DENVER, Aug. 7 CO-Delta-2Q-Earns
DENVER, Aug. 7 /PRNewswire-FirstCall/ -- Delta Petroleum Corporation
(Delta or the Company) (Nasdaq: DPTR), an independent oil and gas exploration
and development company, today announced its financial and operating results
for the second quarter and first half of 2008.
SECOND QUARTER HIGHLIGHTS
-- Revenue increased 81% to $69.5 million and discretionary cash flow (a
non-GAAP measure) increased 127% to $40.7 million, when compared with the
prior-year quarter.
-- Production from continuing operations increased 75% for the second
quarter of 2008 as compared to the prior-year quarter.
-- Proved reserves (unaudited) increased 8% in the current quarter to 649
billion cubic feet of natural gas equivalents (Bcfe) as of June 30, 2008,
compared with 603 Bcfe on March 31, 2008, and 376 Bcfe as of December 31,
2007.
-- The Company's borrowing base increased from $140.0 million to $250.0
million due to growth in production and proved reserves.
-- The Greentown pipeline became operational and began accepting gas from
the Greentown Federal 28-11 well.
RESULTS FOR THE SECOND QUARTER
For the quarter ended June 30, 2008, the Company reported total production
of 6.2 Bcfe, which was consistent with the upper half of previously stated
guidance. Production from continuing operations increased 75% when compared
with the prior-year quarter and rose 16% from the levels recorded during the
first quarter of 2008. Total revenue increased 81% to $69.5 million in the
most recent quarter, compared with $38.4 million in the quarter ended June 30,
2007. Revenue from oil and gas sales increased 197% to $61.7 million,
compared with $20.7 million in the prior-year quarter. The increase in oil
and gas revenue when compared with the corresponding period of the previous
year was due to higher production from continuing operations and higher
commodity prices. Revenue from contract drilling and trucking fees decreased
45% to $7.9 million, versus $14.3 million in the second quarter of 2007, as a
result of inter-company eliminations due to additional DHS rigs working for
Delta.
EBITDAX increased 101% to $39.5 million during the three months ended June
30, 2008, compared with $19.6 million in the three months ended June 30, 2007.
Discretionary cash flow increased 127% to $40.7 million, versus $18.0 million
in the comparable 2007 quarter. (Note: EBITDAX and Discretionary Cash Flow are
non-GAAP measures and are described in greater detail below.)
After adjusting for selected items, primarily the non-cash impact of
unrealized derivative losses, net income for the second quarter 2008
approximated $4.7 million, or $0.04 per diluted share, versus an adjusted net
loss of ($26.8 million), or ($0.43) per share, in the 2007 quarter (see
reconciliation of net income (loss) (GAAP) to adjusted net income (loss) (non-
GAAP) table for additional information). Before adjusting for the selected
items, the Company reported a second quarter net loss of ($22.4 million), or
($0.22) per share, compared with a net loss of ($95.3 million), or ($1.53) per
share, in the year-earlier quarter.
SECOND QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per equivalent
thousand cubic feet (Mcfe) for the three months ended June 30, 2008 and 2007
were as follows:
Three Months Ended
June 30,
2008 2007
Production - Continuing Operations:
Oil (MBbl) 209206
Gas (MMcf)4,158 1,857
Production - Discontinued Operations:
Oil (MBbl) 38 67
Gas (MMcf) 516738
Total Production (MMcfe) 6,156 4,230
Average Price - Continuing Operations:
Oil (per barrel)$113.06 $58.38
Gas (per Mcf) $9.15 $4.70
Costs per Mcfe - Continuing Operations:
Lease operating expense$1.58 $1.52
Production taxes$.71 $.34
Transportation costs$.44 $.21
Depletion expense $3.73 $4.44
Realized derivative gain (loss) $ (1.32) $1.09
The depletion rate decreased to $3.73 per Mcfe for the three months ended
June 30, 2008, from $4.44 per Mcfe in the prior-year period, primarily as a
result of increased reserve additions and lower costs per well in the Piceance
Basin capital development program and a higher mix of production from Rocky
Mountain properties.
The Company recognized $27.1 million in unrealized losses on derivative
instruments during the three months ended June 30, 2008, compared with $1.0
million in unrealized gains during the prior-year period, primarily due to
higher commodity prices.
