DENVER, March 16, 2011 /PRNewswire/ -- 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 fourth
quarter and full year 2010.
Carl Lakey, Delta's President and
CEO stated, "We are very pleased with our results for the fourth
quarter. Our EBITDAX is 20% higher than the third quarter
driven by lower operating and overhead costs, despite lower
production related to asset sales and lower average Henry Hub gas
prices in the quarter. We have been committed to reducing our
operating and overhead costs, and I'm pleased to state that we have
been able to deliver such results. We drove our LOE/Mcfe down
by 38% compared to the third quarter. Additionally, our
overhead costs are down 25% from the third quarter. We remain
focused on sustaining costs at or near these levels for 2011.
We've also had very positive results from the well completion
activity performed in the fourth quarter and to date in the first
quarter of this year. The larger frac design, which we call
Gen IV, has increased our initial production and our estimated
reserves per well. We have completed a total of 16 wells with
the Gen IV frac design and all have performed better than we would
have expected under prior completion designs. Thus, we expect
first quarter production to increase 4% to 7% over the fourth
quarter. These new cost control measures substantially
improve our EBITDAX and cash flow which, combined with increased
production at the Vega Area, provide value to our
shareholders."
Delta believes the presentation of EBITDAX (a non GAAP measure)
provides useful information because it is commonly used by
investors to assess financial performance and operating results of
ongoing business operations. Reconciliations of EBITDAX to
net income (loss) and cash provided by (used in) operating
activities, the most directly comparable GAAP financial measures,
are provided within the financial tables of this press release.
2010 YEAR-END RESERVES
For the year ended December 31,
2010, total estimated proved reserves as prepared by an
independent third party engineering firm were 134 billion cubic
feet equivalents ("Bcfe"), an increase of 17% from the prior year
when adjusted for the 39 Bcfe divesture in the third quarter of
2010. Estimated proved reserves were 91% natural gas, which
includes related natural gas liquids, and were 92% proved
developed, with a standardized measure of $192 million. Approximately 92% of proved
reserves are located in the Rocky Mountain region. In
addition to proved reserves, the Company estimates that total
proved and probable reserves for the Vega Area, its core asset,
have increased to 2.9 net trillion cubic feet equivalent ("Tcfe")
from the Williams Fork section and above.
See "Reserve Disclosure" below for more explanation with respect
to the Company's probable reserves.
Prices used to calculate the Company's estimated proved reserves
reflect the pricing methodology required under the SEC's reserve
reporting rules which uses the trailing 12-month average of the
first of the month price, or $3.95
per million British thermal units ("MMBtu") priced at Colorado
Interstate Gas (CIG) and $79.61 per
barrel of West Texas Intermediate (WTI) oil for 2010, in each case
adjusted for differentials, contractual deducts, and similar
factors.
Total costs incurred in oil and gas operations during 2010 were
$44.7 million, of which $42.4 million were drilling and completion
related.
|
Total
|
|
|
(MMcfe)
|
|
Estimated Proved Reserves:
Balance at December 31, 2009
|
153,585
|
|
|
|
|
Revisions of
quantity estimate
|
14,456
|
|
Extensions
and discoveries
|
22,164
|
|
Purchase of
properties
|
-
|
|
Sale of
properties
|
(39,240)
|
|
Production
|
(16,766)
|
|
|
|
|
Estimated Proved Reserves:
Balance at December 31, 2010
|
134,199
|
|
|
|
|
Proved
developed reserves:
|
|
|
December 31,
2009
|
132,866
|
|
December 31,
2010
|
123,688
|
|
|
|
Future net cash flows presented below are computed using first
of the month 12-month historical average and costs.
|
2010
|
|
|
|
|
Future net cash flows
|
$793,556
|
|
Future costs:
|
|
|
Production
|
402,334
|
|
Development and
abandonment
|
18,899
|
|
Income taxes*
|
-
|
|
Future net cash flows
|
372,323
|
|
10% discount
factor
|
(180,229)
|
|
Standardized measure of
discounted
|
|
|
future net cash
flows
|
$192,094
|
|
Estimated future development
cost
|
|
|
anticipated for following
two years
|
|
|
on existing
properties
|
$13,952
|
|
|
|
*No income tax provision is included in the standardized measure
calculation shown above as the Company does not project to be
taxable or pay cash income taxes based on its available tax assets
and additional tax assets generated in the development of its
reserves because the tax basis of its oil and gas properties and
NOL carryforwards exceeds the amount of discounted future net
earnings.
