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8-K - FORM 8-K - PAR PACIFIC HOLDINGS, INC. | c24572e8vk.htm |
Exhibit 99.1
DELTA PETROLEUM CORPORATION
Daniel Taylor, Chairman
Carl Lakey, President and CEO
Kevin Nanke, Treasurer and CFO
Broc Richardson, V.P. Corporate Development and IR
370 17th Street, Suite 4300
Denver, Colorado 80202
Daniel Taylor, Chairman
Carl Lakey, President and CEO
Kevin Nanke, Treasurer and CFO
Broc Richardson, V.P. Corporate Development and IR
370 17th Street, Suite 4300
Denver, Colorado 80202
For Immediate Release
DELTA PETROLEUM CORPORATION ANNOUNCES
THIRD QUARTER 2011 RESULTS AND UPDATE ON STRATEGIC ALTERNATIVES PROCESS
THIRD QUARTER 2011 RESULTS AND UPDATE ON STRATEGIC ALTERNATIVES PROCESS
DENVER, Colorado (November 9, 2011) Delta Petroleum Corporation (Delta or the
Company) (NASDAQ Capital Market: DPTR), an independent oil and gas exploration and development
company, today announced its financial and operating results for the third quarter 2011 and
provided an update on the strategic alternatives process.
STRAGETIC ALTERNATIVES UPDATE
In July 2011, the Board of Directors of the Company announced that it had engaged
Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors to the Company in
conducting a strategic alternatives process in order to maximize shareholder value and address the
2012 debt maturities. In the strategic alternatives process, the board of directors has considered
a wide variety of possible transactions, including the sale of the company, issuances of equity or
debt securities, sales of assets, joint ventures and volumetric production payment financing, as
well as other potential corporate transactions. With respect to a potential sale of the company or
its assets, the Company solicited offers from a significant number of potential purchasers,
including domestic and foreign industry participants and private equity firms, and has engaged in
substantive negotiations with several such potential purchasers. However, the Company has not
received any definitive offer with respect to an acquisition of the company or its assets that
implies a value of the assets that is greater than its aggregate indebtedness, and has not been
able to identify any significant source of additional financing that is likely to be available on
acceptable terms. Accordingly, based on the results of the process to date, the Company believes
that a restructuring of the Companys indebtedness is likely to be necessary. The Company is
continuing to discuss potential transactions with potential purchasers and expects to engage in
discussions with certain holders of its outstanding senior notes. There can be no assurance that
these discussions will lead to a definitive agreement on acceptable terms, or at all, with any
party. Any transaction that is agreed to could be highly dilutive to existing stockholders. If
the Company is unsuccessful in consummating a transaction or transactions that address its
liquidity issues, the Company will be required to seek protection under Chapter 11 of the U.S.
Bankruptcy Code.
On November 2, 2011, Delta appointed John T. Young, Jr. as its Chief Restructuring Officer.
Mr. Young is a Senior Managing Director at Conway MacKenzie, Inc., which Delta has retained to
assist with its strategic alternatives process. Mr. Young has substantial knowledge and experience
providing restructuring advisor services, including interim management and debtor advisory,
bankruptcy preparation and management, litigation support, post-merger integration and debt
restructuring and refinancing. Mr. Youngs experience also includes serving in a multitude of
advisory capacities within the energy and oilfield services industries.
LIQUIDITY UPDATE
At September 30, 2011, $12.0 million was available under the Macquarie Bank Limited (MBL)
revolving credit facility in addition to approximately $2.1 million in cash. The Company is
current with all of its payables and debt obligations including its semiannual interest payments on
its notes. The current availability on the revolving credit facility approximates $4.0 million.
The MBL credit facility, which has a total capacity of $33 million, matures January 31, 2012.
Additionally, the holders of the $115 million 3 3/4% senior convertible notes can require the Company
to repurchase the notes at par on or after May 1, 2012.
RESULTS FOR THE THIRD QUARTER 2011
For the quarter ended September 30, 2011, the Company reported production from continuing
operations of 2.6 Bcfe, remaining flat when comparing third quarter 2011 to the prior year period.