RESULTS FOR THE SIX-MONTH PERIOD
During the six months ended June 30, 2008, oil and gas sales from
continuing operations increased 167% to $107.1 million, compared with $40.2
million in the comparable period a year earlier. The increase was the result
of a 71% growth in production from continuing operations, an 81% increase in
oil prices, and a 65% increase in gas prices. Drilling and trucking revenue
decreased 40% to $18.6 million, from $30.9 million in the prior-year period,
as a result of inter-company eliminations due to additional DHS rigs working
for Delta.
EBITDAX increased 96% and totaled $69.3 million in the first half of 2008,
compared with $35.3 million in the six months ended June 30, 2007.
Discretionary cash flow increased 121% to $69.3 million in the six months
ended June 30, 2008, versus $31.4 million in the corresponding period of the
previous year.
After adjusting for selected items, primarily the non-cash impact of
unrealized derivative losses, net loss for the six months ended June 30, 2008
was ($966,000), or ($0.01) per diluted share, versus an adjusted net loss of
($38.8 million), or ($0.66) per share in the 2007 period. Before adjusting
for the selected items, the Company reported a net loss for the six months
ended June 30, 2008 of ($42.2 million), or ($0.47) per share, compared with a
net loss of ($113.7 million), or ($1.95) per diluted share, in the six months
ended June 30, 2007.
SIX MONTH PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per Mcfe for the six
months ended June 30, 2008 and 2007 were as follows:
Six Months Ended
June 30,
2008 2007
Production - Continuing Operations:
Oil (MBbl) 438403
Gas (MMcf)7,452 3,459
Production - Discontinued Operations:
Oil (MBbl) 75136
Gas (MMcf) 990 1,463
Total Production (MMcfe) 11,522 8,154
Average Price - Continuing Operations:
Oil (per barrel)$100.92 $55.74
Gas (per Mcf) $8.44 $5.12
Costs per Mcfe - Continuing Operations:
Lease operating expense$1.61 $1.48
Production taxes$.68 $.37
Transportation costs$.41 $.25
Depletion expense $3.87 $4.94
Realized derivative gain (loss)$(.87) $ .77
The depletion rate decreased to $3.87 per Mcfe for the six months ended
June 30, 2008, from $4.94 per Mcfe in the year-earlier period, primarily due
to increased reserve additions and lower costs per well in the Piceance Basin
capital development program and a higher mix of production from Rocky Mountain
properties.
The Company recognized $41.2 million in unrealized losses on derivative
instruments during the six months ended June 30, 2008, versus $674,000 in
unrealized losses on derivative instruments during the prior-year period,
primarily due to higher commodity prices.
DERIVATIVE CONTRACTS
The following table summarizes the Company's open derivative contracts as
of June 30, 2008:
Price Floor/
Commodity Volume Price CeilingTermIndex
Crude oil 1,200 Bbls/day $65.00/$79.86 July '08-Sept '08 NYMEX - WTI
Crude oil 1,200 Bbls/day $65.00/$79.83 Oct '08-Dec '08 NYMEX - WTI
Natural gas 15,000MMBtu/day $6.50/$8.30 July '08-Dec '08 CIG
Natural gas 10,000MMBtu/day $6.00/$7.25 July '08-Sept '08 CIG
Natural gas 10,000MMBtu/day $6.50/$8.15 July '08-Sept '08 CIG
Natural gas 10,000MMBtu/day $6.50/$7.90Oct '08-Dec '08 CIG
Natural gas 35,000MMBtu/day $7.50/$9.88Jan '09-Mar '09 CIG
Natural gas 10,000MMBtu/day $9.00/$11.53Oct '08-Dec '08 NYMEX-H HUB
Natural gas 10,000MMBtu/day $9.00/$10.58 Apr '09-June '09 NYMEX-H HUB
Natural gas 10,000MMBtu/day $9.50/$12.55 Apr '09-June '09 NYMEX-H HUB
Natural gas 15,000MMBtu/day $9.00/$10.70 Apr '09-June '09 NYMEX-H HUB
Natural gas 10,000MMBtu/day $9.00/$10.82 July'09-Sept '09 NYMEX-H HUB
Natural gas 10,000MMBtu/day $9.50/$13.00 July'09-Sept '09 NYMEX-H HUB
Natural gas 15,000MMBtu/day $9.00/$10.90 July'09-Sept '09 NYMEX-H HUB
Natural gas 10,000MMBtu/day $9.00/$12.05 Oct '09-Dec '09 NYMEX-H HUB
Natural gas 15,000MMBtu/day $9.00/$11.95 Oct '09-Dec '09 NYMEX-H HUB
Natural gas 15,000MMBtu/day $10.00/$13.10 Oct '09-Dec '09 NYMEX-H HUB
OPERATIONS UPDATE
Piceance Basin, CO, 31% - 100% WI - The Company continues to develop the
Vega Area with four DHS drilling rigs. Current plans include an increase in
the number of operating rigs to eight by the first quarter of 2009. Current
net production from the Piceance Basin approximates 46.5 million cubic feet
equivalents per day (Mmcfe/d). The Company has continued to experience
significant drilling cost reductions by decreasing the drilling time required
for new wells from an average of 15 days in the first quarter of 2008 to an
average of 13 days in the most recent quarter. Drilling results continue to
support the Company's expectation that the total resource potential of the
Company's approximate 24,000 net acres of leasehold in the Piceance Basin may
exceed 2.4 trillion cubic feet of natural gas equivalents (Tcfe). Proved
reserves are unaudited and estimated to approximate 515 Bcfe as of June 30,
2008.