RESERVE SENSITIVITIES
The Company internally performed price sensitivities to its
reserve estimates using 2011 strip pricing as of December 31, 2010 with a four rig drilling
program at its Vega asset and adding $1.00 and $2.00 to
the NYMEX gas price. All reserves that were included are
limited to locations that meet the five-year drilling
requirements.
|
|
2010 SEC Reserves
|
|
|
|
|
|
Proved
Reserves
|
Standardized
Measure
|
|
|
Estimated
Reserves
|
Standardized
Measure
|
|
(Bcfe)
|
($MM)
|
|
2010 Reserve Sensitivities, Four
Rig Drilling Program
|
(Bcfe)
|
($MM)
|
|
134
|
$192
|
|
2011 Strip Pricing as of
12/31/10
|
767
|
$528
|
|
|
|
|
2011 Strip Pricing as of
12/31/10 + $1.00 NYMEX gas price
|
767
|
$873
|
|
|
|
|
2011 Strip Pricing as of
12/31/10 + $2.00 NYMEX gas price
|
767
|
$1,217
|
|
|
|
|
|
|
|
|
|
LIQUIDITY UPDATE
At December 31, 2010, the Company
had $15.7 million in cash and
approximately $6.2 million available
under its amended credit facility ($26.4
million available at March 16,
2011).
On March 14, 2011, Delta entered
into an amendment to the Macquarie Bank Limited ("MBL") Credit
Agreement that increased the availability under the term loan at
the time from $6.2 million to $25.0
million, and does not require repayments of the term loan
until the January 2012 maturity date.
Specifically, among other changes, the amendment provided for
an increase in the term loan commitment from $20.0 million to $25.0 million and removed the
requirement that advances under the term loan be subject to
approval of a development plan. In addition, so long as Delta
is not in default under the MBL Credit Agreement, Delta is not
required to comply with certain cash management provisions,
including the previous requirement to repay any term loan advances
outstanding on a monthly basis with 100% of net operating cash
flows.
At December 31, 2010, DHS Drilling
Company ("DHS") was out of compliance with debt covenants under its
credit facility and entered into a Forbearance Agreement with its
credit facility lender which expires on March 25, 2011. Although the DHS facility
is non-recourse to Delta, amounts outstanding under the DHS credit
facility are classified as a current liability in the accompanying
consolidated balance sheet as of December
31, 2010 as the amounts outstanding under the facility are
due on August 31, 2011. DHS
continues discussions with its credit facility lender regarding
amendments, waivers or other restructuring of the credit facility,
but there can be no assurance that the lender will agree to any
such amendments. The Board of Directors of DHS has directed
DHS management to explore the possible sale of the company or its
assets.
OPERATIONS UPDATE
Current production from the Vega Area exceeds 30.0 million cubic
feet equivalent per day ("Mmcfe/d") net. During the fourth
quarter 2010 the Company completed eight wells from its drilled and
uncompleted inventory in the Vega Area. Since year end, the Company
has completed three of the inventory wells and currently expects to
complete the remaining two drilled and uncompleted wells in the
second quarter of 2011. With the use of the Company's improved frac
technology, referred to as "Gen IV," currently 16 wells, or 8% of
Delta's total producing wells in the Vega Area, are contributing
approximately 39% of total production from the Vega Area.
Based on third party engineering data, the new Gen IV fracs
are producing at rates that equate to an average gross estimated
ultimate recovery ("EUR") of 1.6 Bcfe per well, an improvement from
1.15 Bcfe using Delta's prior completion methods.
As previously disclosed, the Company has drilled an exploratory
test well in the Vega Area to explore potential below the Williams
Fork section and is now conducting completion activities on the
well. Additionally, during the current quarter Delta began
drilling a second exploratory test well to continue to evaluate
resource potential beneath the Williams Fork section. Delta
will release results of the exploratory test wells when
appropriate.
The Company recently terminated a contract with a water
treatment service provider for the Vega Area, which resulted in the
elimination of an ongoing future expense of approximately
$500,000 per month for a ten year
period in exchange for a one-time payment of $1.5 million. The termination of this
contract allows Delta to use alternative methods of water treatment
and disposal that are more suitable for the amount of water that is
currently being produced at the field, and management believes that
the use of subsurface injection for water disposal is a much more
viable and cost effective approach at the present time. In
addition to the water disposal wells that are currently utilized,
the Company anticipates converting four wells in the field to water
disposal wells and possibly drilling another. The existing
wells that are targeted for water disposal are old wells that have
minimal or no gas production. Delta is currently in the
process of obtaining the necessary permits to inject produced water
into the four existing wells, which will help maintain overall
operating costs at the reduced levels.
2011 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE
Delta will focus its current available capital for 2011 on
completing the remaining five previously drilled wells, completing
the exploratory test well, drilling a second exploratory test well
to continue to evaluate potential below the Williams Fork section,
and drilling a lease preservation well, all in the Vega Area.
