DENVER, Aug. 9 /PRNewswire-FirstCall/ -- Delta Petroleum
Corporation (the "Company" or "Delta") (Nasdaq: DPTR), an
independent oil and gas exploration and development company, today
announced its financial and operating results for the second
quarter of 2010.
Carl Lakey, Delta's President and
CEO, stated, "The second quarter for 2010 was a pivotal period for
Delta Petroleum. We have now completed our strategic
alternatives process and have begun analyzing the results from
earlier changes in the well completion process in the Piceance
Basin. The new completion technique is generating results
that are better than expected. Although we are still early in the
evaluation process, the results to date do suggest using the new
technique on all 15 remaining wells.
"After the end of the quarter, we received approximately
$130 million in gross proceeds from
the sale to Wapiti Oil & Gas of certain non-core properties
that amounted to approximately 25% of our total proved reserves at
year end 2009. With the proceeds from this transaction, we
have reduced our credit facility borrowings to very minimal levels
and we are now in the process of obtaining a new credit facility
that we expect to have in place by the end of the third quarter. We
will continue to stringently focus on cost control and efficient
operations in the Vega area and are confident that we will be able
to create value in doing so."
$130 MILLION ASSET
DIVESTITURE
As previously announced, the Company closed on its $130 million non-core asset sale with Wapiti Oil
& Gas, L.L.C. ("Wapiti") on July 30,
2010 (the "Wapiti Transaction"). Of the $130 million purchase price, $112 million was received by the Company at
closing and used to reduce bank debt and to pay transaction
costs. The remaining $18
million is being held in escrow until third party consents
are obtained for the assignment of the Company's working interest
in certain properties that were a part of the transaction.
The Company expects to receive the consents and escrowed
funds during the third quarter of 2010, and upon receipt, such
funds will also be used to reduce debt.
In accordance with applicable accounting standards, properties
held for sale at June 30, 2010 in
conjunction with the Wapiti Transaction in which the Company only
sold half of its interest continue to be reported as a component of
continuing operations and are primarily comprised of the Newton and
Midway Loop fields. The fields classified as discontinued
operations are fields in which the Company sold all of its interest
and include the 31% working interest in the Garden Gulch field, the
Baffin Bay field, and the Bull Canyon field, as well as the
Company's interest in its wholly-owned subsidiary, Piper Petroleum.
The Company recorded impairment losses associated with assets
held for sale during the three months ended June 30, 2010 of $96.1
million, of which $92.2
million was included in loss from discontinued operations
and $3.9 million was included in dry
holes and impairments. The Company expects to recognize a
gain on sale for the closing of the Wapiti Transaction in the three
months ending September 30, 2010 of
approximately $29.4 million, subject
to revision for normal and customary purchase price adjustments as
provided for under the purchase and sale agreement. In total,
the Wapiti Transaction is expected to result in a $66.7 million loss when the second quarter asset
held for sale impairments are considered in conjunction with the
third quarter gain on sale.
See Reconciliation of Non-GAAP Measures below for a
reconciliation of non-GAAP measures to the GAAP measures each as
provided herein.
LIQUIDITY UPDATE
On July 23, 2010, the Company and
its credit facility banks agreed to amend the credit agreement for
its senior credit facility. As a result of the new amendment
and the completion of the Wapiti Transaction, the Company's
borrowing base was reduced to $35
million. The amendment imposed capital expenditures
limitations of $18 million for the
third quarter 2010 and $10 million
for the fourth quarter 2010 with a carry-over provision and
eliminated all scheduled or special borrowing base redeterminations
prior to the maturity of the facility in January 2011.
The Company was in compliance with its financial ratio, capital
expenditures and accounts payable covenants under its credit
facility as of June 30, 2010.
At July 30, 2010, the Company held
approximately $10 million in cash
after paying transaction costs on the Wapiti sale and $18 million held in escrow pending third party
consents. Based on the revised borrowing base and the
completion of the Wapiti Transaction, $11
million was available for borrowing under the amended credit
facility, giving the Company approximately $40 million in liquidity.
RESULTS FOR THE SECOND QUARTER
The Company reported a second quarter net loss attributable to
common stockholders of ($149.8
million), or ($0.54) per
share, compared with a net loss attributable to common stockholders
of ($172.3 million), or ($0.89) per share, in the second quarter of 2009.
The net loss attributable to common stockholders for the
second quarter 2010 includes a $96.1
million impairment charge associated with the assets held
for sale.