In addition, Delta and its partners in the Collbran Valley Gas Gathering,
LLC (CVGG) will participate in the construction of a 20-mile, 24-inch
pipeline, with an ultimate capacity of 600 Mmcf/d. This pipeline will
interconnect with a new 22-mile, 24-inch pipeline that will provide access to
the Meeker processing facility. Initial deliveries are expected in the first
quarter of 2009. CVGG will provide the Company with significant takeaway
capacity for the development of its properties in the Vega Area.
Paradox Basin, UT, 70% WI - To date the Company has drilled six wells in
the Greentown project area. The Company is in the process of drilling two
wells, completing three wells, and has one producing well.During the past
five months, the Company has experimented with numerous drilling and
completion procedures that have included artificial stimulation of various
clastic zones in vertical wellbores and the drilling of six separate
horizontal laterals in three wellbores. The Company's activities were
primarily focused on two geologic intervals, the "O" zone and Cane Creek.
The Company continues its completion activities at the recently drilled
Greentown Federal 26-43D (83% WI), which included a 269' horizontal lateral
section in the "O" zone. The well had excellent shows while drilling and
required mud weights exceeding 19 pounds, which is indicative of very high
pressures. The wellbore has experienced numerous downhole mechanical
complications but is expected to be completed and flow tested soon.
In addition, the Company has drilled a 2,049' horizontal lateral (with
871' of lateral in the "O" zone) in the Greentown State 36-24H (75% WI) and a
2,533' horizontal lateral (all in the "O" zone) in the Greentown State 31-36
(83% WI). The Company is preparing to "frac" these laterals in mid-August and
expects initial sales by the end of the month.
Three of the wells - the Greentown Federal 26-43D, Greentown State 31-36
and Greentown State 36-24H - have been drilled horizontally in the Cane Creek
member of the Paradox Formation, with laterals of 1,439', 2,725' and 1,647',
respectively. These wells exhibited oil and gas shows while drilling or
testing, but did not provide any indication of fracturing and were not
accompanied by the over pressuring seen in the "O" zone, where pressure
gradients approach 0.9 psi/foot. The shows indicate that hydrocarbons were
present in the Cane Creek but that the lack of a bottom seal (salt) on the
western edge of the project area, where most of the wells have been drilled to
date, caused an ineffective trap. The eastern side of the Greentown area
would be at least five to six miles away from the Cane Creek subcrop and
should allow for commercial accumulations similar to the historic production
in the Big Flats/Bartlett Flats area to the southeast, where wells along the
western subcrop of the Cane Creek have been either non-productive or
marginally productive. The larger Cane Creek wells in the Big Flats Field are
located in excess of five miles to the east of the Cane Creek subcrop.
The Company is preparing to drill the Federal 11-24 with DHS rig #10.
This well site is located approximately halfway between the Greentown State
36-11 and the Greentown State 32-42 discovery wells. Simultaneously, the
Company is expected to commence drilling the Greentown Federal 33-12, which is
located one-half mile east of the Greentown State 32-42 discovery well, with
DHS rig #1.
Management believes that the drilling and production results to date
confirm that the "O" interval of the Greentown project area is a commercial
oil and natural gas bearing zone that is prospective over the majority of the
Company's acreage position. Management also believes that the Cane Creek is a
potentially commercial zone that is prospective over approximately half of the
Company's acreage position.