Revenue from oil and gas sales was $16.5 million, an increase of 31% when compared to the prior
year period of $12.7 million. The average natural gas price received during the quarter ended
September 30, 2011 increased to $5.91 per thousand cubic feet (Mcf) compared to $4.44 per Mcf for
the prior year period. The average oil price received during the quarter ended September 30, 2011
increased to $71.45 per barrel compared to $58.71 per barrel for the prior year period.
The Company reported a third quarter net loss attributable to Delta common stockholders of
($429.4 million), or ($15.40) per diluted share, compared to net income attributable to Delta
common stockholders of $13.9 million, or $0.49 per diluted share, in the third quarter of 2010.
The increase in net loss is primarily due to an increase in dry hole costs and impairments as well
as discontinued operations.
THIRD QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and costs per equivalent Mcf for the quarter
ended September 30, 2011 and 2010 were as follows:
Three Months Ended | ||||||||
September 30, | ||||||||
2011 | 2010 | |||||||
Production Continuing Operations: |
||||||||
Oil (Mbbl) |
32 | 39 | ||||||
Gas (Mmcf) |
2,418 | 2,327 | ||||||
Total Production (Mmcfe) Continuing Operations |
2,608 | 2,563 | ||||||
Average Price Continuing Operations: |
||||||||
Oil (per barrel) |
$ | 71.45 | $ | 58.71 | ||||
Gas (per Mcf) |
$ | 5.91 | $ | 4.44 | ||||
Costs (per Mcfe) Continuing Operations: |
||||||||
Lease operating expense |
$ | 1.37 | $ | 1.78 | ||||
Transportation expense |
$ | 1.29 | $ | 1.29 | ||||
Production taxes |
$ | 0.24 | $ | 0.26 | ||||
Depletion expense |
$ | 3.75 | $ | 4.20 | ||||
Realized derivative gain (loss) (per Mcfe) |
$ | 0.03 | $ | (0.16 | ) |
2
Lease Operating Expense. Lease operating expenses for the three months ended September
30, 2011 decreased to $3.6 million from $4.6 million in the prior year period primarily due to
lower water handling costs in the Vega Area as a result of the resumption of development activities
and improved water handling facilities. As a result, lease operating expenses per Mcfe in the Vega
Area declined from $1.63 per Mcfe for the three months ended September 30, 2010 to $1.12 per Mcfe
for the three months ended September 30, 2011. Overall, lease operating expense per Mcfe from
continuing operations for the three months ended September 30, 2011 decreased to $1.37 per Mcfe
from $1.78 per Mcfe.
Transportation Expense. Transportation expense for the three months ended September 30, 2011
increased to $3.4 million from $3.3 million in the prior year. Transportation expense per Mcfe
held constant at $1.29 per Mcfe for the quarters ended September 30, 2011 and 2010.
Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of $420.4
million for the three months ended September 30, 2011 compared to ($1.2 million) for the comparable
period a year ago. During the three months ended September 30, 2011, proved and unproved property
impairments to the Rocky Mountain region of $420.1 million were recognized. During the three
months ended September 30, 2011, the Company evaluated the fair value of its properties based on
market indicators in conjunction with the progression of the strategic alternatives evaluation
process. Delta has not received any definitive offer with respect to an acquisition of the company
or its assets that implies a value of the assets that is greater than its aggregate indebtedness.
As a result, the Company recorded an impairment of $157.5 million to its Vega unproved leasehold,
$239.8 million to its Vega area proved properties, $20.5 million to its Vega area gathering system
and facilities, and $2.1 million to its Vega area surface acreage. During the three months ended
September 30, 2010, dry hole and impairment costs were a result of minor cost true-ups.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense
decreased 7% to $10.7 million for the three months ended September 30, 2011, as compared to $11.5
million for the comparable year earlier period. Depletion expense for the three months ended
September 30, 2011 decreased to $9.8 million from $10.8 million for the three months ended
September 30, 2010 primarily due to higher reserves as a result of the Companys recent drilling
and completion activity in the Vega Area. Accordingly, the depletion rate decreased from $4.20 per
Mcfe for the three months ended September 30, 2010 to $3.75 per Mcfe for the current year period.
