DENVER, Aug. 4, 2011 /PRNewswire/ -- Delta Petroleum
Corporation ("Delta" or the "Company") (NASDAQ Capital Market:
DPTRD), an independent oil and gas exploration and development
company, today announced its financial and operating results for
the second quarter 2011.
Carl Lakey, Delta's CEO and
President stated, "We are pleased to provide our shareholders with
another solid operating quarter coupled with the accomplishment of
some very important strategic steps. We sold our remaining
non-core assets, which reduced our leverage and provided sufficient
liquidity to continue our deep shale evaluation and development in
the Vega Area. While the strategic alternatives process, the
2C well results, and the Netherland Sewell report were all
announced subsequent to the end of the quarter, much of the efforts
that went into those steps occurred in the second quarter.
The 2B and 2C well results and Netherland Sewell's report are
very important contributions that support Delta's intrinsic value
and aid our strategic alternatives process."
VEGA AREA SHALE EVALUATION UPDATE
As previously announced, the Delta 2C well began producing
hydrocarbons on Wednesday, July 20,
at a rate of 5.4 million cubic feet of gas per day (MMcf/d), which
was choke-restricted with a 7/64 of an inch choke and 8,360 psi of
flowing tubing pressure. Gas sales from the well began on
Thursday, July 21 from the Niobrara
and Frontier formations only. The well is currently producing
between 2.5 – 3.5 MMcf/d with 6,100 psi of flowing tubing pressure.
The well choke is currently set at 9/64 of an inch. The
Mancos shale, Corcoran and Williams Fork formations remain
uncompleted.
The Delta 2B well in the Vega Area of the Piceance Basin drilled
through a portion of the Mancos
formation and reached total depth of 10,700 feet. Below the
Williams Fork the well was completed in 1,200 feet of shale in the
Corcoran and the upper portion of the Mancos formation. Gas production began
on April 24 and sales commenced on
April 29. As announced on
May 10, the 2B well experienced
sustained production of 3.3 MMcf/d from only the Mancos and Corcoran formations. The well
is currently producing 0.6 MMcf/d. The information available
indicates that the natural fractures in the 2B well may have
prematurely closed by the high flow rate (6 MMcf/d) during initial
flowback activities, which has subsequently hindered production.
The Company is currently evaluating refracturing the well in
the Mancos and Corcoran formations
to reestablish higher production levels in the well.
The Company is currently drilling the 12B well. The
current depth is approximately 8,500 feet with a target depth of
13,000 feet. It is expected that the target depth will reach
the Frontier formation. Total depth is expected to be reached
during September. Once completed, this well will hold the
acreage of the federal Sheep Creek Unit and bring the Company's
Vega leasehold up to 95% held by production.
STRATEGIC ALTERNATIVES UPDATE
On July 6, 2011, Delta announced
that it had engaged Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as
advisors to the Company in conducting a strategic alternatives
process aimed at maximizing shareholder value and dealing with the
Company's 2012 debt maturities. Through this process, the Board of
Directors is evaluating all opportunities available, including a
potential sale of the Company. The process is in its early
stages and the Company does not expect to make further public
comment regarding the process until the Board of Directors has
approved a specific transaction or otherwise determines that
disclosure of significant developments, if any, is appropriate.
OPERATIONS UPDATE
Current production of the Company approximates 28 million cubic
feet equivalent per day (MMcfe/d) net.
2011 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE
Delta will focus its current available capital for the remainder
of 2011 on drilling and completing the 12B well and completing the
remaining two previously drilled Williams Fork wells. The
completions of the remaining two previously drilled wells have been
postponed to the fourth quarter of 2011; however, these plans could
be altered depending on shale well results, with capital
potentially being reallocated to additional shale activity.
Developments related to the strategic alternatives process
may also affect current capital spending plans.
Production for the third quarter 2011 is expected to be between
2.6 Bcfe and 2.7 Bcfe.
LIQUIDITY UPDATE
At June 30, 2011, the Company had
$3.9 million in cash and
approximately $18.0 million available
under its amended credit facility. During the second quarter,
Delta received $43.2 million from the
sale of non-core assets. The proceeds were used to pay down
the facility, close out certain oil derivative positions and for
development activity in the Company's Piceance Basin projects.
The Company expects to have sufficient capital under its
credit facility, combined with proceeds from the non-core asset
sale and net cash from operating activities, to fund Delta's
operating expenses and the current capital development described
above and to maintain its debt service obligations through the
remainder of 2011.