The Company believes that the amounts available under its
credit facility as recently amended, combined with net cash from
operating activities, will provide it with sufficient liquidity to
fund Delta's operating expenses and the capital development
described above and maintain current debt service obligations.
The 2011 capital expenditure program, beyond those
expenditures currently planned and described herein, will be
dependent upon the commodity price environment, well results and
the availability of capital to the Company.
Production for the first quarter 2011 is expected to be between
3.5 Bcfe and 3.6 Bcfe, exceeding the fourth quarter 2010 by 4% to
7%.
RESULTS FOR THE FOURTH QUARTER 2010
For the quarter ended December 31,
2010, the Company reported production from continuing
operations of 3.35 Bcfe, a decrease of 19% when compared with the
fourth quarter of 2009 due to the divestiture of assets in the
third quarter of 2010. As a result, revenue from oil and gas
sales declined 24% to $19.7 million
from $26.0 million in the prior year
quarter. The average oil price received during the three
months ended December 31, 2010
increased to $74.44 per barrel
compared to $68.13 per barrel for the
year earlier period. The average natural gas price received
during the three months ended December 31,
2010 decreased to $4.66 per
thousand cubic feet (Mcf) compared to $4.74 per Mcf for the prior year period.
Revenue from contract drilling and trucking fees increased
300% to $17.0 million in the fourth
quarter of 2010, versus $4.3 million
in the fourth quarter of 2009.
The Company reported a fourth quarter net loss attributable to
Delta common stockholders of ($33.7
million), or ($0.12) per
diluted share, compared with net loss attributable to Delta common
stockholders of ($34.1 million), or
($0.12) per diluted share, in the
fourth quarter of 2009.
FOURTH QUARTER 2010 PRODUCTION VOLUMES, UNIT PRICES AND
COSTS
Production volumes, average prices received and costs per
equivalent Mcf for the three months ended December 31, 2010 and 2009 were as follows:
|
Three Months
Ended December 31,
|
|
|
2010
|
2009
|
|
Production – Continuing
Operations:
|
|
|
|
Oil
(MBbl)
|
87
|
164
|
|
Gas
(MMcf)
|
2,828
|
3,134
|
|
Total
(MMcfe)
|
3,350
|
4,115
|
|
|
|
|
|
Average Price – Continuing
Operations:
|
|
|
|
Oil (per
barrel)
|
$74.44
|
$68.13
|
|
Gas (per
Mcf)
|
$4.66
|
$4.74
|
|
|
|
|
|
Costs per Mcfe – Continuing
Operations:
|
|
|
|
Lease operating
expense
|
$1.09
|
$1.28
|
|
Production taxes
|
$(0.01)
|
$(0.04)
|
|
Transportation costs
|
$1.20
|
$0.83
|
|
Depletion expense
|
$3.56
|
$4.29
|
|
|
|
|
Lease Operating Expense. Lease operating expenses
for the quarter ended December 31,
2010 were $3.7 million
compared to $5.3 million for the
prior year period. The 31% decrease was the result of a
decrease in water handling costs in the Vega Area due to the
resumption of a development program and to a reduced working
interest in the properties sold in the third quarter of 2010.
The average lease operating expense was $1.09 per Mcfe in the fourth quarter 2010 as
compared to $1.28 per Mcfe for the
year earlier period.
Transportation Expense. Transportation expense for
the quarter ended December 31, 2010
was $4.0 million, compared to
$3.4 million for the prior year
period, up 45% on a per unit basis from $0.83 per Mcfe to $1.20 per Mcfe. The increase on a per unit
basis is primarily the result of a change in production mix related
to the divestiture of assets in the third quarter of 2010 and
changes to the Vega gas marketing contract that went into effect in
October 2009 whereby gas is processed
through a higher efficiency plant with higher costs. Although
the Vega area transportation costs increased on a per unit basis in
the fourth quarter 2010 as a result of these operations, these
costs were offset by higher revenues in the Vega area from improved
natural gas liquids recoveries and a greater percentage of liquids
proceeds retained.
Depreciation, Depletion and Amortization – oil and gas.
Depreciation, depletion and amortization expense
decreased 31% to $12.7 million for
the quarter ended December 31, 2010,
as compared to $18.5 million for the
prior year period. Depletion expense for the quarter ended
December 31, 2010 was $11.9 million compared to $17.7 million for the quarter ended December 31, 2009. The 33% decrease in depletion
expense was primarily due to a 19% decrease in production from
continuing operations and a 17% decrease in the depletion rate.
The unit-of-production depletion rate decreased to
$3.56 per Mcfe for the quarter ended
December 31, 2010 from $4.29 per Mcfe for the prior year period. The
decrease is primarily due to improved economics from the use of
improved fracturing methods and the changed mix of properties due
to the divestiture of assets in the third quarter of 2010.