For the quarter ended June 30,
2010, the Company reported production of 4.7 billion cubic
feet equivalents ("Bcfe"). Approximately 1.3 Bcfe of
production in the quarter was from assets sold in the Wapiti
Transaction, of which 795 Mmcfe is accounted for under
"Discontinued Operations". The following discussion is on a
"Continuing Operations" basis.
Total revenue increased 73% to $36.0
million in the quarter, versus revenue of $20.9 million in the quarter ended June 30, 2009. The increase is primarily
related to a $9.4 million increase in
contract drilling and trucking fees, improved third party rig
utilization, and a $5.8 million
quarter-over-quarter increase in oil and gas sales. For the quarter
ended June 30, 2010, oil and gas
sales increased 30% to $25.1 million,
as compared to $19.3 million for the
prior year period. The increase was primarily the result of a
110% increase in natural gas prices and a 31% increase in oil
prices, partially offset by a 21% decrease in production. The
average natural gas price received during the quarter ended
June 30, 2010 increased to
$4.86 per thousand cubic feet ("Mcf")
compared to $2.31 per Mcf for the
prior year period. The average oil price received during the
quarter ended June 30, 2010 increased
to $69.88 per barrel ("Bbl") compared
to $53.22 per Bbl for the prior year
period.
SECOND QUARTER PRODUCTION VOLUMES, UNIT PRICES AND
COSTS
Production volumes, average prices received and cost per
equivalent Mcf for the three months ended June 30, 2010 and 2009 are as follows:
|
Three Months Ended
|
|
|
June 30,
|
|
|
2010
|
2009
|
|
Production – Continuing
Operations:
|
|
|
|
Oil
(Mbbl)
|
150
|
198
|
|
Gas
(Mmcf)
|
3,004
|
3,776
|
|
Total Production (Mmcfe) –
Continuing Operations
|
3,902
|
4,964
|
|
|
|
|
|
Average Price – Continuing
Operations:
|
|
|
|
Oil (per
barrel)
|
$69.88
|
$53.22
|
|
Gas (per
Mcf)
|
$4.86
|
$2.31
|
|
|
|
|
|
Costs (per Mcfe) – Continuing
Operations:
|
|
|
|
Lease operating
expense
|
$2.05
|
$1.38
|
|
Transportation
expense
|
$1.14
|
$0.44
|
|
Production
taxes
|
$0.35
|
$0.21
|
|
Depletion
expense
|
$3.82
|
$4.66
|
|
|
|
|
|
Realized derivative losses (per
Mcfe)
|
$0.15
|
$-
|
|
|
|
|
Lease Operating Expense. Lease operating expenses
for the quarter ended June 30, 2010
increased to $8.0 million from
$6.8 million in the year earlier
period primarily due to increased water handling costs in the Vega
area partially offset by lower offshore lease operating costs.
Lease operating expense per Mcfe for the quarter ended
June 30, 2010 increased to
$2.05 per Mcfe from $1.38 per Mcfe. The quarter-over-quarter
increase on a per unit basis was primarily due to the increased
water handling costs in the Vega area and the effect of fixed costs
spread over a 21% decline in production volumes.
Transportation Expense. Transportation expense for
the quarter ended June 30, 2010
increased to $4.5 million from
$2.2 million in the prior year.
Transportation expense per Mcfe for the quarter ended
June 30, 2010 increased 159% to
$1.14 per Mcfe from $0.44 per Mcfe. The increase on a per unit
basis is primarily the result of changes to the Company's Vega gas
marketing contract that went into effect in October 2009 whereby the Company's 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.
Depreciation, Depletion, Amortization and Accretion – Oil and
Gas. Depreciation, depletion and amortization expense
decreased 33% to $15.9 million for
the quarter ended June 30, 2010, as
compared to $23.8 million for the
comparable year earlier period. Depletion expense for the quarter
ended June 30, 2010 decreased to
$14.9 million from $23.1 million for the quarter ended June 30, 2009 due to lower production volumes and
a decrease in the per unit depletion rate. The Company's depletion
rate decreased from $4.66 per Mcfe
for the quarter ended June 30, 2009
to $3.82 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.
General and Administrative Expense. General and
administrative expense increased 30% to $11.6 million for the quarter ended June 30, 2010, as compared to $9.0 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 to increased non-cash stock compensation
expense related to restricted stock granted in December 2009, partially offset by reduced
staffing as a result of reductions in force during the first half
of 2009 resulting in lower cash compensation expense.