RESULTS FOR THE SECOND QUARTER 2011
For the quarter ended June 30,
2011, the Company reported total production of 3.2 Bcfe.
Production from continuing operations was 2.8 Bcfe, remaining
flat when comparing second quarter 2011 to the prior year period.
Revenue from oil and gas sales was $16.9 million, an increase of 14% when compared
to the prior year period of $14.8
million. The average natural gas price received during
the quarter ended June 30, 2011
increased to $5.31 per thousand cubic
feet (Mcf) compared to $4.92 per Mcf
for the prior year period. The average oil price received
during the quarter ended June 30,
2011 increased to $86.87 per
barrel compared to $58.29 per barrel
for the prior year period.
The Company reported a second quarter net loss attributable to
Delta common stockholders of ($963,000), or ($0.03) per diluted share, compared to a net loss
attributable to Delta common stockholders of ($149.8 million), or ($5.43) per diluted share, in the second quarter
of 2010. The decrease in net loss is primarily due to a
decrease in dry hole costs and impairments and a decrease in
operating expenses, as well as discontinued operations.
SECOND QUARTER PRODUCTION VOLUMES, UNIT PRICES AND
COSTS
Production volumes, average prices received and costs per
equivalent Mcf for the quarter ended June
30, 2011 and 2010 were as follows:
|
Three Months
Ended
|
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
Production – Continuing
Operations:
|
|
|
|
|
Oil
(Mbbl)
|
38
|
|
41
|
|
Gas
(Mmcf)
|
2,550
|
|
2,528
|
|
Total Production (Mmcfe) –
Continuing Operations
|
2,781
|
|
2,774
|
|
|
|
|
|
|
Average Price – Continuing
Operations:
|
|
|
|
|
Oil (per
barrel)
|
$86.87
|
|
$58.29
|
|
Gas (per
Mcf)
|
$5.31
|
|
$4.92
|
|
|
|
|
|
|
Costs (per Mcfe) – Continuing
Operations:
|
|
|
|
|
Lease operating
expense
|
$1.28
|
|
$2.19
|
|
Transportation
expense
|
$1.30
|
|
$1.57
|
|
Production
taxes
|
$0.22
|
|
$0.28
|
|
Depletion
expense
|
$3.54
|
|
$4.03
|
|
|
|
|
|
|
Realized derivative losses (per Mcfe)
|
$(1.80)
|
|
$(0.22)
|
|
|
|
|
|
Lease Operating Expense. Lease operating expenses
for the three months ended June 30,
2011 decreased to $3.6 million
from $6.1 million in the prior year
period primarily due to lower water handling costs in the Vega Area
as a result of the resumption of development activities and
improved water handling facilities. As a result, lease
operating expenses per Mcfe in the Vega Area declined from
$2.18 per Mcfe for the three months
ended June 30, 2010 to $0.87 per Mcfe for the three months ended
June 30, 2011. Overall, lease
operating expense per Mcfe from continuing operations for the three
months ended June 30, 2011 decreased
to $1.28 per Mcfe from $2.19 per Mcfe.
Transportation Expense. Transportation expense for
the three months ended June 30, 2011
decreased to $3.6 million from
$4.4 million in the prior year.
Transportation expense per Mcfe for the three months ended
June 30, 2011 decreased 17% to
$1.30 per Mcfe from $1.57 per Mcfe. The decrease on a per unit
basis is primarily the result of adjustments in the prior year that
did not recur in the current year.
Depreciation, Depletion and Amortization.
Depreciation, depletion and amortization expense
decreased 13% to $10.5 million for
the three months ended June 30, 2011,
as compared to $12.1 million for the
comparable year earlier period. Depletion expense for the three
months ended June 30, 2011 decreased
to $9.8 million from $11.2 million for the three months ended
June 30, 2010 primarily due to higher
reserves as a result of recent drilling and completion activity in
the Vega Area. Accordingly, the Company's depletion rate
decreased from $4.03 per Mcfe for the
three months ended June 30, 2010 to
$3.54 per Mcfe for the current year
period.
Realized Loss on Derivative Instruments, Net.
During the three months ended June 30,
2011, the Company recognized a $5.0
million loss associated with settlements on derivative
contracts. Included in this loss was $3.3
million paid to settle a portion of Delta's oil derivative
contracts outstanding from July 2011
to December 2013 as a requirement to
the amended MBL Credit Agreement completed in conjunction with the
2011 non-core asset sale. During the three months ended
June 30, 2010, the Company recognized
a $601,000 loss associated with
settlements on derivative contracts.