General and Administrative Expense. General and
administrative expense ("G&A") decreased 21% to $7.8 million for the quarter ended December 31, 2010, as compared to $9.9 million for the prior year period. The
decrease in general and administrative expenses is primarily
attributed to lower expenses incurred on employee benefits and
wages from reductions in force during 2010. For the quarter ended
December 31, 2010 G&A expense
included $2.7 million of non-cash
equity based compensation and $1.1
million of G&A expense related to DHS. For the
quarter ended December 31, 2009
G&A expense included $2.5 million
of non-cash equity based compensation and $1.0 million G&A expense related to DHS.
Stand alone Delta cash G&A from the quarter ended
December 31, 2010 decreased 38% from
the quarter ended December 31, 2009.
RESULTS FOR THE FULL YEAR 2010
For the year ended December 31,
2010, the Company reported total production from continuing
operations of 14.8 Bcfe, which was a decrease of 21% from the
previous year due to the divestiture of assets in the third quarter
of 2010 and production declines in the Piceance Basin. For
the year ended December 31, 2010, oil
and gas sales from continuing operations increased 14% to
$94.4 million, compared with
$82.7 million in the comparable
period a year earlier. The increase resulted from a 62%
increase in the average gas price and a 35% increase in the average
oil price. Drilling and trucking revenue increased 289% to
$53.2 million, from $13.7 million in the prior year period, as the
result of the increase in third party rig utilization due to an
increase in drilling activity attributable in particular to higher
oil prices.
For the year ended December 31,
2010, the Company reported a net loss of ($182.3) million, or ($0.66) per diluted share, compared with a net
loss of ($328.8 million), or
($1.56) per diluted share, for the
year ended December 31, 2009.
FULL YEAR 2010 PRODUCTION VOLUMES, UNIT PRICES AND
COSTS
Production volumes, average prices received and costs per
equivalent Mcf for the years ended December
31, 2010 and 2009 are as follows:
|
Years Ended
December 31,
|
|
|
2010
|
2009
|
|
Production – Continuing
Operations:
|
|
|
|
Oil
(MBbl)
|
500
|
734
|
|
Gas
(MMcf)
|
11,759
|
14,319
|
|
Total
(MMcfe)
|
14,759
|
18,727
|
|
|
|
|
|
Average Price – Continuing
Operations:
|
|
|
|
Oil (per
barrel)
|
$70.90
|
$52.45
|
|
Gas (per
Mcf)
|
$5.01
|
$3.09
|
|
|
|
|
|
Costs per Mcfe – Continuing
Operations:
|
|
|
|
Lease operating
expense
|
$1.66
|
$1.41
|
|
Production taxes
|
$0.25
|
$0.16
|
|
Transportation costs
|
$1.03
|
$0.54
|
|
Depletion expense
|
$3.73
|
$4.19
|
|
|
|
|
|
|
|
|
Lease Operating Expense. Lease operating expenses
for the year ended December 31, 2010
were $24.6 million compared to
$26.4 million for the year earlier
period, a decrease of $1.8 million;
however, lease operating expenses increased on a per unit basis
primarily due to the effect of fixed costs spread over a 21%
decline in production volumes. The average lease operating
expense was $1.66 per Mcfe in 2010 as
compared to $1.41 per Mcfe for the
year earlier period.
Transportation expense. Transportation expense for
the year ended December 31, 2010 was
$15.2 million, compared to prior year
costs of $10.1 million, up 91% on a
per unit basis from $0.54 per Mcfe to
$1.03 per Mcfe. The increase on
a per unit basis is primarily the result of changes to the Vega gas
marketing contract that went into effect in October 2009 whereby gas is processed through a
higher efficiency plant. Although the Vega area
transportation costs increased on a per unit basis in 2010 as a
result of these operations, these costs were offset by higher
revenues in the Vega area from improved natural gas liquids
recoveries and a greater percentage of liquids proceeds
retained.
Depreciation, Depletion and Amortization – oil and gas.
Depreciation, depletion and amortization expense
decreased 28% to $58.3 million for
the year ended December 31, 2010, as
compared to $81.3 million for the
year earlier period. Depletion expense for the year ended
December 31, 2010 was $55.0 million compared to $78.4 million for the year ended December 31, 2009. The 30% decrease in depletion
expense was primarily due to a 21% decrease in production from
continuing operations and an 11% decrease in the depletion rate.
The depletion rate decreased to $3.73 per Mcfe for the year ended December 31, 2010 from $4.19 per Mcfe for the year earlier period. The
decrease is primarily due to a change in the mix of Delta
properties as a result of the divestiture of assets in the third
quarter of 2010 and additional Rockies reserves recorded in 2010 as
a result of completion activities and use of improved fracturing
methods.
