Clayton Williams Energy, Inc. (the “Company”) (NASDAQ:CWEI)
today reported its financial results for the quarter and year ended
December 31, 2011, along with information about its proved oil and
gas reserves as of December 31, 2011.
Highlights
- 2011 Cash Flow from Operations of
$280 Million, up 34%
- Total Proved Reserves of 64.3
Million BOE, up 26%
- 77% Oil and NGL and 61% Proved
Developed
- 384% of 2011 Production Replaced by
Reserve Additions
Financial Results for Fiscal Year 2011
Net income attributable to Company stockholders for fiscal 2011
was $93.8 million, or $7.71 per share, as compared to net income of
$36.9 million, or $3.04 per share, for fiscal 2010. Cash flow from
operations for 2011 was $280 million as compared to $208.3
million for 2010. The key factors affecting the comparability of
the two years were:
- Oil and gas sales increased $78.9
million in 2011 compared to 2010. Price variances accounted for
$63.8 million of the increase and production variances accounted
for the remaining $15.1 million. Average realized oil prices were
$92.43 per barrel in 2011 versus $76.44 per barrel in 2010, and
average realized gas prices were $5.30 per Mcf in 2011 versus $5.17
per Mcf in 2010. Although combined oil and gas production for 2011
remained relatively constant on a barrel of oil equivalent (“BOE”)
basis compared to 2010, oil and NGL production accounted for 74% of
total production in 2011 versus 67% in 2010. Oil production
increased 10% compared to 2010, while gas production declined 20%.
On a comparable basis, after giving effect to the sale of
properties in North Louisiana in June 2010, oil and gas production
in 2011 on a BOE basis was 4% higher than 2010.
- Gain on derivatives for 2011 was $47
million ($42.5 million gain on settled contracts and a $4.5 million
non-cash mark-to-market gain) versus a gain in 2010 of $0.7 million
($9.9 million realized gain on settled contracts and a $9.2 million
non-cash mark-to-market loss). See accompanying tables for
additional information about the Company’s accounting for
derivatives.
- Production costs increased 22% to
$101.1 million in 2011 from $83.1 million in 2010. Production costs
excluding production taxes, referred to as lifting costs, accounted
for $14.7 million of the increase due to a combination of more
producing wells and rising costs of field services, and production
taxes accounted for the remaining $3.3 million of the increase due
to higher oil and gas sales.
- Exploration expenses related to
abandonments and impairments were $20.8 million in 2011 compared to
$9.1 million in 2010. The expense for 2011 includes a charge of
$11.8 million for the abandonment of the Hamill Foundation #1, an
exploratory well in Leon County, Texas targeting the Deep Bossier
gas formation, and $5 million of leasehold impairments related to
the abandonment of the well. Based on the results of a recent
stimulation procedure, the Company determined that the well was
uneconomic.
- Interest expense increased to $32.9
million in 2011 from $24.4 million in 2010 due primarily to the
increase in the total aggregate principal amount of the Senior
Notes from $225 million to $350 million. The Company also recorded
a $5.5 million loss on early extinguishment of long-term debt
related to the redemption of the 2013 Senior Notes in 2011.
- Net gain on sales of assets and
impairment of inventory was a $14.1 million gain in 2011 compared
to a gain of $1.9 million in 2010. In 2011, the Company sold two
2,000 horsepower drilling rigs and related equipment for a gain of
$13.2 million.
- General and administrative expenses for
2011 were $41.6 million versus $35.6 million in 2010. Non-cash
employee compensation related to non-equity incentive plans totaled
$12.9 million in 2011 versus $13.9 million in 2010. Excluding
non-cash employee compensation, general and administrative expenses
increased to $28.7 million in 2011 versus $21.7 million in 2010 due
to a combination of higher personnel costs and costs associated
with the proposed merger with affiliated partnerships.