General and Administrative Expense. General and
administrative expense decreased 39% to $6.5
million for the three months ended June 30, 2011, as compared to $10.6 million for the comparable prior year
period. The decrease in general and administrative expenses is
attributed to a decrease in non-cash stock compensation expense,
lower corporate consulting fees and to reduced staffing as a result
of attrition and a reduction in force since the second quarter of
2010 resulting in lower cash compensation expense.
RESULTS FOR THE SIX MONTHS ENDED JUNE
30, 2011
The Company reported a six month net loss attributable to common
stockholders of ($28.8 million), or
($1.03) per share, compared with a
net loss attributable to common stockholders of ($162.5 million), or ($5.90) per share, in the six months ended
June 30, 2010.
For the six months ended June 30,
2011, the Company reported production from continuing
operations of 5.78 Bcfe. Revenue from oil and gas sales was
$34.6 million, remaining flat when
compared to the prior year period. The average natural gas
price received during the six months ended June 30, 2011 decreased to $5.31 per Mcf compared to $5.49 per Mcf for the year earlier period.
The average oil price received during the six months ended
June 30, 2011 increased to
$82.31 per Bbl compared to
$59.60 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, 2011 and 2010 are as follows:
|
Six Months
Ended
|
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
Production – Continuing
Operations:
|
|
|
|
|
Oil
(Mbbl)
|
77
|
|
85
|
|
Gas
(Mmcf)
|
5,323
|
|
5,352
|
|
Total Production (Mmcfe) –
Continuing Operations
|
5,784
|
|
5,864
|
|
|
|
|
|
|
Average Price – Continuing
Operations:
|
|
|
|
|
Oil (per
barrel)
|
$82.31
|
|
$59.60
|
|
Gas (per
Mcf)
|
$5.31
|
|
$5.49
|
|
|
|
|
|
|
Costs (per Mcfe) – Continuing
Operations:
|
|
|
|
|
Lease operating
expense
|
$1.20
|
|
$1.80
|
|
Transportation
expense
|
$1.31
|
|
$1.30
|
|
Production
taxes
|
$0.25
|
|
$0.29
|
|
Depletion
expense
|
$3.67
|
|
$3.81
|
|
|
|
|
|
|
Realized derivative losses (per Mcfe)
|
$(0.94)
|
|
$(0.80)
|
|
|
|
|
|
Lease Operating Expense. Lease operating expenses
for the six months ended June 30,
2011 decreased 34% to $7.0
million as compared to $10.5
million in the year earlier period. The decrease is
primarily due to lower water handling costs in the Vega Area as a
result of the resumption of development activities and improved
water handling facilities. As a result, lease operating
expense per Mcfe in the Vega Area declined from $1.74 per Mcfe for the six months ended
June 30, 2010 to $0.88 per Mcfe for the six months ended
June 30, 2011. Overall, lease
operating expense per Mcfe from continuing operations for the six
months ended June 30, 2011 decreased
to $1.20 per Mcfe from $1.80 per Mcfe for the comparable year earlier
period.
Transportation Expense. Transportation expense for
the six months ended June 30, 2011
was $7.6 million comparable to
$7.6 million in the prior year.
Transportation expense per Mcfe for the six months ended
June 30, 2011 increased slightly to
$1.31 per Mcfe from $1.30 per Mcfe.
Depreciation, Depletion, Amortization and Accretion – Oil and
Gas. Depreciation, depletion and amortization expense
decreased 6% to $22.5 million for the
six months ended June 30, 2011, as
compared to $23.9 million for the
comparable year earlier period. Depletion expense for the six
months ended June 30, 2011 was
$21.2 million compared to
$22.3 million for the six months
ended June 30, 2010. The Company's
depletion rate decreased from $3.81
per Mcfe for the six months ended June 30,
2010 to $3.67 per Mcfe for the
current year period primarily due to higher reserves as a result of
the Company's recent drilling and completion activity in the Vega
Area.
Realized Loss on Derivative Instruments, Net.
During the six months ended June 30,
2011, the Company recognized a $5.5
million loss associated with settlements on derivative
contracts compared to a $4.7 million
loss for the comparable prior year period. Included in the
June 30, 2011 loss was $3.3 million paid to settle a portion of Delta's
oil derivative contracts outstanding from July 2011 to December
2013 as a requirement to the amended MBL Credit Agreement
completed in conjunction with the 2011 non-core asset sale.