General and Administrative Expense. General and administrative expense decreased 23% to $6.1
million for the three months ended September 30, 2011, as compared to $7.9 million for the
comparable prior year period. The decrease in general and administrative expenses is attributed to
a decrease in non-cash stock compensation expense and to reduced staffing as a result of attrition
and a reduction in force in the third quarter of 2010 resulting in lower cash compensation expense.
RESULTS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011
The Company reported a nine month net loss attributable to common stockholders of ($458.2
million), or ($16.33) per share, compared with a net loss attributable to common stockholders of
($148.6 million), or ($5.40) per share, in the nine months ended September 30, 2010.
For the nine months ended September 30, 2011, the Company reported total production of 9.2
Bcfe, including production from continuing operations of 8.4 Bcfe. Revenue from oil and gas sales
increased 9% to $51.1 million when compared to the prior year period. The average natural gas
price received during the nine months ended September 30, 2011 increased to $5.50 per Mcf compared
to $5.17 per Mcf for the year earlier period. The average oil price received during the nine
months ended September 30, 2011 increased to $79.13 per Bbl compared to $59.32 per Bbl for the year
earlier period.
3
NINE MONTHS ENDED PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per equivalent Mcf for the nine
months ended September 30, 2011 and 2010 are as follows:
Nine Months Ended | ||||||||
September 30, | ||||||||
2011 | 2010 | |||||||
Production Continuing Operations: |
||||||||
Oil (Mbbl) |
108 | 125 | ||||||
Gas (Mmcf) |
7,741 | 7,678 | ||||||
Total Production (Mmcfe) Continuing Operations |
8,392 | 8,428 | ||||||
Average Price Continuing Operations: |
||||||||
Oil (per barrel) |
$ | 79.13 | $ | 59.32 | ||||
Gas (per Mcf) |
$ | 5.50 | $ | 5.17 | ||||
Costs (per Mcfe) Continuing Operations: |
||||||||
Lease operating expense |
$ | 1.26 | $ | 1.79 | ||||
Transportation expense |
$ | 1.30 | $ | 1.30 | ||||
Production taxes |
$ | 0.25 | $ | 0.28 | ||||
Depletion expense |
$ | 3.69 | $ | 3.93 | ||||
Realized derivative losses (per Mcfe) |
$ | (0.64 | ) | $ | (0.61 | ) |
Lease Operating Expense. Lease operating expenses for the nine months ended September
30, 2011 decreased 30% to $10.5 million as compared to $15.1 million in the year earlier period.
The decrease is primarily due to lower water handling costs in the Vega Area as a result of the
resumption of development activities and improved water handling facilities. As a result, lease
operating expense per Mcfe in the Vega Area declined from $1.70 per Mcfe for the nine months ended
September 30, 2010 to $0.95 per Mcfe for the nine months ended September 30, 2011. Overall, lease
operating expense per Mcfe from continuing operations for the nine months ended September 30, 2011
decreased to $1.26 per Mcfe from $1.79 per Mcfe for the comparable year earlier period.
Transportation Expense. Transportation expense for the nine months ended September 30, 2011
and 2010 was $10.9 million. Transportation expense per Mcfe for the nine months ended September 30,
2011 held constant at $1.30 per Mcfe.
Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of $420.9
million for the nine months ended September 30, 2011 compared to $29.8 million for the comparable
period a year ago. During the three months ended September 30, 2011, proved and unproved property
impairments to the Rocky Mountain region of $420.1 million were recognized. During the three months
ended September 30, 2011, the Company evaluated the fair value of its properties based on market
indicators in conjunction with the progression of the strategic alternatives evaluation process.
Delta has not received any definitive offer with respect to an acquisition of the company or its
assets that implies a value of the assets that is greater than its aggregate indebtedness. As a
result, the Company recorded an impairment of $157.5 million to its Vega unproved leasehold, $239.8
million to its Vega area proved properties, $20.5 million to its Vega area gathering system and
facilities, and $2.1 million to its Vega area surface acreage. During the nine months ended
September 30, 2010, dry hole and impairment costs primarily related to unproved property
impairments of $25.7 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 the
Paradox pipeline.