RESULTS FOR THE SIX MONTHS ENDED JUNE
30, 2010
The Company reported a six month net loss attributable to common
stockholders of ($162.5 million), or
($0.59) per share, compared with a
net loss attributable to common stockholders of ($197.9 million), or ($1.35) per share, in the six months ended
June 30, 2009. The net loss
attributable to common stockholders for the six months ended
June 30, 2010 includes a $96.1 million impairment charge associated with
assets held for sale.
For the six months ended June 30,
2010, the Company reported production of 9.7 Bcfe.
Approximately 2.7 Bcfe of production for the six month period
was from assets sold in the Wapiti Transaction, of which 1.7 Bcfe
is accounted for under "Discontinued Operations". The
following discussion is on a "Continuing Operations" basis.
Total revenue decreased 1% to $75.4
million for the six months ended June
30, 2010, versus revenue of $76.2
million in the six months ended June
30, 2009. The decrease is primarily related to a
$31.2 million gain associated with
the offshore California litigation
in 2009, offset by a $16.9 million
period-over-period increase in oil and gas sales and a $14.1 million increase in contract drilling and
trucking fees, due to improved third party rig utilization.
For the six months ended June 30,
2010, oil and gas sales increased 44% to $55.0 million, as compared to $38.1 million for the prior year period.
The increase was principally the result of a 102% increase in
natural gas prices and a 68% increase in oil prices, partially
offset by a 22% decrease in production. The average natural
gas price received during a six months ended June 30, 2010 increased to $5.38 per Mcf compared to $2.66 per Mcf for the year earlier period.
The average oil price received during the six months ended
June 30, 2010 increased to
$70.54 per Bbl compared to
$41.99 per Bbl for the year earlier
period.
SIX MONTHS ENDED PRODUCTION VOLUMES, UNIT PRICES AND
COSTS
Production volumes, average prices received and cost per
equivalent Mcf for the six months ended June
30, 2010 and 2009 are as follows:
|
Six Months Ended
|
|
|
June 30,
|
|
|
2010
|
2009
|
|
Production – Continuing
Operations:
|
|
|
|
Oil
(Mbbl)
|
299
|
405
|
|
Gas
(Mmcf)
|
6,299
|
7,934
|
|
Total Production (Mmcfe) –
Continuing Operations
|
8,093
|
10,364
|
|
|
|
|
|
Average Price – Continuing
Operations:
|
|
|
|
Oil (per
barrel)
|
$70.54
|
$41.99
|
|
Gas (per
Mcf)
|
$5.38
|
$2.66
|
|
|
|
|
|
Costs (per Mcfe) – Continuing
Operations:
|
|
|
|
Lease operating
expense
|
$1.88
|
$1.42
|
|
Transportation
expense
|
$0.96
|
$0.45
|
|
Production
taxes
|
$0.35
|
$0.25
|
|
Depletion
expense
|
$3.67
|
$4.29
|
|
|
|
|
|
Realized derivative losses (per
Mcfe)
|
$0.58
|
$-
|
|
|
|
|
Lease Operating Expense. Lease operating expenses
for the six months ended June 30,
2010 of $15.2 million was
comparable to $14.7 million in the
year earlier period. Lease operating expense per Mcfe for the
six months ended June 30, 2010
increased to $1.88 per Mcfe from
$1.42 per Mcfe for the comparable
year earlier period. The increase on a per unit basis was
primarily due to increased water handling costs in the Vega area
and the effect of fixed costs spread over a 22% decline in
production volumes.
Transportation Expense. Transportation expense for
the six months ended June 30, 2010
increased to $7.8 million from
$4.6 million in the prior year.
Transportation expense per Mcfe for the six months ended
June 30, 2010 increased to
$0.96 per Mcfe from $0.45 per Mcfe. The increase on a per unit
basis is primarily the result of changes to the Company's Vega gas
marketing contract that went into effect in October 2009 whereby the Company's 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.
Depreciation, Depletion, Amortization and Accretion – Oil and
Gas. Depreciation, depletion and amortization expense
decreased 32% to $31.3 million for
the six months ended June 30, 2010,
as compared to $45.9 million for the
comparable year earlier period. Depletion expense for the six
months ended June 30, 2010 was
$29.7 million compared to
$44.4 million for the six months
ended June 30, 2009. The depletion
rate decreased from $4.29 per Mcfe
for the six months ended June 30,
2009 to $3.67 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.
General and Administrative Expense. General and
administrative expense increased 7% to $23.0
million for the six months ended June
30, 2010, as compared to $21.6
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
to increased non-cash stock compensation expense related to
restricted stock granted in December
2009, partially offset by reduced staffing as a result of
reductions in force during the first half of 2009 resulting in
lower cash compensation expense.
