | ||||||||||||
|
Natural gas
|
6,000 | MMBtu / Day | $ | 5.720 | Oct ’10 - Dec ’10 | NYMEX — HHUB | 977 | |||||||||||||
|
Natural gas
|
15,000 | MMBtu / Day | $ | 4.105 | Oct ’10 - Dec ’10 | CIG | 705 | |||||||||||||
|
Natural gas
|
5,367 | MMBtu / Day | $ | 3.973 | Oct ’10 - Dec ’10 | CIG | 187 | |||||||||||||
|
Natural gas
|
12,000 | MMBtu / Day | $ | 5.150 | Jan ’11 - Dec ’11 | CIG | 5,006 | |||||||||||||
|
Natural gas
|
3,253 | MMBtu / Day | $ | 5.040 | Jan ’11 - Dec ’11 | CIG | 1,229 | |||||||||||||
|
|
||||||||||||||||||||
|
|
$ | 1,100 | ||||||||||||||||||
|
|
||||||||||||||||||||
| 1 |
As a result of the closing of the Wapiti Transaction, for the period from October to
December 2010, derivative contract volumes were anticipated to exceed physical production volumes
in certain months. Accordingly, in October 2010, the Company partially terminated its November and
December 2010 derivatives for a cost of $729,000 to reduce the hedged volume from 1,000 barrels per
day to 625 barrels per day.
|
Assuming production and the percent of oil and gas sold remained unchanged for the nine months
ended September 30, 2010, a hypothetical 10% decline in the average market price we realized during
the nine months ended September 30, 2010 on unhedged production would reduce our oil and natural
gas revenues by approximately $7.5 million.
Interest Rate Risk
We were subject to interest rate risk on $93.1 million of variable rate debt obligations at
September 30, 2010. The annual effect of a 10% change in interest rates on the debt would be
approximately $716,000.
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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 September 30, 2010, 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.
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:
We are currently engaged in arbitration with 212 Resources Corporation (“212”) with regard to a
dispute involving a May 18, 2008 Oil and Gas Fluid Processing Agreement (the “Agreement”) between
212 and us. The Agreement requires 212 to design, construct, and operate “Mobile Pods” to treat
and discharge to surface waters fluid produced by our oil and gas operations in compliance with
applicable law and permits, and requires us to pay 212 approximately $500,000 per month commencing
on the earlier of the date that such Mobile Pod is (a) first Available, or (b) first used to
provide the contemplated services. The term “Available,” as used in the Agreement, means the first
date that a Mobile Pod is mechanically capable of providing the contemplated services (or would
have been mechanically capable of providing such services but for our failure to perform any of our
obligations under the Agreement). On October 27, 2009, 212 filed a Demand for Arbitration and
Statement of Claim and alleged that we delayed the performance of our duty to obtain permits and
construct the site under the Agreement. 212 contends, in essence, that we delayed obtaining permits
for the operation of the Mobile Pods and that we owe the monthly fee for the Mobile Pods for the
period commencing on October 1, 2009. We have denied 212’s claims and contend, in essence, that
212 has still not demonstrated that the Mobile Pods are capable of treating and discharging to
surface waters fluid produced by our oil and gas operations in compliance with applicable law and
permits. We have also filed counterclaims. The matter is currently set for arbitration on November
29, 2010, but we have filed a motion seeking a delay of the hearing for a time sufficient to obtain
and analyze a variety of test results to determine whether or not the operation of the Mobile Pods
complies with applicable law and permits. While we believe that we have meritorious defenses to
212’s claims and have valid counterclaims, we are unable to predict the ultimate outcome of the
arbitration.
The Company’s indirect, 49.8% owned affiliate DHS Drilling Company (“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 they 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 to a DHS customer in
Mexico. DHS has cooperated and will continue to cooperate with the investigation, which is
currently in its initial stages. This investigation is subject to uncertainties, and, as such, DHS
is unable to estimate the nature of any possible liability that may result.
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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
2009 Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on March
12, 2010. This information should be considered carefully, together with other information in this
report and other reports and materials we file with the SEC.
Our existing credit facility matures on January 15, 2011 and we may be unable to refinance in
a timely manner or on terms acceptable to us, if at all.
Our existing credit facility matures on January 15, 2011, at which time all amounts outstanding
thereunder will be due and payable. Without a refinancing of the credit facility or another
capital-raising transaction, management currently does not believe that we will have sufficient
cash on hand, based on current cash flow projections, to repay the credit facility in full at
maturity. We are currently negotiating with a new lender to replace our existing credit facility,
but there can be no assurance that we will be able to refinance the credit facility on terms and
conditions acceptable to us, or at all, or on a timely basis. In addition, credit or financial
market disruptions such as those that have recently been experienced in the United States and
abroad may have a material adverse effect on our ability to refinance the credit facility on a
timely basis and on terms acceptable to us, if at all. Without a
replacement credit facility, it is likely that we will have limited
borrowing capacity and insufficient capital to support our
development and capital expenditure plans.
The table below provides a summary of our purchases of our own common stock during the three months
ended September 30, 2010.
| 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) | ||||||||||||
|
July 1 – July 31, 2010
|
903,000 | $ | 0.82 | — | — | |||||||||||
|
August 1 – August 31, 2010
|
— | — | — | — | ||||||||||||
|
September 1 – September 30, 2010
|
— | — | — | — | ||||||||||||
|
|
||||||||||||||||
|
Total
|
903,000 | $ | 0.82 | — | — | |||||||||||
|
|
||||||||||||||||
| (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.
|
None.
53
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Exhibits are as follows:
| 10.1 |
Severance Agreement by and between Delta Petroleum Corporation and
John R. Wallace, effective October 19, 2010. Incorporated by reference from
Exhibit 10.1 to the Company’s Form 8-K filed October 25, 2010.
|
||
| 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.
|
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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 | |||
| Carl E. Lakey, President and | ||||
| Chief Executive Officer | ||||
| By: | /s/ Kevin K. Nanke | |||
| Kevin K. Nanke, Treasurer and | ||||
| Chief Financial Officer | ||||
Date: November 9, 2010
55
Table of Contents
EXHIBIT INDEX:
| 10.1 |
Severance Agreement by and between Delta Petroleum Corporation and
John R. Wallace, effective October 19, 2010. Incorporated by reference from
Exhibit 10.1 to the Company’s Form 8-K filed October 25, 2010.
|
||
| 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