DELTA PETROLEUM CORP. 
By PROVED RESERVES INCREASE 135% TO 884 BCFE AND ALL-IN F&D COSTS DECREASE TO
2008 HIGHLIGHTS
-- Revenue from oil and gas sales increased 79% to $221 million
-- Total revenue increased 39% to $271 million
-- EBITDAX (a non-GAAP measure) increased 86% to $156 million
-- Cash provided by operating activities of $141 million
-- Production from continuing operations increased 48%
-- Proved reserves increased 135% to 884 Bcfe
-- Proved developed reserves increased 52% to 181 Bcfe
-- All-in F&D costs per Mcfe totaled $1.37 for 2008 with a 3-year
average of $1.84
"In addition, the Company's exploration program in the Columbia River Basin was marked by significant accomplishments during 2008. We began drilling the Gray 31-23 well, secured a joint venture partner and acquired significant additional acreage. Exciting and recently obtained drilling information has strengthened our belief in the vast resource potential of this project and the role it can play in our Company's future success."
"While 2008 was a year of impressive operating results, dramatic declines in oil and gas prices during the past twelve months have presented Delta and many energy companies with liquidity challenges in recent months," continued Parker. "Our goal is to address these issues through a combination of joint ventures and other capital raising transactions, while also implementing cost reduction measures. Additionally, the lenders on our senior credit facility have provided covenant relief for 2009 and 2010. The combination of our capital raising efforts, cost reductions and relief provided by our banks should provide the Company with the liquidity and flexibility necessary to endure the current environment. We have weathered downturns before, and I am confident that Delta will again realize its potential as a successful development and exploration company."
2008 YEAR-END RESERVES AND RESERVE GROWTH
For the year-ended
The following table presents information regarding the change in oil and natural gas proved reserves from
Gas Oil Total
(Mmcf) (MBbl) (Mmcfe)
------ ------ -------
(In thousands)
Estimated Proved Reserves: Balance
at December 31, 2007 309,473 11,025 375,623
======= ====== =======
Revisions of quantity estimate 191,002 (4,108) 166,354
Extensions and discoveries 152,801 1,652 162,713
Purchase of properties 193,351 1,877 204,613
Sale of properties - - -
Production (18,950) (993) (24,908)
-------- ----- --------
Estimated Proved Reserves: Balance
at December 31, 2008 827,677 9,453 884,395
======= ===== =======
Proved developed reserves:
December 31, 2006 65,026 6,287 102,748
December 31, 2007 92,194 4,548 119,482
December 31, 2008 161,552 3,274 181,196
Future net cash flows presented below are computed using year end
prices and costs.
December 31, 2008 (in thousands)
Future net cash flows $ 3,542,332
Future costs:
Production 924,705
Development and abandonment 1,337,842
Income taxes -
------------
Future net cash flows 1,279,785
10% discount factor (1,120,417)
-------------
Standardized measure of discounted
future net cash flows $ 159,368*
=============
Estimated future development cost
anticipated for fiscal 2009 and
2010 on existing properties $ 216,000
============
*The standardized measure discounted at 10% attributed to proved
developed reserves is $289.8 million.