4
Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion and
amortization expense decreased 6% to $33.2 million for the nine months ended September 30, 2011, as
compared to $35.4 million for the comparable year earlier period. Depletion expense for the nine
months ended September 30, 2011 was $31.0 million compared to $33.1 million for the nine months
ended September 30, 2010. The Companys depletion
rate decreased from $3.93 per Mcfe for the nine months ended September 30, 2010 to $3.69 per
Mcfe for the current year period primarily due to higher reserves as a result of the Companys
recent drilling and completion activity in the Vega Area.
General and Administrative Expense. General and administrative expense decreased 33% to
$19.2 million for the nine months ended September 30, 2011, as compared to $28.8 million for the
comparable prior year period. The decrease in general and administrative expenses is attributed to
a decrease in non-cash stock compensation expense, lower corporate consulting fees and to reduced
staffing as a result of attrition and a reduction in force during 2010 resulting in lower cash
compensation expense.
DHS DRILLING COMPANY
On October 31, 2011, Delta sold its stock in DHS Drilling Company to DHSs lender,
Lehman Commercial Paper, Inc., for $500,000. Delta expects to recognize a gain of approximately
$6.1 million in connection with the divestiture of DHS during the fourth quarter of 2011.
ADDITIONAL FINANCIAL INFORMATION
The following table summarizes the Companys open derivative contracts at September 30, 2011:
Remaining | ||||||||||||||
Commodity | Volume | Fixed Price | Term | Index Price | ||||||||||
Crude oil |
203 | Bbls / Day | $ | 57.70 | Oct 11 - Dec 11 | NYMEX WTI | ||||||||
Crude oil |
62 | Bbls / Day | $ | 91.05 | Oct 11 - Dec 11 | NYMEX WTI | ||||||||
Crude oil |
230 | Bbls / Day | $ | 91.05 | Jan 12 - Dec 12 | NYMEX WTI | ||||||||
Crude oil |
162 | Bbls / Day | $ | 91.05 | Jan 13 - Dec 13 | NYMEX WTI | ||||||||
Natural gas |
12,000 | MMBtu / Day | $ | 5.150 | Oct 11 - Dec 11 | CIG | ||||||||
Natural gas |
3,253 | MMBtu / Day | $ | 5.040 | Oct 11 - Dec 11 | CIG | ||||||||
Natural gas |
12,052 | MMBtu / Day | $ | 4.440 | Jan 12 - Dec 12 | CIG | ||||||||
Natural gas |
10,301 | MMBtu / Day | $ | 4.440 | Jan 13 - Dec 13 | CIG | ||||||||
Natural gas liquids(1) |
34,367 | Gallons / Day | $ | 0.913 | Oct 11 - Dec 11 | MT. BELVIEU | ||||||||
Natural gas liquids(1) |
30,617 | Gallons / Day | $ | 0.832 | Jan 12 - Dec 12 | MT. BELVIEU | ||||||||
Natural gas liquids(1) |
12,286 | Gallons / Day | $ | 0.767 | Jan 13 - Dec 13 | MT. BELVIEU |
(1) | Natural gas liquids includes purity ethane, propane, natural gasoline,
normal butane and isobutene derivatives and the weighted average price is used. |
ABOUT DELTA PETROLEUM
Delta Petroleum Corporation is an oil and gas exploration and development company based
in Denver, Colorado. The Companys core area of operation is the Rocky Mountain Region, where the
majority of its proved reserves, production and long-term growth prospects are located. Its common
stock is listed on the NASDAQ Capital Market System under the symbol DPTR.