ADDITIONAL FINANCIAL INFORMATION
The following table summarizes the Company's open derivative
contracts at June 30, 2010:
|
|
|
Remaining
|
|
|
Commodity
|
Volume
|
Fixed Price
|
Term
|
Index Price
|
|
|
|
|
|
|
|
Crude oil
|
1,000 Bbls /
Day(1)
|
$52.25
|
July '10 - Dec '10
|
NYMEX – WTI
|
|
Crude oil
|
500 Bbls / Day
|
$57.70
|
Jan '11 - Dec '11
|
NYMEX – WTI
|
|
Natural gas
|
6,000 MMBtu /
Day
|
$5.720
|
July '10 - Dec '10
|
NYMEX – HHUB
|
|
Natural gas
|
15,000 MMBtu /
Day
|
$4.105
|
July '10 - Dec '10
|
CIG
|
|
Natural gas
|
5,367 MMBtu /
Day
|
$3.973
|
July '10 - Dec '10
|
CIG
|
|
Natural gas
|
12,000 MMBtu /
Day
|
$5.150
|
Jan '11 - Dec '11
|
CIG
|
|
Natural gas
|
3,253 MMBtu /
Day
|
$5.040
|
Jan '11 - Dec '11
|
CIG
|
|
|
|
|
|
|
|
(1) As a result of the
closing of the Wapiti Transaction, for the period from August to
December 2010, the Company expects its oil derivative contracts to
equal 108% to 114% of forecast oil and condensate production sold
on WTI based terms. Because derivative contract volumes are
anticipated to exceed physical production volumes
in certain months, the Company could be exposed to financial
derivative losses in excess of oil revenue gains to the extent WTI
oil prices rise from current levels.
|
|
|
|
|
|
|
The pre-credit risk adjusted fair value of the Company's net
derivative liabilities as of June 30,
2010 was $6.6 million. A
credit risk adjustment of $0.6
million to the fair value of the derivatives reduced the
reported amount of the net derivative liabilities to $6.0 million.
OPERATIONS UPDATE
Total Company net production for the month of August is expected
to be 34 Mmcfe/d. During the second quarter 2010 the Company
completed one well from its drilled and uncompleted inventory in
the Vega area. The Company expects to complete the remaining
15 drilled and uncompleted wells in the third and fourth quarters
of this year, utilizing its redesigned completion techniques.
2010 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE
With the completion of the Wapiti Transaction and the reduction
in the Company's credit facility borrowing base to $35.0 million, capital expenditure limitations in
the Company's credit agreement for the third and fourth quarters of
2010 are set at $18.0 million and
$10.0 million, respectively.
The Company intends to focus capital expenditures for the
remainder of the year on completing 15 previously drilled wells in
the Vega area. Based on this level of development and
considering production sold in the Wapiti Transaction, the Company
expects oil and gas equivalent production for the remainder of the
year to range between 6.9 Bcfe and 7.2 Bcfe.
INVESTOR CONFERENCE CALL
The Company will host an investor conference call Tuesday, August 10, 2010 at 12:00 noon Eastern Time (10:00
am Mountain Time) to discuss financial and operating results
for the second quarter 2010.
Shareholders and other interested parties may participate in the
conference call by dialing 877-317-6789 (international callers dial
412-317-6789) and referencing the ID code "Delta Petroleum call," a
few minutes before 12:00 noon Eastern
Time on August 10, 2010.
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 10,
2010 until August 19, 2010 by
dialing 877-344-7529 (international callers dial 412-317-0088) and
entering the conference ID 443139.
ABOUT DELTA PETROLEUM CORPORATION
Delta Petroleum Corporation is an oil and gas exploration and
development company based in Denver,
Colorado. The Company's 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 Global Market System under the
symbol "DPTR."