General and Administrative Expense. General and
administrative expense decreased slightly to $41.1 million for the year ended December 31, 2010, as compared to $41.4 million for the comparable prior year
period. While the Company experienced a decrease in general
and administrative expenses primarily attributable to lower
expenses incurred on employee benefits and wages from reductions in
force during 2010 and 2009, such decrease was offset by significant
costs associated with Delta's 2010 strategic alternatives process
and bad debt expense recorded by DHS. The Company expects further
reductions to full year cash general and administrative expenses in
2011 as cost saving measures implemented in 2010 take full effect
in 2011.
ADDITIONAL FINANCIAL INFORMATION
The following table summarizes the Company's open derivative
contracts at December 31, 2010,
required pursuant to the Company's credit agreement:
Commodity
|
Volume
|
Fixed
Price
|
Term
|
Index
Price
|
|
|
|
|
|
|
|
Crude
oil
|
500
Bbls / Day
|
$57.70
|
Jan '11- Dec
'11
|
NYMEX –
WTI
|
|
Crude
oil
|
116
Bbls / Day
|
$91.05
|
Jan '11- Dec
'11
|
NYMEX –
WTI
|
|
Crude
oil
|
497
Bbls / Day
|
$91.05
|
Jan '12- Dec
'12
|
NYMEX –
WTI
|
|
Crude
oil
|
396
Bbls / Day
|
$91.05
|
Jan '13- Dec
'13
|
NYMEX –
WTI
|
|
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
|
|
Natural
gas
|
347
MMBtu / Day
|
$4.440
|
Jan '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
|
|
|
|
|
|
|
The following table summarizes the Company's current open
derivative contracts for natural gas liquids that were put in place
during the first quarter of 2011 required pursuant to the Company's
credit agreement:
|
|
2011
|
2012
|
2013
|
|
|
|
Volume
|
|
Volume
|
|
Volume
|
|
|
Commodity
|
Index Price
|
(Mgl)
|
Price
|
(Mgl)
|
Price
|
(Mgl)
|
Price
|
|
|
|
|
|
|
|
|
|
|
Isobutane
|
Mont Belvieu-OPIS
|
659
|
$1.61
|
559
|
$1.52
|
224
|
$1.44
|
|
Normal Butane
|
Mont Belvieu-OPIS
|
790
|
1.56
|
671
|
1.49
|
269
|
1.41
|
|
Natural Gasoline
|
Mont Belvieu-OPIS
|
1,317
|
2.06
|
1,118
|
2.02
|
448
|
1.93
|
|
Propane
|
Mont Belvieu-OPIS
|
2,897
|
1.18
|
2,459
|
1.08
|
987
|
0.98
|
|
Purity Ethane
|
Mont Belvieu-OPIS
|
7,507
|
0.48
|
6,370
|
0.40
|
2,556
|
0.36
|
|
Total
|
|
13,170
|
$0.91
|
11,177
|
$0.83
|
4,484
|
$0.77
|
|
|
|
|
|
|
|
|
|
INVESTOR CONFERENCE CALL
The Company will host an investor conference call on
Thursday, March 17, 2011 at 12:00
noon Eastern Time to discuss
operating results for the fourth quarter and full year 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 March 17, 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 March 17,
2011 until March 25, 2011 by
dialing 877-344-7529 (international callers dial 412-317-0088) and
entering the conference ID 448373.
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 in the
Rocky Mountain region, where the majority of its proved reserves,
production and long-term growth prospects are located. Its
common stock is listed on the NASDAQ Capital Market System under
the symbol "DPTR."
RESERVE DISCLOSURE
The Company does not plan to include probable reserve estimates
in its filings with the SEC. The Company has provided
internally generated estimates for probable reserves in this
release. The estimates conform to SEC guidelines. They are not
prepared or reviewed by third party engineers. Delta's probable
reserve estimates are determined using strip pricing which it uses
internally for planning and budgeting purposes. The Company's
estimate of probable reserves is provided in this release because
management believes it is useful additional information that is
widely used by the investment community in the valuation,
comparison and analysis of companies.
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, anticipated future operating and
overhead costs, cost control measures, liquidity requirements and
availability of capital, drilling and completion activity,
anticipated impact of new frac designs, expected decreases in
general and administrative expenses and anticipated production for
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 and its working capital needs, the
contraction in 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, 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. 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 info@deltapetro.com.