5
FORWARD-LOOKING STATEMENTS
Forward-looking statements in this announcement are made pursuant to the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995. Such forward-looking
statements include, without limitation, business objectives and strategies, including our focus on
the Vega Area of the Piceance Basin, as well as statements regarding our strategic alternatives
process, possible value creation and resource potential, anticipated future operating and overhead
costs, liquidity requirements and availability of capital, drilling and completion activity and
anticipated timing, and anticipated sources and uses of capital. Readers are cautioned that all
forward-looking statements are based on managements present expectations, estimates and
projections, but involve risks and uncertainty, including without limitation, the availability of
capital to fund required payments on the Companys indebtedness, its working capital needs, its
ability to sell the Company or its assets
at a value greater than its aggregate indebtedness, its ability to obtain financing from any
source or the viability of any attempted restructuring efforts or bankruptcy proceedings, effects
of oil and natural gas prices, the demand for natural gas in the United States, uncertainties in
the projection of future rates of production, unanticipated recovery or production problems,
unanticipated results from wells being drilled or completed, the effects of delays in completion of
gas gathering systems, pipelines and processing facilities, regulations that might be adopted in
the future that could, among other things, significantly limit or curtail hydraulic fracturing
techniques used in the Piceance Basin, as well as general market conditions, competition and
pricing. The United States Securities and Exchange Commission permits oil and gas companies, in
their filings with the SEC, to characterize as proved reserves only those accumulations that a
company has demonstrated by actual production or conclusive formation tests to be economically and
legally producible under existing economic and operating conditions, and that are part of an
approved five-year development plan. Please refer to the Companys report on Form 10-K for the
year ended December 31, 2010 and subsequent reports on Forms 10-Q and 8-K as filed with the
Securities and Exchange Commission for additional information. The Company is under no obligation
(and expressly disclaims any obligation) to update or alter its forward-looking statements, whether
as a result of new information, future events or otherwise.
For further information contact the Company at (303) 293-9133 or via email at
investorrelations@deltapetro.com.
SOURCE: Delta Petroleum Corporation
6
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
(In thousands, except share data) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 2,101 | $ | 14,190 | ||||
Short-term restricted deposits |
100,000 | 100,000 | ||||||
Trade accounts receivable, net of allowance for doubtful
accounts of $175 and $100, respectively |
7,598 | 7,373 | ||||||
Assets held for sale DHS subsidiary |
70,819 | 108,218 | ||||||
Deposits and prepaid assets |
1,790 | 1,720 | ||||||
Inventories |
153 | 3,446 | ||||||
Derivative instruments |
1,463 | | ||||||
Other current assets |
1,344 | 4,821 | ||||||
Total current assets |
185,268 | 239,768 | ||||||
Property and equipment: |
||||||||
Oil and gas properties, successful efforts method of accounting: |
||||||||
Unproved |
72,190 | 229,943 | ||||||
Proved |
684,539 | 671,041 | ||||||
Pipeline and gathering systems |
63,842 | 93,558 | ||||||
Other |
11,713 | 13,556 | ||||||
Total property and equipment |
832,284 | 1,008,098 | ||||||
Less accumulated depreciation and depletion |
(469,762 | ) | (232,493 | ) | ||||
Net property and equipment |
362,522 | 775,605 | ||||||
Long-term assets: |
||||||||
Investments in unconsolidated affiliates |
3,599 | 3,376 | ||||||
Deferred financing costs |
1,299 | 1,832 | ||||||
Other long-term assets |
1,583 | 3,531 | ||||||
Total long-term assets |