Columbia River Basin, WA, 100% WI - The Company is drilling the Gray 31-23
well (Bronco Prospect) in Klickitat County, Washington. On July 25, 2008 the
well experienced a fire on DHS rig #7 that injured four workers. It is
suspected that a pocket of natural gas encountered while drilling ignited on
the rig floor. Although the fire caused some damage to the rig, it has been
repaired and is expected to recommence drilling within the next few days.
Although a natural gas accumulation within the basalt is generally a positive
indication of the existence of a natural gas source, it does not necessarily
translate into the presence of economic natural gas zones beneath the basalt.
The Company still expects to reach total depth early this fall.
Central Utah Hingeline Project, UT, 65% WI - The Company has received a
permit and is building a location for the Beaver Federal 21-14 in Beaver
County, Utah. DHS rig #11 should arrive on location in mid-August, and the
well should spud immediately thereafter. This prospect is a large seismically
defined structural feature located approximately midway between the Covenant
oil field to the north and the Company's Parowan prospect (Federal 23-44 well)
to the south.
The Company has also received approval to commence completion activities
on the Federal 23-44 in the Parowan prospect. The Company plans to begin
testing various formations beginning the week of August 11, 2008.
Midway Loop Area, SE Gulf Coast, TX, ~ 10% - 55% WI - During the second
quarter, the Company completed the Baxter A-141, which had an initial
production rate of 15.3 Mmcf/d and 1,100 Bo/d. The Company is currently
drilling the Carter A-144, which is expected to reach total depth within the
next two months. The Midway Loop project wells and acreage are currently held
for sale.
Other Properties - The Company continues to develop and pursue
opportunities on its properties in the DJ Basin, Wind River Basin and
southeast Texas areas.
PRODUCTION GUIDANCE
The previously announced hydro-testing of the Rockies Express Pipeline
during the month of September 2008 may materially impact production for the
third quarter. As such, the Company is projecting a third quarter production
increase of 4% to 7% over the second quarter of 2008 to 6.4 - 6.6 Bcfe. The
Company also reaffirms its full year 2008 guidance that production should
increase 45% to 60% over 2007 levels, to a range of 25.8 - 28.4 Bcfe.
INVESTOR CONFERENCE CALL
An investor conference call has been scheduled for 12:00 noon EDT today,
Thursday, August 7, 2008.
Shareholders and other interested parties may participate in the
conference call by dialing 800-860-2442 (international callers dial 412-858-
4600) and reference the ID code "Delta Petroleum call", a few minutes before
12:00 noon Eastern time on August 7, 2008. The call will also be broadcast
live and can be accessed through the Company's website at
http://www.deltapetro.com/eventscalendar.html. A replay of the conference
call will be available one hour after the completion of the conference call
from August 7, 2008 until August 15, 2008 by dialing 877-344-7529
(international callers dial 412-317-0088) and entering the conference ID
421773#.
Delta Petroleum Corporation is an oil and gas exploration and development
company based in Denver, Colorado. The Company's core areas of operations are
the Rocky Mountain and Gulf Coast Regions, which comprise the majority of its
proved reserves, production and long-term growth prospects. Its common stock
is listed on the NASDAQ Global Market System under the symbol "DPTR."