General and Administrative Expense. General and
administrative expense decreased 37% to $13.1 million for the six months ended
June 30, 2011, as compared to
$20.9 million for the comparable
prior year period. The decrease in general and administrative
expenses is attributed to a decrease in non-cash stock compensation
expense, lower corporate consulting fees and to reduced staffing as
a result of attrition and a reduction in force during 2010
resulting in lower cash compensation expense.
DHS DRILLING COMPANY
The Board of Directors of DHS Drilling Company engaged
transaction advisors to explore a strategic alternatives process
focused on a sale of DHS or substantially all of its assets. In
accordance with accounting standards, the financial position and
results of operations relating to DHS have been reflected as assets
and liabilities held for sale and discontinued operations in the
accompanying consolidated balance sheets and statements of
operations. The DHS credit facility debt of $69.9 million at June 30,
2011 is included in the consolidated balance sheets as a
component of liabilities related to assets held for sale. The
DHS credit facility debt is non-recourse to Delta.
ADDITIONAL FINANCIAL INFORMATION
The following table summarizes the Company's open derivative
contracts at June 30, 2011:
Commodity
|
|
Volume
|
|
Fixed
Price
|
|
Remaining
Term
|
|
Index
Price
|
|
|
|
Crude oil
|
|
192
|
Bbls / Day
|
|
$57.70
|
|
Jul '11
|
- Dec '11
|
|
NYMEX –
WTI
|
|
Crude oil
|
|
79
|
Bbls / Day
|
|
$91.05
|
|
Jul '11
|
- Dec '11
|
|
NYMEX –
WTI
|
|
Crude oil
|
|
230
|
Bbls / Day
|
|
$91.05
|
|
Jan '12
|
- Dec '12
|
|
NYMEX –
WTI
|
|
Crude oil
|
|
162
|
Bbls / Day
|
|
$91.05
|
|
Jan '13
|
- Dec '13
|
|
NYMEX –
WTI
|
|
Natural gas
|
|
12,000
|
MMBtu / Day
|
|
$5.150
|
|
Jul '11
|
- Dec '11
|
|
CIG
|
|
Natural gas
|
|
3,253
|
MMBtu / Day
|
|
$5.040
|
|
Jul '11
|
- Dec '11
|
|
CIG
|
|
Natural gas
|
|
12,052
|
MMBtu / Day
|
|
$4.440
|
|
Jan '12
|
- Dec '12
|
|
CIG
|
|
Natural gas
|
|
10,301
|
MMBtu / Day
|
|
$4.440
|
|
Jan '13
|
- Dec '13
|
|
CIG
|
|
Natural gas
liquids(1)
|
|
35,406
|
Gallons / Day
|
|
$0.913
|
|
Jul '11
|
- Dec '11
|
|
MT.
BELVIEU
|
|
Natural gas
liquids(1)
|
|
30,617
|
Gallons / Day
|
|
$0.832
|
|
Jan '12
|
- Dec '12
|
|
MT.
BELVIEU
|
|
Natural gas
liquids(1)
|
|
12,286
|
Gallons / Day
|
|
$0.767
|
|
Jan '13
|
- Dec '13
|
|
MT.
BELVIEU
|
|
|
|
|
(1) Natural gas liquids
include purity ethane, propane, natural gasoline, normal butane and
isobutene derivatives and the weighted average price is
used.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTOR CONFERENCE CALL
The Company will host an investor conference call today,
Thursday, August 4, 2011 at 12:00
noon Eastern Time (10:00 am Mountain Time) to discuss financial and
operating results for the second quarter 2011.
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 4, 2011.
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 4,
2011 until August 12, 2011 by
dialing 877-344-7529 (international callers dial 412-317-0088) and
entering the conference ID 10002277.
ABOUT DELTA PETROLEUM
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 Capital Market System under
the symbol "DPTRD" until on or around August
10, 2011, when the symbol will return to "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. Such forward-looking statements
include, without limitation, business objectives and strategies,
including our focus on the Vega Area of the Piceance Basin, as well
as statements regarding our strategic alternatives process,
possible value creation and resource potential, anticipated future
operating and overhead costs, liquidity requirements and
availability of capital, drilling and completion activity and
anticipated timing, anticipated sources and uses of capital, and
anticipated production for third quarter 2011. 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 the Company's credit facility, its
working capital needs and in respect of the possible redemption of
its senior convertible notes, the demand for natural gas in
the United States, uncertainties
in the projection of future rates of production, unanticipated
recovery or production problems, unanticipated results from wells
being drilled or completed, the effects of delays in completion of
gas gathering systems, pipelines and processing facilities,
regulations that might be adopted in the future that could, among
other things, significantly limit or curtail hydraulic fracturing
techniques used in the Piceance Basin, as well as general market
conditions, competition and pricing. The United States
Securities and Exchange Commission permits oil and gas companies,
in their filings with the SEC, to characterize as proved reserves
only those accumulations that a company has demonstrated by actual
production or conclusive formation tests to be economically and
legally producible under existing economic and operating
conditions, and that are part of an approved five-year development
plan. Please refer to the Company's report on Form 10-K for
the year ended December 31, 2010 and
subsequent reports on Forms 10-Q and 8-K as filed with the
Securities and Exchange Commission for additional
information. The Company is under no obligation (and
expressly disclaims any obligation) to update or alter its
forward-looking statements, whether as a result of new information,
future events or otherwise.