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 projected capital
development and working capital needs, the ability to obtain
necessary third party consents to transfer assets to be conveyed in
the Wapiti Transaction, as well as general market conditions,
competition and pricing, the increase in supply and contraction in
demand for natural gas in the United
States, lack of availability of third party services
including frac crews, the impact of current economic and financial
conditions on our ability to raise capital, availability of
borrowings under our credit facility and the ability to obtain a
new or replacement credit facility, 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. Please
refer to the Company's report on Form 10-K for the year ended
December 31, 2009 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
DELTA PETROLEUM
CORPORATION
|
|
AND SUBSIDIARIES
|
|
CONSOLIDATED BALANCE
SHEETS
|
|
(Unaudited)
|
|
|
|
|
|
|
June 30,
|
December 31,
|
|
|
2010
|
2009
|
|
ASSETS
|
(In thousands, except share
data)
|
|
Current assets:
|
|
|
|
Cash and cash
equivalents
|
$11,051
|
$61,918
|
|
Short-term
restricted deposits
|
100,000
|
100,000
|
|
Trade accounts
receivable, net of allowance for doubtful
|
|
|
|
accounts of $100 and $100, respectively
|
17,757
|
16,654
|
|
Oil and gas
properties held for sale
|
99,902
|
-
|
|
Deposits and
prepaid assets
|
2,051
|
3,103
|
|
Inventories
|
4,150
|
5,588
|
|
Other current
assets
|
3,169
|
5,189
|
|
Total
current assets
|
238,080
|
192,452
|
|
|
|
|
|
Property and
equipment:
|
|
|
|
Oil and gas
properties, successful efforts method of accounting:
|
|
|
|
Unproved
|
236,096
|
280,844
|
|
Proved
|
944,163
|
1,379,920
|
|
Drilling and
trucking equipment
|
175,844
|
177,762
|
|
Pipeline and
gathering systems
|
96,446
|
92,064
|
|
Other
|
15,681
|
16,154
|
|
Total
property and equipment
|
1,468,230
|
1,946,744
|
|
Less accumulated
depreciation and depletion
|
(578,771)
|
(800,501)
|
|
Net
property and equipment
|
889,459
|
1,146,243
|
|
|
|
|
|
Long-term assets:
|
|
|
|
Long-term
restricted deposit
|
100,000
|
100,000
|
|
Investments in
unconsolidated affiliates
|
4,928
|
7,444
|
|
Deferred financing
costs
|
2,442
|
3,017
|
|
Other long-term
assets
|
6,163
|
8,329
|
|
Total
long-term assets
|
113,533
|
118,790
|
|
|
|
|
|
Total
assets
|
$1,241,072
|
$1,457,485
|
|
|
|
|
|
LIABILITIES AND
EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
Credit facility –
Delta
|
$119,538
|
$-
|
|
Credit facility –
DHS
|
73,590
|
83,268
|
|
Installments
payable on property acquisition
|
99,144
|
97,874
|
|
Accounts
payable
|
31,175
|
44,225
|
|
Liabilities related
to oil and gas properties held for sale
|
7,280
|
-
|
|
Offshore litigation
payable
|
-
|
13,877
|
|
Other accrued
liabilities
|
11,628
|
13,459
|
|
Derivative
instruments
|
4,705
|
19,497
|
|
Total
current liabilities
|
347,060
|
272,200
|
|
|
|
|
|
Long-term
liabilities:
|
|
|
|
Installments
payable on property acquisition, net of current portion
|
96,619
|
95,381
|
|
7% Senior
notes
|
149,647
|
149,609
|
|
3 3/4% Senior
convertible notes
|
106,268
|
104,008
|
|
Credit facility –
Delta
|
-
|
124,038
|
|
Asset retirement
obligations
|
4,620
|
7,654
|
|
Derivative
instruments
|
1,319
|
7,475
|
|
Total
long-term liabilities
|
358,473
|
488,165
|
|
|
|
|
|
Commitments and
contingencies
|
|
|
|
|
|
|
|
Equity:
|
|
|
|
Preferred stock,
$.01 par value:
|
|
|
|
authorized 3,000,000 shares, none issued
|
-
|
-
|
|
Common stock, $.01
par value: authorized 600,000,000 shares,
|
|
|
|
issued 282,760,000 shares at June 30, 2010 and
|
|
|
|
282,548,000 shares at December 31, 2009
|
2,828
|
2,825
|
|
Additional paid-in
capital
|
1,631,517
|
1,625,035
|
|
Treasury stock at
cost; 34,000 shares at June 30, 2010
|
|
|
|
and
42,000 shares at December 31, 2009
|
(75)
|
(268)
|
|
Accumulated
deficit
|