6,481 | 8,739 | ||||||
Total assets |
$ | 554,271 | $ | 1,024,112 | ||||
LIABILITIES AND EQUITY |
||||||||
Current liabilities: |
||||||||
Credit facility Delta |
$ | 21,000 | $ | | ||||
Installment payable on property acquisition |
99,785 | 97,874 | ||||||
33/4% Senior convertible notes current |
112,167 | | ||||||
Accounts payable |
18,152 | 27,616 | ||||||
Liabilities related to assets held for sale DHS subsidiary |
78,829 | 82,852 | ||||||
Other accrued liabilities |
12,662 | 11,066 | ||||||
Derivative instruments |
| 574 | ||||||
Total current liabilities |
342,595 | 219,982 | ||||||
Long-term liabilities: |
||||||||
7% Senior notes |
149,741 | 149,684 | ||||||
33/4% Senior convertible notes |
| 108,593 | ||||||
Credit facility Delta |
| 29,130 | ||||||
Asset retirement obligations |
3,354 | 2,709 | ||||||
Derivative instruments |
319 | 2,419 | ||||||
Total long-term liabilities |
153,414 | 292,535 | ||||||
Commitments and contingencies |
||||||||
Equity: |
||||||||
Preferred
stock, $.01 par value: authorized 3,000,000 shares, none issued |
| | ||||||
Common stock, $.01 par value: authorized 200,000,000 shares,
issued 28,870,000 shares at September 30, 2011 and
28,513,800 shares at December 31, 2010 (1) |
289 | 285 | ||||||
Additional paid-in capital |
1,640,591 | 1,635,783 | ||||||
Treasury stock at cost; zero shares at September 30, 2011
and 3,300 shares at December 31, 2010 (1) |
| (279 | ) | |||||
Accumulated deficit |
(1,579,578 | ) | (1,121,342 | ) | ||||
Total Delta stockholders equity |
61,302 | 514,447 | ||||||
Non-controlling interest |
(3,040 | ) | (2,852 | ) | ||||
Total equity |
58,262 | 511,595 | ||||||
Total liabilities and equity |
$ | 554,271 | $ | 1,024,112 | ||||
(1) | All common share amounts (except par value and par value per share amounts) have been
retroactively restated to reflect the Companys one-for-ten reverse common stock split
effective July 13, 2011. |
7
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Revenue: |
||||||||||||||||
Oil and gas sales |
$ | 16,546 | $ | 12,653 | $ | 51,143 | $ | 47,138 | ||||||||
Loss on property sales |
| (1 | ) | | (539 | ) | ||||||||||
Total revenue |
16,546 | 12,652 | 51,143 | 46,599 | ||||||||||||
Operating expenses: |
||||||||||||||||
Lease operating expense |
3,577 | 4,555 | 10,535 | 15,082 | ||||||||||||
Transportation expense |
3,367 | 3,298 | 10,935 | 10,940 | ||||||||||||
Production taxes |
633 | 667 | 2,094 | 2,358 | ||||||||||||
Exploration expense |
53 | 368 | 329 | 952 | ||||||||||||
Dry hole costs and impairments |
420,447 | (1,164 | ) | 420,863 | 29,762 | |||||||||||
Depreciation, depletion, amortization and accretion |
10,701 | 11,522 | 33,180 | 35,410 | ||||||||||||
General and administrative expense |
6,065 | 7,872 | 19,165 | 28,770 | ||||||||||||
Executive severance expense, net |
| (674 | ) | | (674 | ) | ||||||||||
Total operating expenses |
444,843 | 26,444 | 497,101 | 122,600 | ||||||||||||
Operating loss |
(428,297 | ) | (13,792 | ) | (445,958 | ) | (76,001 | ) | ||||||||
Other income and (expense): |
||||||||||||||||
Interest expense and financing costs, net |
(6,727 | ) | (7,567 | ) | (21,530 | ) | (24,050 | ) | ||||||||
Other income (expense) |
(1,857 | ) | 508 | (1,693 | ) | 686 | ||||||||||
Realized gain (loss) on derivative instruments, net |
79 | (418 | ) | (5,371 | ) | (5,132 | ) | |||||||||
Unrealized gain on derivative instruments, net |
6,749 | 7,124 | 4,137 | 28,072 | ||||||||||||
Income (loss) from unconsolidated affiliates |
80 | (90 | ) | 294 | 893 | |||||||||||
Total other income and (expense) |
(1,676 | ) | (443 | ) | (24,163 | ) | 469 | |||||||||
Loss from continuing operations before income taxes and
discontinued operations |
(429,973 | ) | (14,235 | ) | (470,121 | ) | (75,532 | ) | ||||||||
Income tax expense (benefit) |
64 | 86 | (4,568 | ) | 564 | |||||||||||
Loss from continuing operations |
(430,037 | ) | (14,321 | ) | (465,553 | ) | (76,096 | ) | ||||||||
Discontinued operations: |
||||||||||||||||
Gain (loss) from results of operations and sale of