Costs incurred for oil and gas producing activities (in thousands)
for the year ended December 31, 2008 are as follows:
Unproved property acquisition costs $ 180,149
Proved property acquisition costs 41,666
Developed costs incurred on proved
undeveloped reserves 123,999
Development costs - other 261,588
Exploration and dry hole costs 122,827
-------
Total costs incurred $ 730,229
============
Capital expenditures for the full year 2008 totaled
Reserve replacement percentage 2,143%
F&D costs per Mmcfe of proved reserves added $ 1.37
Drillbit F&D costs per Mmcfe of proved reserves added $ 1.55
The principal sources of changes in the standardized measure of discounted net cash flows during the year ended
Year ended December 31, 2008 (in thousands)
Beginning of the year $ 701,874
Sales of oil and gas production during
the period, net of production costs (164,755)
Purchase of reserves in place 289,040
Net change in prices and production costs (907,844)
Changes in estimated future development costs (27,087)
Extensions, discoveries and improved recovery 242,079
Revisions of previous quantity estimates,
estimated timing of development and other (281,302)
Previously estimated development and
abandonment costs incurred during the period 123,999
Sales of reserves in place -
Change in future income tax 113,177
Accretion of discount 70,187
------
End of year $ 159,368
============
OPERATIONS UPDATE
Piceance Basin, CO, 31% - 100% WI - Current production from the Piceance Basin approximates 57 Mmcfe/d gross and 46 Mmcfe/d net. The last ten wells drilled in the Vega Area averaged ten days, down from the third quarter 2008 average of 13 days. The Company has an inventory of approximately 35 wells that have been drilled but not yet completed. The Company will have a measured completion program based on available capital with the intention of maintaining current production levels throughout the remainder of 2009. As of mid-February, the Company does not have any drilling rigs active in the field. Throughout the first three quarters of 2008, Delta undertook a concerted effort to prepare for accelerated drilling activity that would ultimately accommodate an eight-rig drilling program. This included large-scale permitting that would allow for drilling 200 new wells per year in the Vega Area beginning in 2009. The Company commenced infrastructure construction necessary for these increased volumes, which included a 16'' intrafield pipeline and additional compression facilities. Additionally, several drilling pads and roads were constructed to accommodate the expected increased rigs and activity. Accordingly, the field is set up for significant near-term growth once drilling activity resumes. The Company is continuing with its marketing efforts in seeking a joint venture partner. Proved reserves in the Piceance Basin grew from 234 Bcfe to 820 Bcfe at
Columbia River Basin, WA, 50% WI - The Company continues to drill the Gray 31-23 well and expects to be at total depth within the next 30 days. On two separate occasions, Delta has stopped drilling to run electric logs and has also taken core samples. Thus far the well has encountered numerous sandstones that contain several hundred net feet of porous and permeable sands based on wireline logs and core analysis. Porosities range from 12% to 17% with an average of 14% and permeabilities are very good and range from 27 md to 107 md. These sandstone intervals required very high mud weights to control gas flows suggesting a highly over-pressured gas system. The gas column appears to be much higher in the stratigraphic section as compared to other wells in the basin. Volumetric calculations based solely on logs and cores indicate the potential for significant gas volumes, and completion results will provide the necessary information to generate reserve estimates. Although no additional capital commitments will be made until results from the Gray 31-23 well have been obtained, the Company has begun permitting efforts for an additional well.
Paradox Basin, UT, 70% WI - In the Greentown area, the Company initially targeted intra-salt clastic intervals on the Greentown Salt Anticline because several older wells experienced significant gas shows while drilling. Delta's initial two wells experienced flow rates of 5 Mmcfe/d and 5.3 Mmcfe/d from the lower clastic intervals. The wells were located approximately seven miles apart and the clastic breaks correlated very well suggesting lateral continuity. The third well drilled in the project area tested 1,946 Bo/d and 11.6 Mmcfe/d during a 72 hour flow test. Subsequent wells were drilled and completion efforts of individual clastic intervals yielded mixed results. There are numerous individual clastic intervals yet to be completed.
Results from activity at the Greentown project have been frustrating at best, but drilling by other operators continues on leasehold immediately adjacent to Delta's. The Company's Paradox pipeline and processing facility infrastructure are well positioned if additional production is established by Delta or others in the play. The Company has decided to temporarily suspend capital expenditures in this area, but outside operator activity should provide new and important information that will help determine the project's potential. In the future, Delta plans to complete several clastic intervals requiring minimal capital investment in each of the five remaining wellbores.
Wind River Basin, WY, 100% WI - Over the last several years the Company drilled several wells in the A-Coal interval of the Waltman Shale. The better performing wells result from fracturing, and the orientation of the fractures appear to be vertical. The Company has generated an unconventional shale play in the Waltman Shale that will include horizontal wellbores directionally oriented to exploit the vertical fracture network in the A-Coal. The Company is attempting to secure a joint venture partner to develop its large leasehold throughout the Wind River Basin.
Central Utah Hingeline Project, UT, 65% WI - The Company did not experience any appreciable drilling success in its first three exploratory wells in the Utah Hingeline Play other than to establish that oil appears to have migrated through this region. The Company has impaired 90% of its acreage cost basis, but believes that of the 21 initially identified structural features only six have been condemned. As with other areas, the Company will likely seek additional joint venture participation in further exploration activities as the Company focuses a majority of its capital expenditures on lower risk projects.