(1,101,557)
|
(939,010)
|
|
Total
Delta stockholders' equity
|
532,713
|
688,582
|
|
Non-controlling
interest
|
2,826
|
8,538
|
|
Total
equity
|
535,539
|
697,120
|
|
|
|
|
|
Total
liabilities and equity
|
$1,241,072
|
$1,457,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DELTA PETROLEUM
CORPORATION
|
|
AND SUBSIDIARIES
|
|
CONSOLIDATED STATEMENTS OF
OPERATIONS
|
|
(Unaudited)
|
|
|
Three Months Ended
|
Six Months Ended
|
|
|
June 30,
|
June 30,
|
|
|
2010
|
2009
|
2010
|
2009
|
|
|
(In thousands, except per share
amounts)
|
|
Revenue:
|
|
|
|
|
|
Oil and gas
sales
|
$25,067
|
$19,267
|
$54,970
|
$38,116
|
|
Contract drilling
and trucking fees
|
11,064
|
1,674
|
20,996
|
6,887
|
|
Gain (loss) on
offshore litigation award and property sales, net
|
(109)
|
(81)
|
(538)
|
31,204
|
|
Total revenue
|
36,022
|
20,860
|
75,428
|
76,207
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
Lease operating
expense
|
8,015
|
6,845
|
15,202
|
14,749
|
|
Transportation
expense
|
4,454
|
2,178
|
7,807
|
4,626
|
|
Production
taxes
|
1,377
|
1,061
|
2,821
|
2,550
|
|
Exploration
expense
|
358
|
471
|
584
|
1,531
|
|
Dry hole costs and
impairments
|
30,767
|
106,621
|
31,121
|
108,064
|
|
Depreciation,
depletion, amortization and accretion – oil and gas
|
15,920
|
23,846
|
31,339
|
45,850
|
|
Drilling and
trucking operating expenses
|
8,123
|
2,342
|
16,012
|
7,598
|
|
Depreciation and
amortization – drilling and trucking
|
5,226
|
6,175
|
10,798
|
11,967
|
|
General and
administrative
|
11,640
|
8,966
|
23,027
|
21,594
|
|
Executive severance
expense, net
|
-
|
3,739
|
-
|
3,739
|
|
Total operating expenses
|
85,880
|
162,244
|
138,711
|
222,268
|
|
|
|
|
|
|
|
Operating loss
|
(49,858)
|
(141,384)
|
(63,283)
|
(146,061)
|
|
|
|
|
|
|
|
Other income and
(expense):
|
|
|
|
|
|
Interest expense
and financing costs, net
|
(9,556)
|
(15,775)
|
(20,116)
|
(32,201)
|
|
Other income
(expense), net
|
(299)
|
1,256
|
(170)
|
1,408
|
|
Realized loss on
derivative instruments, net
|
(601)
|
-
|
(4,714)
|
-
|
|
Unrealized gain
(loss) on derivative instruments, net
|
3,676
|
(15,647)
|
20,948
|
(21,111)
|
|
Income (loss) from
unconsolidated affiliates
|
991
|
(3,617)
|
983
|
(2,870)
|
|
|
|
|
|
|
|
Total other expense
|
(5,789)
|
(33,783)
|
(3,069)
|
(54,774)
|
|
|
|
|
|
|
|
Loss from continuing operations
before income taxes and
|
|
|
|
|
|
discontinued
operations
|
(55,647)
|
(175,167)
|
(66,352)
|
(200,835)
|
|
|
|
|
|
|
|
Income tax expense
(benefit)
|
203
|
265
|
478
|
(318)
|
|
|
|
|
|
|
|
Loss from continuing
operations
|
(55,850)
|
(175,432)
|
(66,830)
|
(200,517)
|
|
|
|
|
|
|
|
Discontinued
operations:
|
|
|
|
|
|
|
|
|
|
|
|
Loss from
discontinued operations, net of tax
|
(96,630)
|
(5,051)
|
(101,642)
|
(9,400)
|
|
|
|
|
|
|
|
Net loss
|
(152,480)
|
(180,483)
|
(168,472)
|
(209,917)
|
|
|
|
|
|
|
|
Less net loss
attributable to non-controlling interest
|
2,730
|
8,165
|
5,925
|
12,046
|
|
|
|
|
|
|
|
Net loss attributable to Delta
common stockholders
|
$(149,750)
|
$(172,318)
|
$(162,547)
|
$(197,871)
|
|
|
|
|
|
|
|
Amounts attributable to Delta
common stockholders:
|
|
|
|
|
|
Loss from
continuing operations
|
$(53,120)
|
$(167,267)
|
$(60,905)
|
$(188,471)
|
|
Loss from
discontinued operations, net of tax
|
(96,630)
|
(5,051)
|
(101,642)
|
(9,400)
|
|
Net loss
|
$(149,750)
|
$(172,318)
|
$(162,547)
|
$(197,871)
|
|
|
|
|
|
|
|
Basic income (loss) attributable
to Delta common stockholders
|
|
|
|
|
|
per common
share:
|
|
|
|
|
|
Loss from
continuing operations
|
$(0.19)
|
$(0.86)
|
$(0.22)
|
$(1.29)
|
|
Discontinued
operations
|
(0.35)
|
(0.03)
|
(0.37)
|
(0.06)
|
|
Net loss
|
$(0.54)
|
$(0.89)
|
$(0.59)
|
$(1.35)
|
|
|
|
|
|
|
|
Diluted income (loss)
attributable to Delta common stockholders
|
|
|
|
|
|
per common
share:
|
|
|
|
|
|
Loss from
continuing operations
|
$(0.19)
|
$(0.86)