Financial Results for the Fourth Quarter of 2011
Net loss attributable to Company stockholders for the fourth
quarter of 2011 (“4Q11”) was $15.5 million, or $1.27 per share, as
compared to a net loss of $5.3 million, or $.44 per share, for the
fourth quarter of 2010 (“4Q10”). Cash flow from operations for 4Q11
was $104.8 million as compared to $54.1 million for 4Q10. The
key factors affecting the comparability of the two quarters
were:
- Oil and gas sales increased $16.3
million in 4Q11 versus 4Q10. Price variances accounted for $9.8
million of the increase while production variances accounted for
the remaining $6.5 million. Average realized oil prices were $91.70
per barrel in 4Q11 versus $82.07 per barrel in 4Q10, and average
realized gas prices were $4.91 per Mcf in 4Q11 versus $5.02 per Mcf
in 4Q10. Combined oil and gas production for 4Q11 was 5% higher on
a BOE basis than in 4Q10. Oil production increased 11% compared to
4Q10, while gas production declined 3%.
- Production costs increased 22% to $25.9
million in 4Q11 from $21.1 million in 4Q10. Production costs
excluding production taxes, referred to as lifting costs, accounted
for $4.1 million of the increase due to a combination of more
producing wells and rising costs of field services, and production
taxes accounted for the remaining $0.7 million of the increase due
to higher oil and gas sales.
- Loss on derivatives for 4Q11 was $27.1
million ($77.5 million non-cash mark-to-market loss offset in part
by a $50.4 million realized gain on settled contracts) versus a
loss in 4Q10 of $26.6 million ($27 million non-cash mark-to-market
loss net of a $0.4 million realized gain on settled contracts). See
accompanying tables for additional information about the Company’s
accounting for derivatives.
- Exploration expenses related to
abandonments and impairments were $18.5 million in 4Q11 compared to
$2.9 million in 4Q10. The expense for 4Q11 includes charges related
to the previously discussed abandonment of the Hamill Foundation
#1.
- General and administrative expenses for
4Q11 were $18.9 million versus $12.8 million in 4Q10. Non-cash
employee compensation related to non-equity incentive plans totaled
$6.8 million in 4Q11 versus $5.8 million in 4Q10. Excluding
non-cash employee compensation, general and administrative expenses
increased to $12.1 million in 4Q11 versus $7 million in 4Q10 due to
a combination of higher personnel costs and costs associated with
the proposed merger with affiliated partnerships.
Reserves
The Company reported that its total estimated proved oil and gas
reserves as of December 31, 2011 were 64.3 million barrels of oil
equivalent (“MMBOE”), consisting of 49.5 million barrels of oil and
NGL and 88.9 Bcf of natural gas. On a BOE basis, oil and NGL
comprised 77% of total proved reserves at year-end 2011 versus 74%
at year-end 2010. Proved developed reserves at year-end 2011 were
39.3 MMBOE, or 61% of total proved reserves, as compared to 34.5
MMBOE, or 68% of total proved reserves, at year-end 2010. The
present value of estimated future net cash flows from total proved
reserves, before deductions for estimated future income taxes and
asset retirement obligations, discounted at 10%, (referred to as
“PV-10 Value”) totaled $1.4 billion for year-end 2011 as compared
to $992 million for year-end 2010. For a reconciliation of PV-10
Value (a non-GAAP measure) to standardized measure of discounted
future net cash flows, see accompanying tables.
The following table summarizes the changes in total proved
reserves during 2011 on an MMBOE basis.
MMBOE Total proved reserves,
December 31, 2010 51.1 Extensions and discoveries 20.9
Revisions (2.1 ) Sales of reserves (0.2 ) Production (5.4 )
Total proved reserves, December 31, 2011 64.3
The Company replaced 384% of its 2011 oil and gas production
through extensions and discoveries. Most of the 20.9 MMBOE of
reserve additions in 2011 were derived from growth through the
drill bit in the Permian Basin drilling Wolfberry and Wolfbone
wells. Oil and NGL accounted for 84% of the 2011 reserve
additions.