For further information contact the Company at (303) 293-9133 or
via email at investorrelations@deltapetro.com.
DELTA PETROLEUM
CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE
SHEETS
|
|
|
|
|
|
|
|
June
30,
|
|
December
31,
|
|
|
2011
|
|
2010
|
|
|
|
|
|
|
ASSETS
|
(In
thousands, except share data)
|
|
Current assets:
|
|
|
|
|
Cash and cash
equivalents
|
$3,894
|
|
$14,190
|
|
Short-term
restricted deposits
|
100,000
|
|
100,000
|
|
Trade accounts
receivable, net of allowance for doubtful
|
|
|
|
|
accounts of $100 and $100, respectively
|
7,510
|
|
7,373
|
|
Assets held for
sale – DHS subsidiary and oil and gas properties
|
66,704
|
|
108,218
|
|
Deposits and
prepaid assets
|
2,617
|
|
1,720
|
|
Inventories
|
642
|
|
3,446
|
|
Other current
assets
|
2,836
|
|
4,821
|
|
Total
current assets
|
184,203
|
|
239,768
|
|
|
|
|
|
|
Property and
equipment:
|
|
|
|
|
Oil and gas properties, successful efforts method of accounting:
|
|
|
|
|
Unproved
|
229,623
|
|
229,943
|
|
Proved
|
695,189
|
|
671,041
|
|
Pipeline and
gathering systems
|
92,461
|
|
93,558
|
|
Other
|
13,815
|
|
13,556
|
|
Total
property and equipment
|
1,031,088
|
|
1,008,098
|
|
Less accumulated
depreciation and depletion
|
(247,438)
|
|
(232,493)
|
|
Net
property and equipment
|
783,650
|
|
775,605
|
|
|
|
|
|
|
Long-term assets:
|
|
|
|
|
Investments in
unconsolidated affiliates
|
3,590
|
|
3,376
|
|
Deferred financing
costs
|
1,432
|
|
1,832
|
|
Other long-term
assets
|
2,970
|
|
3,531
|
|
Total long-term
assets
|
7,992
|
|
8,739
|
|
|
|
|
|
|
Total
assets
|
$975,845
|
|
$1,024,112
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND EQUITY
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
Credit facility –
Delta
|
$15,000
|
|
$-
|
|
Installment payable
on property acquisition
|
99,144
|
|
97,874
|
|
3 3/4% Senior
convertible notes – current
|
110,953
|
|
-
|
|
Accounts
payable
|
21,030
|
|
27,616
|
|
Liabilities related
to assets held for sale - DHS subsidiary and
|
|
|
|
|
oil
and gas properties
|
76,112
|
|
82,852
|
|
Other accrued
liabilities
|
8,281
|
|
11,066
|
|
Derivative
instruments
|
2,123
|
|
574
|
|
Total
current liabilities
|
332,643
|
|
219,982
|
|
|
|
|
|
|
Long-term
liabilities:
|
|
|
|
|
7% Senior
notes
|
149,722
|
|
149,684
|
|
3 3/4% Senior
convertible notes
|
-
|
|
108,593
|
|
Credit facility –
Delta
|
-
|
|
29,130
|
|
Asset retirement
obligations
|
3,299
|
|
2,709
|
|
Derivative
instruments
|
3,482
|
|
2,419
|
|
Total
long-term liabilities
|
156,503
|
|
292,535
|
|
|
|
|
|
|
Commitments and
contingencies
|
|
|
|
|
|
|
|
|
|
Equity:
|
|
|
|
|
Preferred stock,
$.01 par value:
|
|
|
|
|
authorized 3,000,000 shares, none issued
|
-
|
|
-
|
|
Common stock, $.01
par value: authorized 200,000,000 shares,
|
|
|
|
|
issued 29,095,000 shares at June 30, 2011 and
|
|
|
|
|
28,514,000 shares at December 31, 2010 (1)
|
291
|
|
285
|
|
Additional paid-in
capital
|
1,640,295
|
|
1,635,783
|
|
Treasury stock at
cost; zero shares at June 30, 2011
|
|
|
|
|
and
3,000 shares at December 31, 2010 (1)
|
-
|
|
(279)
|
|
Accumulated
deficit
|
(1,150,145)
|
|
(1,121,342)
|
|
Total
Delta stockholders' equity
|
490,441
|
|
514,447
|
|
Non-controlling
interest
|
(3,742)
|
|
(2,852)
|
|
Total
equity
|
486,699
|
|
511,595
|
|
|
|
|
|
|
Total
liabilities and equity
|
$975,845
|
|
$1,024,112
|
|
|
|
|
|
|
|
(1) All common share
amounts (except par value and par value per share amounts) have
been retroactively restated as of June 30, 2011 to reflect the
Company's one-for-ten reverse common stock split effective July 13,
2011.