DELTA PETROLEUM
CORPORATION
|
|
AND SUBSIDIARIES
|
|
CONSOLIDATED BALANCE
SHEETS
|
|
|
|
|
|
|
|
|
|
|
December
31,
|
December
31,
|
|
|
2010
|
2009
|
|
ASSETS
|
(In
thousands, except share data)
|
|
Current assets:
|
|
|
|
Cash and cash
equivalents
|
$15,653
|
$61,918
|
|
Short-term
restricted deposits
|
100,000
|
100,000
|
|
Trade accounts
receivable, net of allowance for doubtful
|
|
|
|
accounts of $2,348 and $100, respectively
|
20,446
|
16,654
|
|
Deposits and
prepaid assets
|
1,720
|
3,103
|
|
Inventories
|
3,446
|
5,588
|
|
Other current
assets
|
5,541
|
5,189
|
|
Total current assets
|
146,806
|
192,452
|
|
|
|
|
|
Property and
equipment:
|
|
|
|
Oil and gas
properties, successful efforts method of accounting:
|
|
|
|
Unproved
|
230,117
|
280,844
|
|
Proved
|
871,986
|
1,379,920
|
|
Drilling and
trucking equipment
|
174,680
|
177,762
|
|
Pipeline and
gathering systems
|
93,558
|
92,064
|
|
Other
|
15,639
|
16,154
|
|
Total property and equipment
|
1,385,980
|
1,946,744
|
|
Less accumulated
depreciation and depletion
|
(517,414)
|
(800,501)
|
|
Net property and equipment
|
868,566
|
1,146,243
|
|
|
|
|
|
Long-term assets:
|
|
|
|
Long-term
restricted deposit
|
-
|
100,000
|
|
Investments in
unconsolidated affiliates
|
3,377
|
7,444
|
|
Deferred financing
costs
|
1,832
|
3,017
|
|
Other long-term
assets
|
3,531
|
8,329
|
|
Total long-term assets
|
8,740
|
118,790
|
|
|
|
|
|
Total assets
|
$1,024,112
|
$1,457,485
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND EQUITY
|
|
|
Current liabilities:
|
|
|
|
Credit facility –
DHS
|
$69,590
|
$83,268
|
|
Installments
payable on property acquisition
|
97,874
|
97,874
|
|
Accounts
payable
|
36,185
|
44,225
|
|
Offshore litigation
payable
|
-
|
13,877
|
|
Other accrued
liabilities
|
14,539
|
13,459
|
|
Derivative
instruments
|
574
|
19,497
|
|
Total current liabilities
|
218,762
|
272,200
|
|
|
|
|
|
Long-term
liabilities:
|
|
|
|
Installments
payable on property acquisition, net of current portion
|
-
|
95,381
|
|
7% Senior
notes
|
149,684
|
149,609
|
|
3 3/4% Senior
convertible notes
|
108,593
|
104,008
|
|
Credit facility -
Delta
|
29,130
|
124,038
|
|
Asset retirement
obligations
|
3,929
|
7,654
|
|
Derivative
instruments
|
2,419
|
7,475
|
|
Total
long-term liabilities
|
293,755
|
488,165
|
|
|
|
|
|
Commitments and
contingencies
|
|
|
|
|
|
|
|
Equity:
|
|
|
|
Preferred stock,
$0.01 par value:
|
|
|
|
authorized
3,000,000 shares, none issued
|
-
|
-
|
|
Common stock, $0.01
par value; authorized 600,000,000 shares,
|
|
|
|
issued 285,138,000
shares at December 31, 2010 and
|
|
|
|
282,548,000 shares
at December 31, 2009
|
2,851
|
2,825
|
|
Additional paid-in
capital
|
1,633,217
|
1,625,035
|
|
Treasury stock at
cost; 33,000 shares at December 31, 2010
|
|
|
|
and 42,000 shares
at December 31, 2009
|
(279)
|
(268)
|
|
Accumulated
deficit
|
(1,121,342)
|
(939,010)
|
|
Total Delta
stockholders' equity
|
514,447
|
688,582
|
|
Non-controlling
interest
|
(2,852)
|
8,538
|
|
Total
equity
|
511,595
|
697,120
|
|
|
|
|
|
Total
liabilities and equity
|
$1,024,112
|
$1,457,485
|
|
|
|
|
DELTA PETROLEUM
CORPORATION
|
|
AND SUBSIDIARIES
|
|
CONSOLIDATED STATEMENT OF
OPERATIONS
|
|
|
Three Months
Ended
|
Twelve
Months Ended
|
|
|
December
31,
|
December
31,
|
|
|
2010
|
2009
|
2010
|
2009
|
|
|
(In
thousands, except per share amounts)
|
|
Revenue:
|
|
|
|
|
|
Oil and gas
sales
|
$19,652
|
$26,007
|
$94,388
|
$82,723
|
|
Contract drilling and
trucking fees
|
17,012
|
4,255
|
53,212
|
13,680
|
|
Gain on offshore
litigation settlement, net of loss on property sales