Revisions of prior year estimates resulted from a combination of
4.9 MMBOE of upward revisions related to the effects of higher
commodity prices on economic limits of long-life properties and
downward revisions of 7 MMBOE related primarily to changes in
estimates based on well performance.
SEC guidelines require that the Company’s estimated proved
reserves and related PV-10 Values be determined using benchmark
commodity prices equal to the unweighted arithmetic average of the
first-day-of-the-month price for the 12-month period prior to the
effective date of each reserve estimate. The benchmark averages for
2011 were $96.19 per barrel of oil and $4.12 per MMBtu of natural
gas, as compared to $79.43 per barrel and $4.38 per MMBtu for 2010.
These benchmark prices were further adjusted for quality, energy
content, transportation fees and other price differentials specific
to the Company’s properties, resulting in an average adjusted price
over the remaining life of the proved reserves of $87.61 per barrel
of oil and NGL and $5.31 per Mcf of natural gas for year-end 2011,
as compared to $72.36 per barrel and $5.44 per Mcf for year-end
2010.
Commodity prices have a significant impact on proved oil and gas
reserves and their related PV-10 Value. Using strip prices as of
December 31, 2011 instead of the SEC mandated benchmark prices, the
Company’s PV-10 Value for year-end 2011 would have been $1.3
billion.
Clayton Williams Energy, Inc. is an independent energy company
located in Midland, Texas.
This release contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and Section
21E of the Securities Exchange Act of 1934. All statements, other
than statements of historical or current facts, that address
activities, events, outcomes and other matters that we plan,
expect, intend, assume, believe, budget, predict, forecast,
project, estimate or anticipate (and other similar expressions)
will, should or may occur in the future are forward-looking
statements. These forward-looking statements are based on
management’s current belief, based on currently available
information, as to the outcome and timing of future events. The
Company cautions that its future natural gas and liquids
production, revenues, cash flows, liquidity, plans for future
operations, expenses, outlook for oil and natural gas prices,
timing of capital expenditures and other forward-looking statements
are subject to all of the risks and uncertainties, many of which
are beyond our control, incident to the exploration for and
development, production and marketing of oil and gas.
These risks include, but are not limited to, the possibility of
unsuccessful exploration and development drilling activities, our
ability to replace and sustain production, commodity price
volatility, domestic and worldwide economic conditions, the
availability of capital on economic terms to fund our capital
expenditures and acquisitions, our level of indebtedness, the
impact of the current economic recession on our business
operations, financial condition and ability to raise capital,
declines in the value of our oil and gas properties resulting in a
decrease in our borrowing base under our credit facility and
impairments, the ability of financial counterparties to perform or
fulfill their obligations under existing agreements, the
uncertainty inherent in estimating proved oil and gas reserves and
in projecting future rates of production and timing of development
expenditures, drilling and other operating risks, lack of
availability of goods and services, regulatory and environmental
risks associated with drilling and production activities, the
adverse effects of changes in applicable tax, environmental and
other regulatory legislation, and other risks and uncertainties are
described in the Company's filings with the Securities and Exchange
Commission. The Company undertakes no obligation to publicly update
or revise any forward-looking statements.
CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED
STATEMENTS OF OPERATIONS (Unaudited) (In thousands,
except per share)
Three Months Ended Year Ended December 31,
December 31, 2011 2010
2011 2010 REVENUES
Oil and gas sales $ 104,728 $ 88,382 $ 405,216 $ 326,320 Natural
gas services 300 279 1,408 1,631 Drilling rig services 446 - 4,060
- Gain on sales of assets 1,174 424
15,744 3,680 Total revenues
106,648 89,085 426,428
331,631 COSTS AND EXPENSES Production 25,862 21,134
101,099 83,146 Exploration: Abandonments and impairments
18,533
2,941
20,840
9,074 Seismic and other 76 2,051 5,363 6,046 Natural gas services
258 258 1,039 1,209 Drilling rig services 686 (6 ) 5,064 1,198
Depreciation, depletion and amortization 29,893 24,873 104,880
101,145 Impairment of property and equipment 896 - 10,355 11,908
Accretion of asset retirement obligations 680 670 2,757 2,623
General and administrative 18,882 12,802 41,560 35,588 Loss on
sales of assets and impairment of inventory 1,249
227 1,666 1,750 Total
costs and expenses
97,015
64,950
294,623
253,687 Operating income
9,633
24,135
131,805
77,944 OTHER INCOME (EXPENSE)
Interest expense (8,615 ) (6,009 ) (32,919 ) (24,402 ) Loss on
early extinguishment of long-term debt - - (5,501 ) - Gain (loss)
on derivatives (27,101 ) (26,567 ) 47,027 722 Other 2,039 492 5,553
3,308 Total other income (expense)
(33,677 ) (32,084 ) 14,160
(20,372 ) Income (loss) before income taxes
(24,044
) (7,949 )
145,965
57,572 Income tax (expense) benefit
8,551
2,626
(52,142
) (20,634 ) NET INCOME (LOSS) $
(15,493
) $ (5,323 ) $
93,823
$ 36,938 Net income (loss) per common
share: Basic $
(1.27
) $
(0.44
) $
7.72
$ 3.04 Diluted $
(1.27
) $ (0.44 ) $
7.71
$ 3.04 Weighted average common shares
outstanding: Basic 12,163 12,153
12,161 12,148 Diluted 12,163
12,153 12,162 12,148
CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED
BALANCE SHEETS (In thousands)
ASSETS December 31, December 31,
2011 2010 (Unaudited)
CURRENT ASSETS Cash and cash equivalents $ 17,525 $ 8,720 Accounts
receivable: Oil and gas sales 41,282 35,361 Joint interest and
other, net 14,517 9,893 Affiliates 990 796 Inventory 44,868 39,218
Deferred income taxes 8,948 5,074 Assets held for sale - 8,762
Prepaids and other 14,813 5,997
142,943 113,821 PROPERTY AND EQUIPMENT Oil and
gas properties, successful efforts method
2,103,085
1,707,252 Natural gas gathering and processing systems 26,040
18,153 Contract drilling equipment 75,956 58,486 Other
19,134 17,425
2,224,215
1,801,316 Less accumulated depreciation, depletion and amortization
(1,156,664 ) (1,034,227 ) Property and equipment, net
1,067,551
767,089 OTHER ASSETS Debt issue costs,
net 11,644 8,323 Other 4,133 1,684
15,777 10,007 $
1,226,271
$ 890,917
LIABILITIES AND STOCKHOLDERS'
EQUITY CURRENT LIABILITIES Accounts payable: Trade $
98,645 $ 74,123 Oil and gas sales 37,409 28,920 Affiliates 1,501
1,251 Fair value of derivatives 5,633 7,224 Accrued liabilities and
other 13,042 22,202 156,230
133,720 NON-CURRENT LIABILITIES
Long-term debt 529,535 385,000 Deferred income taxes
134,209
78,035 Fair value of derivatives 494 3,409 Asset retirement
obligations 40,794 40,444 Other
21,508
857
726,540
507,745 STOCKHOLDERS' EQUITY Preferred
stock, par value $.10 per share - - Common stock, par value $.10
per share 1,216 1,215 Additional paid-in capital 152,515 152,290
Retained earnings
189,770
95,947 Total stockholders' equity
343,501
249,452 $
1,226,271
$ 890,917
CLAYTON WILLIAMS ENERGY,
INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) (In thousands)
Three Months Ended Year Ended
December 31, December 31, 2011
2010 2011
2010 CASH FLOWS FROM OPERATING
ACTIVITIES Net income (loss) $
(15,493
) $ (5,323 ) $
93,823
$ 36,938 Adjustments to reconcile net income (loss) to cash
provided by operating activities: Depreciation, depletion and
amortization 29,893 24,873 104,880 101,145 Impairment of property
and equipment 896 - 10,355 11,908 Exploration costs
18,533
2,941
20,840
9,074 (Gain) loss on sales of assets and impairment of inventory,
net 75 (197 ) (14,078 ) (1,930 ) Deferred income tax expense
(benefit)
(8,143
) (3,001 )
52,550
20,259 Non-cash employee compensation 6,762 5,832 12,866 13,898
Unrealized (gain) loss on derivatives 77,523 27,027 (4,506 ) 9,153
Accretion of asset retirement obligations 680 670 2,757 2,623
Amortization of debt issue costs 719 474 2,342 1,648 Loss on early
extinguishment of long-term debt - - 5,501 - Changes in
operating working capital: Accounts receivable (11,507 ) (11,779 )
(10,739 ) (10,036 ) Accounts payable 12,007 13,897 7,551 19,144
Other (7,185 ) (1,331 ) (4,095 ) (5,573
) Net cash provided by operating activities 104,760
54,083 280,047 208,251
CASH FLOWS FROM INVESTING ACTIVITIES Additions to property
and equipment (130,539 ) (77,014 ) (413,013 ) (285,655 ) Proceeds
from sales of assets 1,436 1,546 13,902 77,216 Change in equipment
inventory (8,149 ) 7,713 (5,305 ) 4,638 Other (364 )
149 (497 ) 18 Net cash used in
investing activities (137,616 ) (67,606 )
(404,913 ) (203,783 ) CASH FLOWS FROM FINANCING
ACTIVITIES Proceeds from long-term debt 103,000 - 547,710 -
Repayments of long-term debt (88,656 ) - (411,500 ) (10,000 )
Premium on early extinguishment of long-term debt - - (2,765 ) -
Proceeds from exercise of stock options 13 239
226 239 Net cash provided by
(used in) financing activities 14,357 239
133,671 (9,761 ) NET INCREASE
(DECREASE) IN CASH AND CASH EQUIVALENTS (18,499 ) (13,284 ) 8,805
(5,293 ) CASH AND CASH EQUIVALENTS Beginning of period
36,024 22,004 8,720 14,013 End of
period $ 17,525 $ 8,720 $ 17,525 $ 8,720
CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF EBITDAX (Unaudited) (In
thousands) EBITDAX is presented as a supplemental
non-GAAP financial measure because of its wide acceptance by
financial analysts, investors, debt holders, banks, rating agencies
and other financial statement users as an indication of an entity's
ability to meet its debt service obligations and to internally fund
its exploration and development activities. The Company
defines EBITDAX as net income (loss) before interest expense,
income taxes, exploration costs, net (gain) loss on sales of assets
and impairment of inventory, loss on early extinguishment of debt
and all non-cash items in the Company's statements of operations,
including depreciation, depletion and amortization, impairment of
property and equipment, accretion of asset retirement obligations,
certain employee compensation and changes in fair value of
derivatives. EBITDAX is not an alternative to net income (loss) or
cash flow from operating activities, or any other measure of
financial performance presented in conformity with GAAP. The
following table reconciles net income (loss) to EBITDAX:
Three Months Ended Year
Ended December 31, December 31,
2011 2010
2011 2010 Net
income (loss) $
(15,493
) $ (5,323 ) $
93,823
$ 36,938 Interest expense 8,615 6,009 32,919 24,402 Income tax
(benefit) expense
(8,551
) (2,626 )
52,142
20,634 Exploration: Abandonments and impairments