|
|
|
|
|
|
|
DELTA PETROLEUM
CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF
OPERATIONS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Six months
Ended
|
|
|
June
30,
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
|
(In
thousands, except per share amounts)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
Oil and gas
sales
|
$16,882
|
|
$14,822
|
|
$34,597
|
|
$34,484
|
|
Loss on
property sales
|
-
|
|
(109)
|
|
-
|
|
(538)
|
|
Total revenue
|
16,882
|
|
14,713
|
|
34,597
|
|
33,946
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Lease
operating expense
|
3,563
|
|
6,067
|
|
6,958
|
|
10,527
|
|
Transportation
expense
|
3,625
|
|
4,359
|
|
7,568
|
|
7,642
|
|
Production
taxes
|
611
|
|
786
|
|
1,461
|
|
1,691
|
|
Exploration
expense
|
233
|
|
358
|
|
276
|
|
584
|
|
Dry hole
costs and impairments
|
273
|
|
29,865
|
|
416
|
|
30,219
|
|
Depreciation, depletion,
amortization and accretion
|
10,528
|
|
12,142
|
|
22,479
|
|
23,887
|
|
General and
administrative expense
|
6,471
|
|
10,648
|
|
13,100
|
|
20,898
|
|
Total operating
expenses
|
25,304
|
|
64,225
|
|
52,258
|
|
95,448
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
(8,422)
|
|
(49,512)
|
|
(17,661)
|
|
(61,502)
|
|
|
|
|
|
|
|
|
|
|
Other income and
(expense):
|
|
|
|
|
|
|
|
|
Interest
expense and financing costs, net
|
(7,997)
|
|
(7,781)
|
|
(14,803)
|
|
(16,484)
|
|
Other
income
|
233
|
|
111
|
|
164
|
|
179
|
|
Realized
loss on derivative instruments, net
|
(5,010)
|
|
(601)
|
|
(5,450)
|
|
(4,714)
|
|
Unrealized
gain (loss) on derivative instruments, net
|
8,341
|
|
3,676
|
|
(2,612)
|
|
20,948
|
|
Income from
unconsolidated affiliates
|
131
|
|
991
|
|
214
|
|
983
|
|
|
|
|
|
|
|
|
|
|
Total other income and
(expense)
|
(4,302)
|
|
(3,604)
|
|
(22,487)
|
|
912
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
before income taxes and
|
|
|
|
|
|
|
|
|
discontinued
operations
|
(12,724)
|
|
(53,116)
|
|
(40,148)
|
|
(60,590)
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
(benefit)
|
(3,938)
|
|
203
|
|
(4,633)
|
|
478
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing
operations
|
(8,786)
|
|
(53,319)
|
|
(35,515)
|
|
(61,068)
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss)
from results of operations and sale of
|
|
|
|
|
|
|
|
|
discontinued operations, net of
tax
|
9,320
|
|
(99,161)
|
|
5,785
|
|
(107,404)
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
534
|
|
(152,480)
|
|
(29,730)
|
|
(168,472)
|
|
|
|
|
|
|
|
|
|
|
Less net
(gain) loss attributable to non-controlling interest
|
|
|
|
|
|
|
|
|
included in discontinued
operations
|
(1,497)
|
|
2,730
|
|
927
|
|
5,925
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Delta
common stockholders
|
$(963)
|
|
$(149,750)
|
|
$(28,803)
|
|