|
$(0.22)
|
$(1.29)
|
|
Discontinued
operations
|
(0.35)
|
(0.03)
|
(0.37)
|
(0.06)
|
|
Net loss
|
$(0.54)
|
$(0.89)
|
$(0.59)
|
$(1.35)
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding:
|
|
|
|
|
|
Basic
|
275,832
|
193,028
|
275,652
|
146,248
|
|
Diluted
|
275,832
|
193,028
|
275,652
|
146,248
|
|
|
|
|
|
|
DELTA PETROLEUM
CORPORATION
|
|
AND SUBSIDIARIES
|
|
RECONCILIATION OF NON-GAAP
MEASURES
|
|
(Unaudited)
|
|
($in thousands)
|
|
|
|
|
|
THREE MONTHS ENDED
|
June 30,
|
June 30,
|
|
|
2010
|
2009
|
|
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
|
$(6,332)
|
$38,757
|
|
Changes in assets and
liabilities
|
6,650
|
(3,778)
|
|
Less net proceeds from offshore
litigation award
|
-
|
(48,701)
|
|
Exploration costs
|
358
|
471
|
|
Discretionary cash flow
(deficiency)*
|
$676
|
$(13,251)
|
|
|
|
|
|
|
|
|
|
SIX MONTHS ENDED
|
June 30,
|
June 30,
|
|
|
2010
|
2009
|
|
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
|
$(23,273)
|
$32,849
|
|
Changes in assets and
liabilities
|
27,271
|
(11,286)
|
|
Less net proceeds from offshore
litigation award
|
-
|
(48,701)
|
|
Exploration costs
|
584
|
1,531
|
|
Discretionary cash flow
(deficiency)*
|
$4,582
|
$(25,607)
|
|
|
|
|
|
|
|
|
|
* Discretionary cash flow
represents net cash provided by (used in) operating activities
before changes in assets and liabilities, net proceeds from
offshore litigation award and 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,
|
|
|
2010
|
2009
|
|
Net loss
|
$(152,480)
|
$(180,483)
|
|
Minority interest
|
2,730
|
8,165
|
|
Income tax expense
|
203
|
265
|
|
Interest expense and financing
costs, net
|
9,556
|
15,775
|
|
Depletion, depreciation and
amortization
|
26,973
|
36,107
|
|
(Gain) loss on offshore
litigation award, property sales and other
|
440
|
(1,643)
|
|
Unrealized (gain) loss on
derivative instruments, net
|
(3,676)
|
15,647
|
|
Exploration, dry hole and
impairment costs
|
123,287
|
107,092
|
|
EBITDAX**
|
$7,033
|
$925
|
|
|
|
|
|
THREE MONTHS ENDED
|
June 30,
|
June 30,
|
|
|
2010
|
2009
|
|
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
|
$(6,332)
|
$38,757
|
|
Changes in assets and
liabilities
|
6,650
|
(3,778)
|
|
Less net proceeds from offshore
litigation award
|
-
|
(48,701)
|
|
Interest net of financing
costs
|
6,141
|
10,446
|
|
Exploration costs
|
358
|
471
|
|
Other non-cash items
|
216
|
3,730
|
|
EBITDAX**
|
$7,033
|
$925
|
|
|
|
|
|
SIX MONTHS ENDED
|
June 30,
|
June 30,
|
|
|
2010
|
2009
|
|
Net loss
|
$(168,472)
|
$(209,917)
|
|
Minority interest
|
5,925
|
12,046
|
|
Income tax expense
(benefit)
|
478
|
(318)
|
|
Interest expense and financing
costs, net
|
20,116
|
32,201
|
|
Depletion, depreciation and
amortization
|
55,731
|
68,721
|
|
(Gain) loss on offshore
litigation award, property sales and other
|
801
|
(32,928)
|
|
Unrealized (gain) loss on
derivative instruments, net
|
(20,948)
|
21,111
|
|
Exploration, dry hole and
impairment costs
|
123,867
|
109,595
|
|
EBITDAX**
|
$17,498
|
$511
|
|
|
|
|
|
SIX MONTHS ENDED
|
June 30,
|
June 30,
|
|
|
2010
|
2009
|
|
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
|
$(23,273)
|
$32,849
|
|
Changes in assets and
liabilities
|
27,271
|
(11,286)
|
|
Less net proceeds from offshore
litigation award
|
-
|
(48,701)
|
|
Interest net of financing
costs
|
12,901
|
20,774
|
|
Exploration costs
|
584
|
1,531
|
|
Other non-cash items
|
15
|
5,344
|
|
EBITDAX**
|
$17,498
|
$511
|
|
|
|
|
|
** EBITDAX represents net
loss before minority interest, income tax expense (benefit),
interest expense and financing costs, net, depreciation, depletion
and amortization expense, gain and loss on sale of oil and gas
properties, offshore litigation and other investments, net
unrealized gains and losses 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 (used in) operating activities
prepared in accordance with GAAP.