Midway
Haynesville Shale, EastTX and LA, ~ 33 - 100% WI - The Company acquired rights to 16,000 gross acres in the Haynesville Shale during the second and third quarters of 2008. The acreage position is concentrated in
LIQUIDITY AND OUTLOOK
The economic and operating condition of the oil and gas exploration and production industry has changed dramatically. The decline in commodity prices has resulted in a significant decrease in Delta's liquidity position. Total liquidity as of
The Company's auditors have issued their opinion on the Company's 2008 financial statements which contains a "going concern" exploratory paragraph.
In an effort to address its liquidity situation and continue to develop its most promising opportunities, the Company has been successful in working with its bank group to modify the terms of its existing senior credit facility and expects to pursue a combination of initiatives including joint ventures, asset monetizations and other capital raising transactions, as well as cost reduction measures.
On
The Company has obtained two judgments against
NON-CASH IMPAIRMENT CHARGES
As a result of the decline in commodities prices, Delta recorded a non-cash impairment charge of approximately
For unproved properties, the impairment test 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, during the year ended
Delta performed an annual DHS goodwill impairment test during the quarter ended
RESULTS FOR THE FOURTH QUARTER 2008
For the quarter ended
For the quarter ended
FOURTH QUARTER 2008 PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per equivalent thousand cubic feet (Mcf) for the three months ended
Three Months Ended December 31,
-------------------------------
2008 2007
---- ----
Production - Continuing Operations:
Oil (MBbl) 233 267
Gas (Mmcf) 5,417 3,424
Total Production (Mmcfe) 6,817 5,028
Average Price - Continuing Operations:
Oil (per barrel) $ 49.62 $ 81.66
Gas (per Mcf) $ 4.22 $ 4.99
Costs per Mcfe - Continuing Operations:
---------------------------------------
Lease operating expense $ 1.29 $ 1.23
Production taxes $ .06 $ .51
Transportation costs $ .51 $ .25
Depletion expense $ 3.06 $ 4.01
Lease Operating Expense. Lease operating expenses for the quarter ended
Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Delta's exploration costs for the quarter ended
Depreciation, Depletion and Amortization - oil and gas. Depreciation, depletion and amortization expense increased 5% to
RESULTS FOR THE FULL YEAR 2008
For the year ended
For the year ended
FULL YEAR 2008 PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per equivalent thousand cubic feet (Mcf) for the year ended
Years Ended December 31,
------------------------
2008 2007
---- ----
Production - Continuing Operations:
Oil (MBbl) 993 1,003
Gas (Mmcf) 18,948 10,866
Production - Discontinued Operations:
Oil (MBbl) - 82
Gas (Mmcf) - 387
Total Production (Mmcfe) 24,908 17,763
Average Price - Continuing Operations:
Oil (per barrel) $ 92.12 $ 67.39
Gas (per Mcf) $ 6.87 $ 5.17
Costs per Mcfe - Continuing Operations:
---------------------------------------
Lease operating expense $ 1.35 $ 1.24
Production taxes $ .48 $ .44
Transportation costs $ .46 $ .24
Depletion expense $ 3.87 $ 4.26
Lease Operating Expense. Lease operating expenses for the year ended
Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Delta's exploration costs for the year ended
Depreciation, Depletion and Amortization - oil and gas. Depreciation, depletion and amortization expense increased 34% to
2009 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE
As previously stated, the Company plans 2009 drilling capital expenditures to be within the Company's operating cash flow and proceeds from capital raising transactions. Therefore 2009 drilling capital expenditures are expected to approximate
Forecasted full year 2009 production is expected to be relatively flat to 2008 levels. The Company currently has no production hedged for 2009, but it expects to hedge 40% of current production for the second half of 2009 and additional amounts in 2010 and beyond in accordance with the requirements of the Amendment.