18,533
2,941
20,840
9,074 Seismic and other 76 2,051 5,363 6,046 Net (gain) loss on
sales of assets and impairment of inventory 75 (197 ) (14,078 )
(1,930 ) Loss on early extinguishment of long-term debt - - 5,501 -
Depreciation, depletion and amortization 29,893 24,873 104,880
101,145 Impairment of property and equipment 896 - 10,355 11,908
Accretion of asset retirement obligations 680 670 2,757 2,623
Non-cash employee compensation 6,762 5,832 12,866 13,898 Non-cash
changes in fair value of derivatives 77,523 27,027 (4,506 ) 9,153
$ 119,009 $ 61,257 $
322,862 $ 233,891
CLAYTON WILLIAMS
ENERGY, INC. SUMMARY PRODUCTION AND PRICE DATA
(Unaudited)
Three Months Ended Year Ended December 31,
December 31, 2011 2010
2011 2010 Oil and Gas
Production Data: Oil (MBbls) 997 900 3,727 3,375 Gas (MMcf)
2,025 2,085 8,594 10,750 Natural gas liquids (MBbls) 58 85 275 292
Total (MBOE) 1,393 1,333 5,434 5,459
Average Realized
Prices (a): Oil ($/Bbl) $ 91.70 $ 82.07 $ 92.43 $ 76.44
Gas ($/Mcf) $ 4.91 $ 5.02 $ 5.30 $ 5.17
Natural gas liquids ($/Bbl) $ 54.76 $ 47.56 $ 53.37 $ 42.47
Gain (Loss) on Settled Derivative
Contracts (a):
($ in thousands, except per unit) Oil: Net realized gain (loss) $
45,343 $ (4,587 ) $ 23,354 $ (7,685 ) Per unit produced ($/Bbl) $
45.48 $ (5.10 ) $ 6.27 $ (2.28 ) Gas: Net realized gain $
5,079 $ 5,047 $ 19,167 $ 17,560 Per unit produced ($/Mcf) $ 2.51 $
2.42 $ 2.23 $ 1.63
Average Daily Production: Oil
(Bbls): Permian Basin Area: West Texas Andrews 2,696 2,390 2,643
1,806 West Texas Reeves 636 - 202 - West Texas Other 3,525 3,583
3,417 3,795 Austin Chalk/ Eagle Ford Shale 3,640 3,292 3,477 2,944
South Louisiana 271 447 399 559 Other 69 71
73 143 (b) Total 10,837 9,783
10,211 9,247 Natural Gas (Mcf):
Permian Basin Area: West Texas Andrews 446 1,261 1,038 834 West
Texas Other 9,763 12,305 11,266 12,834 Giddings Area: Austin Chalk/
Eagle Ford Shale 2,477 2,049 2,142 2,179 Cotton Valley Reef Complex
3,243 3,092 3,021 3,599 South Louisiana 5,314 3,010 4,970 5,265
Other 768 946 1,108 4,741
(b) Total 22,011 22,663 23,545
29,452 Natural Gas Liquids (Bbls): Permian Basin
Area: West Texas Andrews 118 406 237 240 West Texas Other 225 193
224 200 Austin Chalk/ Eagle Ford Shale 224 231 212 237 South
Louisiana 42 69 50 89 Other 21 25 30
34 (b) Total 630 924 753
800
Three Months Ended Year
Ended December 31, December 31,
2011 2010 2011
2010 Oil and Gas Costs ($/BOE
Produced): Production costs $ 18.57 $ 15.85 $ 18.60 $ 15.23
Production costs (excluding production taxes) $ 14.84 $ 12.42 $
14.79 $ 12.03 Oil and gas depletion $ 20.76 $ 18.52 $ 18.72 $ 18.09
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation $ 12,120 $ 6,970 $ 28,694
$ 21,690 Non-cash employee compensation (c) 6,762
5,832 12,866 13,898 Total $ 18,882 $
12,802 $ 41,560 $ 35,588 (a) Hedging
gains/losses are only included in the determination of the
Company's average realized prices if the underlying derivative
contracts are designated as cash flow hedges under applicable
accounting standards. The Company did not designate any of its 2011
or 2010 derivative contracts as cash flow hedges. This means that
the Company's derivatives for 2011 and 2010 have been
marked-to-market through its statement of operations as other
income/expense instead of through accumulated other comprehensive
income on the Company's balance sheet. This also means that all
realized gains/losses on these derivatives are reported in other
income/expense instead of as a component of oil and gas sales.