$(162,547)
|
|
|
|
|
|
|
|
|
|
|
Amounts attributable to Delta common stockholders:
|
|
|
|
|
|
|
|
|
Loss from
continuing operations
|
$(8,786)
|
|
$(53,319)
|
|
$(35,515)
|
|
$(61,068)
|
|
Income
(loss) from discontinued operations, net of tax
|
7,823
|
|
(96,431)
|
|
6,712
|
|
(101,479)
|
|
Net
loss
|
$(963)
|
|
$(149,750)
|
|
$(28,803)
|
|
$(162,547)
|
|
|
|
|
|
|
|
|
|
|
Basic income (loss) attributable
to Delta common stockholders
|
|
|
|
|
|
|
|
|
per common
share:
|
|
|
|
|
|
|
|
|
Loss from
continuing operations
|
$(0.31)
|
|
$(1.93)
|
|
$(1.27)
|
|
$(2.22)
|
|
Discontinued
operations
|
0.28
|
|
(3.50)
|
|
0.24
|
|
(3.68)
|
|
Net
loss
|
$(0.03)
|
|
$(5.43)
|
|
$(1.03)
|
|
$(5.90)
|
|
|
|
|
|
|
|
|
|
|
Diluted income (loss)
attributable to Delta common stockholders
|
|
|
|
|
|
|
|
|
per common
share:
|
|
|
|
|
|
|
|
|
Loss from
continuing operations
|
$(0.31)
|
|
$(1.93)
|
|
$(1.27)
|
|
$(2.22)
|
|
Discontinued
operations
|
0.28
|
|
(3.50)
|
|
0.24
|
|
(3.68)
|
|
Net
loss
|
$(0.03)
|
|
$(5.43)
|
|
$(1.03)
|
|
$(5.90)
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding(1):
|
|
|
|
|
|
|
|
|
Basic
|
27,873
|
|
27,583
|
|
27,878
|
|
27,565
|
|
Diluted
|
27,873
|
|
27,583
|
|
27,878
|
|
27,565
|
|
|
|
|
(1) All common share
amounts (except par value and par value per share amounts) have
been retroactively restated as of June 30, 2011 to reflect the
Company's one-for-ten reverse common stock split effective July 13,
2011.
|
|
|
|
|
|
|
|
|
|
|
DELTA PETROLEUM
CORPORATION
RECONCILIATION OF DISCRETIONARY
CASH FLOW AND EBITDAX
(Unaudited)
|
|
($in
thousands)
|
|
|
|
THREE MONTHS ENDED
|
June
30,
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
CASH USED IN OPERATING
ACTIVITIES
|
$(8,686)
|
|
$(15,829)
|
|
Changes in assets and
liabilities
|
4,168
|
|
6,650
|
|
Exploration costs
|
233
|
|
358
|
|
Discretionary cash flow* –
continuing operations
|
(4,285)
|
|
(8,821)
|
|
Discretionary cash flow* –
discontinued operations
|
2,768
|
|
9,497
|
|
Total discretionary cash
flow*
|
$(1,517)
|
|
$676
|
|
|
|
|
|
|
SIX MONTHS ENDED
|
June
30,
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
CASH USED IN OPERATING
ACTIVITIES
|
$(7,076)
|
|
$(41,548)
|
|
Changes in assets and
liabilities
|
2,787
|
|
27,271
|
|
Exploration costs
|
276
|
|
584
|
|
Discretionary cash flow* –
continuing operations
|
(4,013)
|
|
(13,693)
|
|
Discretionary cash flow* –
discontinued operations
|
4,975
|
|
18,275
|
|
Total discretionary cash
flow*
|
$962
|
|
$4,582
|
|
|
|
|
|
|
* Discretionary cash flow
represents net cash provided by (used in) operating activities
before changes in assets and liabilities and exploration costs.
Discretionary cash flow is presented as a supplemental
financial measurement in the evaluation of Delta's business.