discontinued operations, net of tax |
1,309 | 25,054 | 7,092 | (81,644 | ) | |||||||||||
Net income (loss) |
(428,728 | ) | 10,733 | (458,461 | ) | (157,740 | ) | |||||||||
Less net (gain) loss attributable to non-controlling interest
included in discontinued operations |
(702 | ) | 3,209 | 225 | 9,134 | |||||||||||
Net income (loss) attributable to Delta common stockholders |
$ | (429,430 | ) | $ | 13,942 | $ | (458,236 | ) | $ | (148,606 | ) | |||||
Amounts attributable to Delta common stockholders: |
||||||||||||||||
Loss from continuing operations |
$ | (430,037 | ) | $ | (14,321 | ) | $ | (465,553 | ) | $ | (76,096 | ) | ||||
Income (loss) from discontinued operations, net of tax |
607 | 28,263 | 7,317 | (72,510 | ) | |||||||||||
Net loss |
$ | (429,430 | ) | $ | 13,942 | $ | (458,236 | ) | $ | (148,606 | ) | |||||
Basic loss attributable to Delta common stockholders
per common share: |
||||||||||||||||
Loss from continuing operations |
$ | (15.42 | ) | $ | (0.52 | ) | $ | (16.59 | ) | $ | (2.76 | ) | ||||
Discontinued operations |
0.02 | 1.03 | 0.26 | (2.64 | ) | |||||||||||
Net loss |
$ | (15.40 | ) | $ | 0.51 | $ | (16.33 | ) | $ | (5.40 | ) | |||||
Diluted loss attributable to Delta common stockholders
per common share: |
||||||||||||||||
Loss from continuing operations |
$ | (15.42 | ) | $ | (0.51 | ) | $ | (16.59 | ) | $ | (2.76 | ) | ||||
Discontinued operations |
0.02 | 1.00 | 0.26 | (2.64 | ) | |||||||||||
Net loss |
$ | (15.40 | ) | $ | 0.49 | $ | (16.33 | ) | $ | (5.40 | ) | |||||
Weighted average common shares outstanding(1): |
||||||||||||||||
Basic |
27,883 | 27,530 | 28,055 | 27,544 | ||||||||||||
Diluted |
27,883 | 28,206 | 28,055 | 27,544 |
(1) | All common share amounts (except par value and par value per share amounts) have been
retroactively restated as of September 30, 2011 to reflect the Companys one-for-ten
reverse common stock split effective July 13, 2011. |
8
DELTA PETROLEUM CORPORATION
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
(Unaudited)
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
(Unaudited)
($ in thousands)
September 30, | September 30, | |||||||
THREE MONTHS ENDED | 2011 | 2010 | ||||||
CASH USED IN OPERATING ACTIVITIES |
$ | 5,651 | $ | (7,427 | ) | |||
Changes in assets and liabilities |
(5,398 | ) | 1,901 | |||||
Exploration costs |
53 | 368 | ||||||
Discretionary cash flow* continuing operations |
306 | (5,158 | ) | |||||
Discretionary cash flow* discontinued operations |
1,478 | 4,742 | ||||||
Total discretionary cash flow* |
$ | 1,784 | $ | (416 | ) | |||
September 30, | September 30, | |||||||
NINE MONTHS ENDED | 2011 | 2010 | ||||||
CASH USED IN OPERATING ACTIVITIES |
$ | (1,425 | ) | $ | (49,611 | ) | ||
Changes in assets and liabilities |
(2,611 | ) | 29,172 | |||||
Exploration costs |
329 | 952 | ||||||
Discretionary cash flow* continuing operations |
(3,707 | ) | (19,487 | ) | ||||
Discretionary cash flow* discontinued operations |
6,453 | 23,738 | ||||||
Total discretionary cash flow* |
$ | 2,746 | $ | 4,251 | ||||
* | Discretionary cash flow represents net cash provided by (used in) operating activities before
changes in assets and liabilities and exploration costs. Discretionary cash flow is presented
as a supplemental financial measurement in the evaluation of Deltas business. The Company
believes that it provides additional information regarding its ability to meet future debt
service, capital expenditures and working capital requirements. This measure is widely used
by investors and rating agencies in the valuation, comparison, rating and investment
recommendations of companies. Discretionary cash flow is not a measure of financial
performance under GAAP. Accordingly, it should not be considered as a substitute for cash
flows from operating, investing or financing activities as an indicator of cash flows, or as a
measure of liquidity. |
September 30, | September 30, | |||||||
THREE MONTHS ENDED | 2011 | 2010 | ||||||
Net loss from continuing operations |
$ | (430,037 | ) | $ | (14,321 | ) | ||