(b) Other for 2010 includes production attributable to sold
properties in North Louisiana as follows: Twelve months: Oil 71,
Gas 3,581, NGL 8. (c) Non-cash employee compensation relates
to the Company's non-equity award plans.
CLAYTON
WILLIAMS ENERGY, INC. SUMMARY OF OPEN COMMODITY
DERIVATIVES (Unaudited)
The following summarizes information concerning the
Company’s net positions in open commodity derivatives applicable to
periods subsequent to December 31, 2011.
Oil
Swaps: Bbls (a) Price Production
Period: 1st Quarter 2012 444,000 $ 95.70 2nd Quarter 2012 410,000 $
95.70 3rd Quarter 2012 384,000 $ 95.70 4th Quarter 2012 362,000 $
95.70 1,600,000 (a) Excludes oil hedges covering
393,863 barrels of oil for production months from January 2012
through May 2016 at a price of $91.15 per barrel. These hedges
cover production related to a volumetric production payment to be
granted in connection with the proposed acquisition by our wholly
owned subsidiary, Southwest Royalties, Inc., of 24 limited
partnerships of which it is the general partner.
CLAYTON WILLIAMS ENERGY, INC.PROVED
RESERVES(Unaudited)
The following table sets forth our estimated quantities of
proved reserves as of December 31, 2011 and 2010, all of which are
located in the United States.
Proved Reserves
Natural Total Oil Oil (a) Gas
Equivalents (b) Reserve Category
(MBbls) (MMcf) (MBOE) December 31,
2011: Developed 28,962 61,811 39,264 Undeveloped 20,574 27,065
25,085 Total Proved 49,536 88,876 64,349
December
31, 2010: Developed 24,570 59,409 34,472 Undeveloped 13,245
20,088 16,593 Total Proved 37,815 79,497 51,065 (a)
Oil reserves include crude oil, condensate and natural gas liquids
("NGL"). (b) Natural gas reserves have been converted to oil
equivalents at the rate of six Mcf to one barrel of oil.
The present value of future net cash flows from proved reserves,
before deductions for estimated future income taxes and asset
retirement obligations, discounted at 10% ("PV-10 Value"), totaled
$1.4 billion at December 31, 2011, as compared to $992 million at
December 31, 2010. Average adjusted commodity prices used at
December 31, 2011 and December 31, 2010 were based on the 12-month
weighted average of the first-day-of-the-month prices from January
through December of the respective years, which for the Company
averaged $87.61 per barrel of oil and NGL and $5.31 per Mcf of
natural gas for 2011 and $72.36 per barrel of oil and NGL and $5.44
per Mcf of natural gas for 2010.
PV-10 Value is a non-GAAP financial measure that we believe is
useful as a supplemental disclosure to the standardized measure of
discounted future net cash flows, a GAAP financial measure. While
the standardized measure of discounted future net cash flows is
dependent on the unique tax situation of each entity, PV-10 Value
is based on prices and discount factors that are consistent for all
entities and can be used within the industry and by securities
analysts to evaluate proved reserves on a more comparable basis.
The following table reconciles PV-10 Value to standardized measure
of discounted future net cash flows.
As of December 31, 2011
2010 (In thousands) PV-10
Value, a non-GAAP financial measure $ 1,375,460 $ 991,748
Less present value, discounted at 10%, of: Estimated asset
retirement obligations (29,520 ) (30,445 ) Estimated future income
taxes (407,427 ) (276,865 ) Standardized measure of
discounted future net cash flows, a GAAP financial
measure $ 938,513 $ 684,438
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