|
(256)
|
42,746
|
(795)
|
73,800
|
|
Total revenue
|
36,408
|
73,008
|
146,805
|
170,203
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
Lease operating
expense
|
3,662
|
5,281
|
24,566
|
26,439
|
|
Transportation
expense
|
4,016
|
3,403
|
15,211
|
10,057
|
|
Production
taxes
|
(33)
|
(163)
|
3,727
|
3,032
|
|
Exploration
expense
|
385
|
182
|
1,337
|
2,604
|
|
Dry hole costs and
impairments
|
12,713
|
34,110
|
43,572
|
176,871
|
|
Depreciation, depletion,
amortization and accretion – oil and gas
|
12,725
|
18,492
|
58,265
|
81,335
|
|
Drilling and trucking
operating expenses
|
14,195
|
4,877
|
42,248
|
15,293
|
|
Goodwill and drilling
equipment impairments
|
-
|
-
|
-
|
6,508
|
|
Depreciation and
amortization – drilling and trucking
|
4,365
|
5,405
|
19,964
|
22,917
|
|
General and administrative
expense
|
7,758
|
9,867
|
41,130
|
41,414
|
|
Executive severance
expense, net
|
-
|
-
|
(674)
|
3,739
|
|
Total operating expenses
|
59,786
|
81,454
|
249,346
|
390,209
|
|
|
|
|
|
|
|
Operating loss
|
(23,378)
|
(8,446)
|
(102,541)
|
(220,006)
|
|
|
|
|
|
|
|
Other income and
(expense):
|
|
|
|
|
|
Interest expense and
financing costs, net
|
(7,821)
|
(10,674)
|
(37,247)
|
(52,581)
|
|
Other income
(expense)
|
(1,203)
|
(581)
|
(1,409)
|
1,049
|
|
Realized loss on
derivative instruments, net
|
(703)
|
(1,485)
|
(5,835)
|
(1,115)
|
|
Unrealized gain (loss) on
derivative instruments, net
|
(4,093)
|
62
|
23,979
|
(26,972)
|
|
Income (loss) from
unconsolidated affiliates
|
845
|
(12,149)
|
1,738
|
(15,473)
|
|
|
|
|
|
|
|
Total other expense
|
(12,975)
|
(24,827)
|
(18,774)
|
(95,092)
|
|
|
|
|
|
|
|
Loss from continuing operations
before income taxes and
|
|
|
|
|
|
discontinued
operations
|
(36,353)
|
(33,273)
|
(121,315)
|
(315,098)
|
|
|
|
|
|
|
|
Income tax expense
(benefit)
|
(21)
|
268
|
543
|
215
|
|
|
|
|
|
|
|
Loss from continuing
operations
|
(36,332)
|
(33,541)
|
(121,858)
|
(315,313)
|
|
|
|
|
|
|
|
Discontinued
operations:
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from results
of operations and sale of
|
|
|
|
|
|
discontinued
operations, net of tax
|
57
|
(5,253)
|
(72,156)
|
(34,371)
|
|
|
|
|
|
|
|
Net loss
|
(36,275)
|
(38,794)
|
(194,014)
|
(349,684)
|
|
|
|
|
|
|
|
Less net loss attributable
to non-controlling interest
|
2,548
|
4,710
|
11,682
|
20,901
|
|
|
|
|
|
|
|
Net loss attributable to Delta
common stockholders
|
$(33,727)
|
$(34,084)
|
$(182,332)
|
$(328,783)
|
|
|
|
|
|
|
|
Amounts attributable to Delta
common stockholders:
|
|
|
|
|
|
Loss from continuing
operations
|
$(33,784)
|
$(28,831)
|
$(110,176)
|
$(294,412)
|
|
Income (loss) from
discontinued operations, net of tax
|
57
|
(5,253)
|
(72,156)
|
(34,371)
|
|
Net loss
|
$(33,727)
|
$(34,084)
|
$(182,332)
|
$(328,783)
|
|
|
|
|
|
|
|
Basic loss attributable to Delta
common stockholders
|
|
|
|
|
|
per common share:
|
|
|
|
|
|
Loss from continuing
operations
|
$(0.12)
|
$(0.10)
|
$(0.40)
|
$(1.40)
|
|
Discontinued
operations
|
-
|
(0.02)
|
(0.26)
|
(0.16)
|
|
Net loss
|
$(0.12)
|
$(0.12)
|
$(0.66)
|
$(1.56)
|
|
|
|
|
|
|
|
Diluted loss attributable to
Delta common stockholders
|
|
|
|
|
|
per common share:
|
|
|
|
|
|
Loss from continuing
operations
|
$(0.12)
|
$(0.10)
|
$(0.40)
|
$(1.40)
|
|
Discontinued
operations
|
-
|
(0.02)
|
(0.26)
|
(0.16)
|
|
Net loss
|
$(0.12)
|
$(0.12)
|
$(0.66)
|
$(1.56)
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding:
|
|
|
|
|
|
Basic
|
277,394
|
274,878
|
275,042
|
211,033
|
|
Diluted
|
277,394
|
274,878
|
275,042
|
211,033
|
|
|
|
|
|
|
DELTA PETROLEUM
CORPORATION
|
|