Income tax expense (benefit) |
64 | 86 | ||||||
Interest expense and financing costs, net |
6,727 | 7,567 | ||||||
Depletion, depreciation and amortization |
10,701 | 11,522 | ||||||
Stock based compensation |
1,735 | 1,883 | ||||||
Gain (loss) on sale of discontinued operations oil and gas properties |
| (20 | ) | |||||
Unrealized gain on derivative instruments, net |
(6,749 | ) | (7,124 | ) | ||||
Realized loss on derivative instruments |
| | ||||||
Exploration, dry hole and impairment costs |
422,124 | (796 | ) | |||||
EBITDAX** continuing operations |
4,565 | (1,203 | ) | |||||
EBITDAX ** discontinued operations |
2,013 | 6,745 | ||||||
Total EBITDAX** |
$ | 6,578 | $ | 5,542 | ||||
September 30, | September 30, | |||||||
THREE MONTHS ENDED | 2011 | 2010 | ||||||
CASH USED IN OPERATING ACTIVITIES |
$ | 5,651 | $ | (7,427 | ) | |||
Changes in assets and liabilities |
(5,398 | ) | 1,901 | |||||
Interest net of financing costs |
4,177 | 3,848 | ||||||
Exploration costs |
53 | 368 | ||||||
Other non-cash items |
82 | 107 | ||||||
EBITDAX** continuing operations |
4,565 | (1,203 | ) | |||||
EBITDAX** discontinued operations |
2,013 | 6,745 | ||||||
Total EBITDAX** |
$ | 6,578 | $ | 5,542 | ||||
September 30, | September 30, | |||||||
NINE MONTHS ENDED | 2011 | 2010 | ||||||
Net income (loss) from continuing operations |
$ | (465,553 | ) | $ | (76,096 | ) | ||
Income tax expense (benefit) |
(4,568 | ) | 564 | |||||
Interest expense and financing costs, net |
21,530 | 24,050 | ||||||
Depletion, depreciation and amortization |
33,180 | 35,410 | ||||||
Stock based compensation |
6,401 | 8,372 | ||||||
Loss on property sales |
| 539 | ||||||
Unrealized loss on derivative instruments, net |
(4,137 | ) | (28,072 | ) | ||||
Realized loss on derivative instruments |
3,295 | | ||||||
Exploration, dry hole and impairment costs |
422,816 | 30,714 | ||||||
EBITDAX** continuing operations |
12,964 | (4,519 | ) | |||||
EBITDAX ** discontinued operations |
9,979 | 26,930 | ||||||
Total EBITDAX** |
$ | 22,943 | $ | 22,411 | ||||
9
September 30, | September 30, | |||||||
NINE MONTHS ENDED | 2011 | 2010 | ||||||
CASH USED IN OPERATING ACTIVITIES |
$ | (1,425 | ) | $ | (49,611 | ) | ||
Changes in assets and liabilities |
(2,611 | ) | 29,172 | |||||
Interest net of financing costs |
12,946 | 13,284 | ||||||
Exploration costs |
329 | 952 | ||||||
Realized loss on derivative instruments |
3,295 | | ||||||
Other non-cash items |
430 | 1,684 | ||||||
EBITDAX** continuing operations |
12,964 | (4,519 | ) | |||||
EBITDAX** discontinued operations |
9,979 | 26,930 | ||||||
Total EBITDAX** |
$ | 22,943 | $ | 22,411 | ||||
** | EBITDAX represents net income (loss) before non-controlling interest, income tax expense
(benefit), interest expense and financing costs, net, depreciation, depletion and amortization
expense, stock based compensation, gain and loss on sale of oil and gas properties and other
investments, net, gain on discontinued operations, unrealized gains and losses on derivative
contracts, realized losses on early termination of derivative instruments and exploration and
impairment and dry hole costs. EBITDAX is presented as a supplemental financial measurement
in the evaluation of the Companys business. Delta believes that it provides additional
information regarding its ability to meet future debt service, capital expenditures and
working capital requirements. This measure is widely used by investors and rating agencies in
the valuation, comparison, rating and investment recommendations of companies. EBITDAX is
also a financial measurement that, with certain negotiated adjustments, is reported to the
Companys lenders pursuant to its bank credit agreement and is used in the financial covenants
in its bank credit agreement and Deltas senior note indentures. EBITDAX is not a measure of
financial performance under GAAP. Accordingly, it should not be considered as a substitute
for net income, income from operations, or cash flow provided by (used in) operating
activities prepared in accordance with GAAP. |
10