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, 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, 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 disclose only proved reserves
that a company has demonstrated by actual production or conclusive formation
tests to be economically and legally producible under existing economic and
operating conditions. In this press release we say that we estimate our
proved reserves to be 649 Bcfe. This is an internally prepared estimate that
has not been reviewed by our third party reserve engineers. Proved reserve
increases were a function of increased drilling activity and NYMEX based
commodity prices less applicable differentials as of June 30, 2008. Please
refer to the Company's report on Form 10-K for the year ended December 31,
2007 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
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)
June 30,December 31,
2008 2007
ASSETS (In thousands)
Current assets:
Cash and cash equivalents $8,599 $9,793
Certificates of deposit 35,480 -
Trade accounts receivable, net of allowance
for doubtful accounts of $66444,265 38,761
Prepaid assets16,032 3,943
Inventories5,632 4,236
Derivative instruments - 2,930
Deferred tax assets 150150
Assets held for sale 67,621 63,749
Other current assets 6,322 10,214
Total current assets184,101133,776
Property and equipment:
Oil and gas properties, successful efforts
method of accounting:
Unproved532,763247,466
Proved1,067,286749,393
Drilling and trucking equipment 172,495146,097
Pipeline and gathering system 49,676 22,140
Other 36,905 19,069
Total property and equipment 1,859,125 1,184,165
Less accumulated depreciation and depletion (296,388) (245,153)
Net property and equipment1,562,737939,012
Long-term assets:
Long-term restricted deposit 300,000 -
Marketable securities 6,012 6,566
Investments in unconsolidated affiliates 14,635 10,281
Deferred financing costs 6,387 7,187
Goodwill 7,747 7,747
Other long-term assets13,135 6,075
Total long-term assets 347,916 37,856
Total assets $2,094,754 $1,110,644
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt$10,676$13
Accounts payable 136,519119,783
Other accrued liabilities 13,574 17,105
Derivative instruments35,718 6,295
Total current liabilities 196,487143,196
Long-term liabilities:
Installments payable on property
acquisition, net282,540 -
7% Senior notes, unsecured 149,497149,459
3-3/4% Senior convertible notes 115,000115,000
Credit facility - Delta 74,500 73,600
Credit facility - DHS 64,324 75,000
Note Payable - DHS 6,000 -
Asset retirement obligations 5,127 4,154
Derivative instruments 8,853 -
Deferred tax liabilities 8,851 9,085
Total long-term liabilities 714,692426,298
Minority interest 33,991 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 103,299,000 shares
at June 30, 2008, and 66,429,000 shares
at December 31, 2007 1,033664
Additional paid-in capital 1,343,022664,733
Treasury stock at cost; 25,000 shares at
June 30, 2008 and none at December 31, 2007(495) -
Accumulated other comprehensive loss(265) -
Accumulated deficit (193,711) (151,543)
Total stockholders' equity1,149,584513,854
Total liabilities and stockholders' equity $2,094,754 $1,110,644
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months EndedSix Months Ended
June 30, June 30,
20082007 2008 2007
(In thousands, except per share amounts)
Revenue:
Oil and gas sales $61,659 $20,728 $107,103 $40,166
Contract drilling and
trucking fees 7,875 14,299 18,595 30,919
Gain on hedging
instruments, net-3,355-4,545
Total revenue 69,534 38,382 125,698 75,630
Operating expenses:
Lease operating expense 8,5724,697 16,1938,713
Transportation expense 2,360 6454,1001,496
Production taxes 3,8591,0556,8712,175
Exploration expense 1,933 7722,9351,396
Dry hole costs and
impairments 430 70,9882,769 74,711
Depreciation,
depletion,
amortization and
accretion - oil
and gas20,807 14,152 40,160 29,853
Drilling and trucking
operations 5,5309,643 12,353 20,245
Depreciation and
amortization
- drilling and trucking 3,2094,4426,8528,806
General and
administrative 13,827 12,928 27,247 24,473
Total operating
expenses 60,527 119,322 119,480 171,868
Operating income (loss) 9,007 (80,940) 6,218 (96,238)
Other income and (expense):
Other income (186) 436 273 587
Realized loss on
derivative instruments,
net(7,130) - (8,765) -
Unrealized gain (loss)
on derivative
instruments, net (27,072) 989 (41,205)(674)
Minority interest (121) 291 208 308
Income from
unconsolidated
affiliates800- 691-
Interest income 3,388 8955,258 971
Interest expense and
financing costs(8,659) (6,236) (16,609) (13,907)
Total other expense (38,980) (3,625) (60,149) (12,715)
Loss from continuing