RECONCILIATION OF DISCRETIONARY
CASH FLOW AND EBITDAX
|
|
(Unaudited)
|
|
|
|
($ in
thousands)
|
|
|
|
|
|
THREE MONTHS ENDED
|
December
31,
|
December
31,
|
|
|
2010
|
2009
|
|
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
|
$(5,580)
|
$61,596
|
|
Changes in assets and
liabilities
|
9,553
|
3,863
|
|
Less net proceeds from offshore
litigation settlement
|
-
|
(62,534)
|
|
Exploration costs
|
385
|
182
|
|
Discretionary cash
flow*
|
$4,358
|
$3,107
|
|
|
|
|
|
|
|
|
|
TWELVE MONTHS ENDED
|
December
31,
|
December
31,
|
|
|
2010
|
2009
|
|
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
|
$(31,538)
|
$81,144
|
|
Changes in assets and
liabilities
|
38,725
|
3,361
|
|
Less net proceeds from offshore
litigation settlement
|
-
|
(111,235)
|
|
Exploration costs
|
1,337
|
2,604
|
|
Discretionary cash flow
(deficiency)*
|
$8,524
|
$(24,126)
|
|
|
|
|
* 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 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
|
December
31,
|
December
31,
|
|
|
2010
|
2009
|
|
Net loss
|
$(36,275)
|
$(38,795)
|
|
Non-controlling
interest
|
2,548
|
4,710
|
|
Income tax expense
|
46
|
268
|
|
Interest expense and financing
costs, net
|
7,821
|
10,674
|
|
Depletion, depreciation and
amortization
|
17,096
|
31,441
|
|
Gain on offshore litigation
settlement, net of loss on property sales
|
1,017
|
(42,238)
|
|
Gain on sale of discontinued
operations
|
(68)
|
-
|
|
Unrealized (gain) loss on
derivative instruments, net
|
4,093
|
(62)
|
|
Exploration, dry hole and
impairment costs
|
14,098
|
45,323
|
|
EBITDAX**
|
$10,376
|
$11,321
|
|
|
|
|
|
|
|
|
|
THREE MONTHS ENDED
|
December
31,
|
December
31,
|
|
|
2010
|
2009
|
|
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
|
$(5,580)
|
$61,596
|
|
Changes in assets and
liabilities
|
9,553
|
3,863
|
|
Net proceeds from offshore
litigation
|
-
|
(62,534)
|
|
Interest net of financing
costs
|
4,984
|
7,096
|
|
Exploration costs
|
385
|
182
|
|
Impairment of unconsolidated
affiliates
|
-
|
11,032
|
|
Other non-cash items
|
1,034
|
(9,914)
|
|
EBITDAX**
|
$10,376
|
$11,321
|
|
|
|
|
|
|
|
|
|
TWELVE MONTHS ENDED
|
December
31,
|
December
31,
|
|
|
2010
|
2009
|
|
Net loss
|
$(194,014)
|
$(349,684)
|
|
Non-controlling
interest
|
11,682
|
20,901
|
|
Income tax expense
|
610
|
215
|
|
Interest expense and financing
costs, net
|
37,247
|
52,581
|
|
Depletion, depreciation and
amortization
|
92,070
|
131,422
|
|
Gain on offshore litigation
settlement, net of loss on property sales
|
2,341
|
(74,955)
|
|
Gain on sale of discontinued
operations
|
(28,978)
|
-
|
|
Unrealized (gain) loss on
derivative instruments, net
|
(23,979)
|
26,972
|
|
Exploration, dry hole and
impairment costs
|
139,508
|
212,247
|
|
EBITDAX**
|
$36,487
|
$19,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TWELVE MONTHS ENDED
|
December
31,
|
December
31,
|
|
|
2010
|
2009
|
|
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
|
$(31,538)
|
$81,144
|
|
Changes in assets and
liabilities
|
38,725
|
3,361
|
|
Less net proceeds from offshore
litigation settlement
|
-
|
(111,235)
|
|
Interest net of financing
costs
|
23,480
|
33,392
|
|
Exploration costs
|
1,337
|
2,604
|
|
Impairment of unconsolidated
affiliates
|
-
|
14,063
|
|
Other non-cash items
|
4,483
|
(3,630)
|
|
EBITDAX**
|
$36,487
|
$19,699
|
|
|
|
|
**EBITDAX represents net income (loss) before non-controlling
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, gain on discontinued
operations, 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 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