CHANGES IN DELTA'S BOARD OF DIRECTORS
The Company has announced that one of the members of its board of directors,
The Company has also been informed that its largest shareholder, Tracinda Corporation, will be nominating two additional board members for election at the Company's upcoming annual shareholder meeting. Tracinda has the right to board membership proportionate to its ownership in the Company, which is approximately 40%.
EARNINGS RELEASE AND INVESTOR CONFERENCE CALL
The Company will host an investor conference call,
Shareholders and other interested parties may participate in the conference call by dialing 1-800-860-2442 (international callers dial 1-412-858-4600) and asking to be connected to the "Delta Petroleum Conference Call" a few minutes before 12:00
ABOUT DELTA PETROLEUM CORPORATION
Delta Petroleum Corporation is an oil and gas exploration and development company based in
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. Readers are cautioned that all forward-looking statements are based on management's present expectations, estimates and projections, but involve risks and uncertainty, including without limitation the effects of oil and natural gas prices, availability of capital to fund required payments on our credit facility and our working capital needs, the contraction in demand for natural gas in
For further information contact the Company at (303) 293-9133 or via email at info@deltapetro.com or RJ Falkner & Company, Inc., Investor Relations Counsel, at (800) 377-9893 or via email at info@rjfalkner.com
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
December 31, December 31,
2008 2007
---- ----
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 65,475 $9,793
Short-term restricted deposit 100,000 -
Trade accounts receivable, net of
allowance for doubtful accounts, of
$652 and $664, respectively 30,437 38,761
Deposits and prepaid assets 11,253 3,943
Inventories 9,140 4,236
Derivative instruments - 2,930
Deferred tax assets 231 150
Assets held for sale - 63,749
Other current assets 6,360 10,214
----- ------
Total current assets 222,896 133,776
Property and equipment:
Oil and gas properties, successful efforts
method of accounting:
Unproved 415,573 247,466
Proved 1,365,440 749,393
Drilling and trucking equipment 194,223 146,097
Pipeline and gathering systems 86,076 25,264
Other 29,107 15,945
------ ------
Total property and equipment 2,090,419 1,184,165
Less accumulated depreciation and depletion (658,279) (245,153)
-------- -------
Net property and equipment 1,432,140 939,012
--------- -------
Long-term assets:
Long-term restricted deposit 200,000 -
Marketable securities 1,977 6,566
Investments in unconsolidated affiliates 17,989 10,281
Deferred financing costs 7,952 7,187
Goodwill - 7,747
Other long-term assets 12,460 6,075
------ -----
Total long-term assets 240,378 37,856
------- ------
Total assets $1,895,414 $1,110,644
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Credit facility - Delta $294,475 $ -
Installments payable on property acquisition 97,453 -
Accounts payable 159,024 119,783
Other accrued liabilities 13,576 17,118
Derivative instruments - 6,295
--- -----
Total current liabilities 564,528 143,196
Long-term liabilities:
Installments payable on property acquisition,
net of current portion 188,334 -
7% Senior notes 149,534 149,459
3 3/4% Senior convertible notes 115,000 115,000
Credit facility - Delta - 73,600
Credit facility - DHS 93,848 75,000
Asset retirement obligations 6,585 4,154
Deferred tax liabilities 1,024 9,085
----- -----
Total long-term liabilities 554,325 426,298
Minority interest 29,104 27,296
Commitments and contingencies
Stockholders' equity:
Preferred stock, $.01 par value;
authorized 3,000,000 shares, none issued - -
Common stock, $.01 par value;
authorized 300,000,000 shares, issued
103,424,000 shares at December 31, 2008,
and 66,429,000 shares at December 31, 2007 1,034 664
Additional paid-in capital 1,350,502 664,733
Treasury stock at cost; 36,000 shares at
December 31, 2008 and none at
December 31, 2007 (540) -
Accumulated deficit (603,539) (151,543)
-------- ---------
Total stockholders' equity 747,457 513,854
------- -------
Total liabilities and stockholders'