operations before
income taxes and
discontinued
operations (29,973) (84,565) (53,931)(108,953)
Income tax expense
(benefit) (860) 14,474 (1,458) 6,249
Loss from continuing
operations (29,113) (99,039) (52,473)(115,202)
Discontinued operations:
Income from
discontinued
operations of
properties sold,
net of tax 6,7567,596 10,302 10,079
Gain (loss) on sale
of discontinued
operations, net of tax(16) (3,880) 3 (8,542)
Net loss $(22,373)$(95,323)$(42,168) $(113,665)
Basic income (loss)
per common share:
Loss from continuing
operations $(0.29) $(1.59) $(0.58) $(1.97)
Discontinued operations 0.07 0.06 0.11 0.02
Net loss$(0.22) $(1.53) $(0.47) $(1.95)
Diluted income (loss)
per common share:
Loss from continuing
operations $(0.29) $(1.59) $(0.58) $(1.97)
Discontinued operations 0.07 0.06 0.11 0.02
Net loss$(0.22) $(1.53) $(0.47) $(1.95)
Weighted average common
shares outstanding:
Basic 101,057 62,417 90,563 58,348
Diluted101,057 62,417 90,563 58,348
DELTA PETROLEUM CORPORATION
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
(in thousands)
(unaudited)
THREE MONTHS ENDED: June 30, June 30,
2008 2007
CASH PROVIDED BY OPERATING ACTIVITIES $42,287$12,646
Changes in assets and liabilities(3,486) 4,547
Exploration expense 1,933772
Discretionary Cash Flow*$40,734$17,965
SIX MONTHS ENDED: June 30, June 30,
2008 2007
CASH PROVIDED BY OPERATING ACTIVITIES $49,383$25,423
Changes in assets and liabilities17,000 4,565
Exploration expense 2,935 1,396
Discretionary Cash Flow*$69,318$31,384
* 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: June 30, June 30,
2008 2007
Net loss $(22,373) $(95,323)
Income tax expense (benefit) (860)16,944
Interest income (3,388) (895)
Interest and financing costs 8,659 6,236
Depletion, depreciation and amortization 27,960 21,845
Loss on sale of oil and gas properties
and other investments 17 16
Unrealized (gain) loss on derivative contracts 27,072 (989)
Exploration and dry hole costs2,363 71,760
EBITDAX** $39,450$19,594
THREE MONTHS ENDED: June 30, June 30,
2008 2007
CASH PROVIDED BY OPERATING ACTIVITIES $42,287$12,646
Changes in assets and liabilities(3,486) 4,547
Interest net of financing costs 2,407 4,858
Exploration and dry hole costs1,933772
Other non-cash items (3,691)(3,229)
EBITDAX** $39,450$19,594
SIX MONTHS ENDED: June 30, June 30,
2008 2007
Net loss $(42,168) $(113,665)
Income tax expense (benefit) (1,458) 8,255
Interest income (5,258) (971)
Interest and financing costs 16,609 13,907
Depletion, depreciation and amortization 54,643 44,405
(Gain) loss on sale of oil and gas properties
and other investments (3) 6,623
Unrealized loss on derivative contracts 41,205674
Exploration and dry hole costs5,704 76,107
EBITDAX** $69,274$35,335
SIX MONTHS ENDED: June 30, June 30,
2008 2007
CASH PROVIDED BY OPERATING ACTIVITIES $49,383$25,423
Changes in assets and liabilities17,000 4,565
Interest net of financing costs 7,095 11,597
Exploration and dry hole costs3,202 2,389
Other non-cash items (7,406)(8,639)
EBITDAX** $69,274$35,335
** 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.
ADJUSTED NET INCOME
RECONCILIATION OF NET INCOME (GAAP) TO ADJUSTED NET INCOME (NON-GAAP)
(In thousands, except per share amounts)
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 20082007
Net loss $(22,373) $(95,323) $(42,168) $(113,665)
Adjustments, net of tax
Unrealized (gain) loss
on derivative
instruments, net 27,072(989)41,205 674
Impairment costs - 58,407 - 58,435
Loss (gain) on sale
of discontinued
properties 16 3,880 (3) 8,542
Valuation allowance
adjustment- 15,365 - 7,225
Total adjustments 27,088 76,663 41,202 74,876
Adjusted net income
(loss)*** $4,715$(18,660) $(966) $(38,789)
Adjusted net income
per share (non-GAAP)
Basic.05(.30) (.01) (.66)
Diluted .04(.30) (.01) (.66)
Average number of shares
outstanding
Basic101,057 62,417 90,563 58,348
Diluted(1) 107,694 62,417 90,563 58,348
*** Adjusted net income (loss) should not be considered a substitute for
net income (loss) as reported in accordance with GAAP. Adjusted net income is
provided for comparison to earnings forecasts prepared by analysts and other
third parties. Management uses adjusted net income in evaluating our
operational trends and performance relative to other oil and gas producing
companies. Items excluded are generally items whose timing or amount cannot be
reasonably estimated.
(1) The adjusted diluted net income per share calculation for the three
months ended June 30, 2008 includes an increase in diluted shares of
approximately 6.6 million shares representing the incremental dilutive shares
that would be included if not for our net loss in the period.
SOURCE Delta Petroleum Corporation