|
|
|
|
|
|
|
|
|
|
|
|
THREE MONTHS ENDED
|
June 30, 2010
|
|
June 30, 2009
|
|
|
Oil (Mbbl)
|
Gas (Mmcf)
|
Mmcfe
|
|
Oil (Mbbl)
|
Gas (Mmcf)
|
Mmcfe
|
|
Total Production
|
153
|
3,777
|
4,697
|
|
202
|
4,483
|
5,695
|
|
Less Wapiti Transaction
production
|
|
|
|
|
|
|
|
|
reported in discontinued
operations***
|
(4)
|
(773)
|
(795)
|
|
(4)
|
(707)
|
(731)
|
|
Production from Continuing
Operations
|
150
|
3,004
|
3,902
|
|
198
|
3,776
|
4,964
|
|
Less Wapiti Transaction
production
|
|
|
|
|
|
|
|
|
reported in continuing
operations***
|
(54)
|
(223)
|
(547)
|
|
(71)
|
(316)
|
(742)
|
|
Production from Remaining
Operations
|
96
|
2,781
|
3,355
|
|
127
|
3,460
|
4,222
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SIX MONTHS ENDED
|
June 30, 2010
|
|
June 30, 2009
|
|
|
Oil (Mbbl)
|
Gas (Mmcf)
|
Mmcfe
|
|
Oil (Mbbl)
|
Gas (Mmcf)
|
Mmcfe
|
|
Total Production
|
309
|
7,889
|
9,743
|
|
414
|
9,532
|
12,016
|
|
Less Wapiti Transaction
production
|
|
|
|
|
|
|
|
|
reported in discontinued
operations***
|
(10)
|
(1,590)
|
(1,650)
|
|
(9)
|
(1,598)
|
(1,652)
|
|
Production from Continuing
Operations
|
299
|
6,299
|
8,093
|
|
405
|
7,934
|
10,364
|
|
Less Wapiti Transaction
production
|
|
|
|
|
|
|
|
|
reported in continuing
operations***
|
(106)
|
(443)
|
(1,079)
|
|
(147)
|
(627)
|
(1,509)
|
|
Production from Remaining
Operations
|
193
|
5,856
|
7,014
|
|
258
|
7,307
|
8,855
|
|
|
|
|
|
|
|
|
|
|
*** The properties
included in the Wapiti Transaction were comprised of non-operated
properties in which Delta sold all of its interest to Wapiti and
operated properties in which Delta sold half of its interest to
Wapiti. In accordance with applicable accounting rules,
properties in which Delta sold all of its interest are reported as
discontinued operations. However, properties in which Delta
only sold half of its interest to Wapiti are required to be
reported as a component of continuing
operations. As a result, the Company's results from
continuing operations for all periods presented include production
from properties included in the Wapiti Transaction in which Delta
now owns 50% less than the amounts included in the Company's
financial statements as continuing operations. As a result,
the Company believes that the information presented will be useful
to investors and analysts in understanding the impact of the
transaction upon the Company's production. Adjustments "from
Continuing Operations" and totals "from Remaining Operations" are
non-GAAP measures, but are reconciled to their equivalent GAAP
measure.
|
|
|
|
|
|
|
|
|
|
SOURCE Delta Petroleum Corporation
Copyright g. 9 PR Newswire