Equity $1,895,414 $1,110,644
========== ==========
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
Three Months Ended Year Ended
December 31, December 31,
------------ -----------
2008 2007 2008 2007
---- ---- ---- ----
(In thousands, except per share amounts)
Revenue:
Oil and gas sales $34,453 $39,060 $221,733 $123,729
Contract drilling and trucking
fees 19,090 11,890 49,445 58,358
Gain on hedging instruments, net - 3,099 - 12,854
--- ----- --- ------
Total revenue 53,543 54,049 271,178 194,941
------ ------ ------- -------
Operating expenses:
Lease operating expense 8,786 6,191 33,508 20,882
Transportation expense 3,493 1,259 11,395 4,074
Production taxes 409 2,553 12,075 7,463
Exploration expense 5,170 2,924 10,975 9,062
Dry hole costs and impairments 428,046 12,475 438,963 87,459
Depreciation, depletion,
amortization and accretion -
oil and gas 21,734 20,655 99,125 73,875
Drilling and trucking operating
expenses 11,997 7,479 32,594 37,698
Goodwill and drilling equipment
impairments 29,349 - 29,349 -
Depreciation and amortization -
drilling and trucking 4,561 3,177 14,134 16,021
General and administrative expense 11,468 12,332 53,607 49,621
------ ------ ------ ------
Total operating expenses 525,013 69,045 735,725 306,155
------- ------ ------- -------
Operating loss (471,470) (14,996) (464,457) (111,214)
-------- ------- -------- --------
Other income and (expense):
Interest expense and financing
costs (14,239) (9,169) (41,421) (29,279)
Interest income 1,732 25 10,132 2,080
Other income (expense) (1,584) (245) (5,210) 376
Realized gain on derivative
instruments, net 16,328 129 18,383 917
Unrealized gain (loss) on
derivative instruments, net (10,209) (6,298) 3,365 (3,819)
Minority interest in losses
(income) of subsidiary 11,131 1,242 11,486 1,231
Income (loss) from unconsolidated
affiliates 562 (342) 3,375 (393)
--- ---- ----- ----
Total other income (expense),
net 3,721 (14,658) 110 (28,887)
----- ------- --- -------
Loss from continuing operations before
income taxes and discontinued
operations (467,749) (29,654) (464,437) (140,101)
Income tax expense (benefit) (8,091) (1,175) (11,723) 5,010
------ ------ ------- -----
Loss from continuing operations (459,658) (28,479) (452,714) (145,111)
Discontinued operations:
Income (loss) from discontinued
operations of properties sold
or held for sale, net of tax - (233) - 1,922
Gain (loss) on sale of discontinued
operations, net of tax (1) 231 718 (3,998)
-- --- --- ------
Net loss $(459,659)$(28,481)$(451,996)$(147,187)
--------- -------- -------- --------
Basic income (loss) per common share:
Income (loss) from continuing
operations $(4.56) $(0.44) $(4.74) $(2.37)
Discontinued operations - - 0.01 (0.04)
--- --- ---- -----
Net income (loss) $(4.56) $(0.44) $(4.73) $(2.40)
------ ------ ------ ------
Diluted income (loss) per common share:
Income (loss) from continuing
operations $(4.56) $(0.44) $(4.74) $(2.37)
Discontinued operations - - 0.01 (0.04)
--- --- ---- -----
Net income (loss) $(4.56) $(0.44) $(4.73) $(2.40)
------ ------ ------ ------
Weighted average common shares
outstanding:
Basic 100,865 64,930 95,530 61,297
Diluted 100,865 64,930 95,530 61,297
DELTA PETROLEUM CORPORATION
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
(Unaudited)
(In thousands)
THREE MONTHS ENDED: December 31, December 31,
2008 2007
---- ----
CASH PROVIDED BY OPERATING ACTIVITIES $63,820 $43,745
Changes in assets and liabilities (39,525) (23,574)
Exploration expense 5,170 2,924
----- -----
Discretionary Cash Flow* $29,465 $23,095
------- -------
YEAR ENDED: December 31, December 31,
2008 2007
---- ----
CASH PROVIDED BY OPERATING ACTIVITIES $140,676 $87,003
Changes in assets and liabilities (9,205) (20,867)
Exploration expense 10,975 9,062
------ -----
Discretionary Cash Flow* $142,446 $75,198
-------- -------
* Discretionary cash flow represents net cash provided by operating
activities before changes in assets and liabilities plus exploration
costs. Discretionary cash flow is presented as a supplemental
financial measurement in the evaluation of our business. We believe
that it provides additional information regarding our ability to meet
our 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.