The Company believes that it provides additional information
regarding its ability to meet future debt service, capital
expenditures and working capital requirements. This measure
is widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
Discretionary cash flow is not a measure of financial
performance under GAAP. Accordingly, it should not be
considered as a substitute for cash flows from operating, investing
or financing activities as an indicator of cash flows, or as a
measure of liquidity.
|
|
|
|
THREE MONTHS ENDED
|
June
30,
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
Net loss from continuing
operations
|
$(8,786)
|
|
$(53,318)
|
|
Income tax expense
(benefit)
|
(3,938)
|
|
203
|
|
Interest expense and financing
costs, net
|
7,998
|
|
7,782
|
|
Depletion, depreciation and
amortization
|
10,527
|
|
12,142
|
|
Stock based
compensation
|
2,346
|
|
3,281
|
|
Loss on sale of oil and gas
properties and other
|
-
|
|
109
|
|
Unrealized gain on derivative
instruments, net
|
(8,341)
|
|
(3,676)
|
|
Realized loss on derivative
instruments
|
3,295
|
|
-
|
|
Exploration, dry hole and
impairment costs
|
506
|
|
30,223
|
|
EBITDAX** – continuing
operations
|
3,607
|
|
(3,254)
|
|
EBITDAX **– discontinued
operations
|
3,866
|
|
9,956
|
|
Total EBITDAX**
|
$7,473
|
|
$6,702
|
|
|
|
|
|
|
|
|
|
|
|
THREE MONTHS ENDED
|
June
30,
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
CASH USED IN OPERATING
ACTIVITIES
|
$(8,686)
|
|
$(15,829)
|
|
Changes in assets and
liabilities
|
4,168
|
|
6,650
|
|
Interest net of financing
costs
|
4,581
|
|
4,369
|
|
Exploration costs
|
233
|
|
358
|
|
Realized loss on derivative
instruments
|
3,295
|
|
-
|
|
Other non-cash items
|
16
|
|
1,198
|
|
EBITDAX** – continuing
operations
|
3,607
|
|
(3,254)
|
|
EBITDAX** – discontinued
operations
|
3,866
|
|
9,956
|
|
Total EBITDAX**
|
$7,473
|
|
$6,702
|
|
|
|
|
|
|
SIX MONTHS ENDED
|
June
30,
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
Net loss from continuing
operations
|
$(35,515)
|
|
$(61,068)
|
|
Income tax expense
(benefit)
|
(4,633)
|
|
478
|
|
Interest expense and financing
costs, net
|
14,807
|
|
16,484
|
|
Depletion, depreciation and
amortization
|
22,478
|
|
23,887
|
|
Stock based
compensation
|
4,666
|
|
6,489
|
|
Loss on sale of oil and gas
properties and other
|
-
|
|
538
|
|
Unrealized (gain) loss on derivative instruments, net
|
2,612
|
|
(20,948)
|
|
Realized loss on derivative
instruments
|
3,295
|
|
-
|
|
Exploration, dry hole and
impairment costs
|
692
|
|
30,803
|
|
EBITDAX** – continuing
operations
|
8,402
|
|
(3,337)
|
|
EBITDAX **– discontinued
operations
|
7,966
|
|
20,161
|
|
Total EBITDAX**
|
$16,368
|
|
$16,824
|
|
|
|
|
|
|
SIX MONTHS ENDED
|
June
30,
|
|
June
30,
|
|
|
2011
|
|
2010
|
|
CASH USED IN OPERATING
ACTIVITIES
|
$(7,076)
|
|
$(41,548)
|
|
Changes in assets and
liabilities
|
2,787
|
|
27,271
|
|
Interest net of financing
costs
|
8,773
|
|
9,355
|
|
Exploration costs
|
276
|
|
584
|
|
Realized loss on derivative
instruments
|
3,295
|
|
-
|
|
Other non-cash items
|
347
|
|
1,001
|
|
EBITDAX** – continuing
operations
|
8,402
|
|
(3,337)
|
|
EBITDAX** – discontinued
operations
|
7,966
|
|
20,161
|
|
Total EBITDAX**
|
$16,368
|
|
$16,824
|
|
|
|
** EBITDAX represents net
income (loss) before non-controlling interest, income tax expense
(benefit), interest expense and financing costs, net, depreciation,
depletion and amortization expense, stock based compensation, gain
and loss on sale of oil and gas properties and other investments,
net, gain on discontinued operations, unrealized gains and losses
on derivative contracts, realized losses on early termination of
derivative instruments and exploration and impairment and dry hole
costs. EBITDAX is presented as a supplemental financial
measurement in the evaluation of the Company's business.
Delta believes that it provides additional information
regarding its ability to meet future debt service, capital
expenditures and working capital requirements. This measure
is widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
EBITDAX is also a financial measurement that, with certain
negotiated adjustments, is reported to the Company's lenders
pursuant to its bank credit agreement and is used in the financial
covenants in its bank credit agreement and Delta's 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.
|
|
|
|
|
|
|
SOURCE Delta Petroleum Corporation