THREE MONTHS ENDED: December 31, December 31,
2008 2007
---- ----
Net loss $(459,659) $(28,481)
Income tax benefit (8,091) (1,744)
Interest income (1,732) (25)
Interest and financing costs 14,239 9,169
Depletion, depreciation and amortization 26,295 23,839
Loss on sale of oil and gas properties
and other investments - 334
Unrealized loss on derivative contracts 10,209 8,295
Exploration, dry hole costs and impairments 462,565 15,399
------- ------
EBITDAX** $43,826 $26,786
------- -------
THREE MONTHS ENDED: December 31, December 31,
2008 2007
---- ----
CASH PROVIDED BY OPERATING ACTIVITIES $63,820 $43,745
Changes in assets and liabilities (39,525) (23,574)
Interest net of financing costs 8,376 6,835
Exploration costs 5,170 2,924
Other non-cash items 5,985 (3,144)
----- ------
EBITDAX** $43,826 $26,786
------- -------
YEAR ENDED: December 31, December 31,
2008 2007
---- ----
Net loss $(451,996) $(147,187)
Income tax expense (benefit) (11,723) 6,446
Interest income (10,132) (2,080)
Interest and financing costs 41,421 29,279
Depletion, depreciation and amortization 113,259 92,384
(Gain) loss on sale of oil and gas properties
and other investments (718) 2,644
Unrealized loss (gain) on derivative
contracts (3,365) 5,816
Exploration, dry hole costs and impairments 479,287 96,521
------- ------
EBITDAX** $156,033 $83,823
-------- -------
YEAR ENDED: December 31, December 31,
2008 2007
---- ----
CASH PROVIDED BY OPERATING ACTIVITIES $140,676 $87,003
Changes in assets and liabilities (9,205) (20,867)
Interest net of financing costs 19,959 22,770
Exploration costs 10,975 10,055
Other non-cash items (6,372) (15,138)
------- --------
EBITDAX** $156,033 $83,823
-------- -------
** EBITDAX represents net income before income tax expense
(benefit),interest and financing costs, depreciation, depletion and
amortization expense, gain on sale of oil and gas properties and other
investments, unrealized gains (loss) on derivative contracts and
exploration and impairment and dry hole costs. EBITDAX is presented
as a supplemental financial measurement in the evaluation of our
business. We believe that it provides additional information
regarding our ability to meet our 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 our lenders pursuant to our bank credit agreement and is
used in the financial covenants in our bank credit agreement and our
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 operating activities prepared in accordance with GAAP.
ABBREVIATIONS
-------------
Bo/d barrels of oil per day
Lbs/gal pounds per gallon
Mcf thousand cubic feet
MBbl thousand barrels of oil
Mmcf million cubic feet
Mmcfe million cubic feet equivalent
Mmcfe/d million cubic feet equivalent per day
Bcfe billion cubic feet equivalent
Mmbtu million British Thermal Units
WTI West Texas Intermediate
NYMEX New York Mercantile Exchange
LIBOR London Interbank Offered Rate
TERMS
Capital Expenditures Includes capitalized administrative expenses
and capitalized interest but does no include
proceeds or other assets
Cash Flow from Operations Earnings from operations plus non-cash charges
before settlement of asset retirement
obligations and change in non-cash working
capital
Drillbit F&D costs per
Mcfe Costs incurred excluding acquisitions divided
by the summation of annual proved reserves on a
Mcfe basis, attributable to revisions of
previous estimates, and discoveries and
extensions. Consistent with industry practice,
future capital costs to develop proved
undeveloped reserves are not included in costs
incurred.
Equity Shares, retained earnings and accumulated other
comprehensive income
All-in F&D costs per
Mcfe Total costs incurred divided by the summation
of annual proved reserves, on a Mcfe basis,
attributable to revisions of previous
estimates, purchases of minerals-in-place and
discoveries and extensions. Consistent with
industry practice, future capital costs to
develop proved undeveloped reserves are not
included in costs incurred.
Total Debt Long-term debt including current portion and
bank operating loans
SOURCE Delta Petroleum Corporation
