Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/ | nfx8k-02162010.htm |
| EX-99.1 - RESERVES PRESS RELEASE - NEWFIELD EXPLORATION CO /DE/ | nfx8k-02162010ex991.htm |
| EX-99.3 - @NFX PUBLICATION - NEWFIELD EXPLORATION CO /DE/ | nfx8k-02162010ex993.htm |
Exhibit
99.2
Newfield
Reports Fourth Quarter and Full-Year 2009
Financial
and Operating Results
FOR
IMMEDIATE RELEASE
Houston –
February 16, 2010 –
Newfield Exploration Company (NYSE: NFX) today reported its unaudited
fourth quarter and full-year 2009 financial and operating results. The press
releases reporting our results and our year-end 2009 reserves are available in
the investor relations section of our website at http://www.newfield.com. Newfield will be hosting a
conference call at 8:30 a.m. (CST) on February 17. To participate in the call,
dial 719-457-2088 or listen through the investor relations section of our
website at http://www.newfield.com.
Fourth Quarter
2009
For the
fourth quarter of 2009, Newfield recorded net income of $113 million, or $0.86
per diluted share (all per share amounts are on a diluted basis). Net income
includes the effect of a net unrealized loss on commodity derivatives of $112
million ($73 million after-tax). Without the effect of this item, net income for
the fourth quarter of 2009 would have been $186 million, or $1.40 per
share.
Revenues
in the fourth quarter of 2009 were $414 million. Net cash provided by operating
activities before changes in operating assets and liabilities was $442 million.
See “Explanation and
Reconciliation of Non-GAAP Financial Measures” found after the financial
statements in this release.
Newfield’s
production in the fourth quarter of 2009 was 65 Bcfe. Natural gas production in
the fourth quarter of 2009 was 46 Bcf, an average of nearly 500 MMcf/d.
Newfield’s oil liftings in the fourth quarter of 2009 were 3.1 MMBbls, or an
average of approximately 34,200 BOPD. Capital expenditures in the fourth quarter
of 2009 were approximately $478 million.
Full-Year
2009
For 2009,
Newfield recorded a net loss of $542 million, or $4.18 per diluted share. The
loss includes the impact of the following items:
|
·
|
a
$1.3 billion ($854 million after-tax), or $6.49 per share, reduction in
the carrying value of oil and gas properties due to significantly lower
gas prices at the end of the first quarter of 2009 compared to year end
2008. This non-cash adjustment resulted from the application of full cost
accounting rules. (Using the quarter-end natural gas price of $3.63 per
MMBtu, the Company’s total estimated proved reserves were negatively
impacted by approximately 400 Bcfe. The revision was primarily related to
proved undeveloped reserves in the Mid-Continent and Rocky Mountain
regions); and
|
|
·
|
a
net unrealized loss on commodity derivatives of $604 million ($387 million
after-tax), or $2.94 per share; and
|
|
·
|
recognition
of a $24 million tax benefit, or $0.18 per share, associated with deferred
tax assets in Malaysia.
|
Without
the effect of these items, the Company would have reported net income in 2009 of
$676 million, or $5.13 per share.
1
Revenues
for 2009 were $1.3 billion. Net cash provided by operating activities before
changes in operating assets and liabilities was $1.7 billion. See “Explanation and Reconciliation of
Non-GAAP Financial Measures” found after the financial statements in this
release.
Newfield’s
production for the full year of 2009 was 257 Bcfe, an increase of 9% over 2008
production volumes. Capital expenditures for 2009 were $1.4
billion.
Highlights
|
·
|
2009 Proved Reserves
Increase 23% over prior year – Newfield’s proved reserves at
year-end 2009 were 3.6 Tcfe. The Company added 1.3 Tcfe of new reserves,
of which about half were related to recent changes in Securities and
Exchange Commission (SEC) reserve reporting rules expanding proved
undeveloped reserve locations beyond one offset. The Company replaced
approximately 250% of its 2009 production with the addition of new
reserves (excluding the impact of the new SEC rules). Approximately 53% of
the Company’s proved reserves were proved developed and 72% were natural
gas.
|
Proved reserves in Newfield’s two
largest divisions –
the Mid-Continent and
Rocky Mountains – increased 34% and represent more than 80% of the Company’s
total proved reserves. The
Company’s proved reserve life index is approximately 14 years, reflecting
continued growth in longer-lived resource plays. A separate release
was issued today with complete information on proved reserves and capital
investments in 2009.
|
·
|
Company Adds
>500,000 Net Acres in Resource Plays – Over the last six months,
the Company added more than a half-million acres in developing resource
plays.
|
|
o
|
TXCO Resources – On February 11,
2010, Newfield purchased a package of assets from TXCO Resources, Inc. for
$215 million. Newfield now owns interests in 300,000 net acres in the
Maverick Basin of southwest Texas with multiple geologic targets,
including the Eagle Ford and Pearsall Shale plays. Newfield expects to
drill about 25 wells on the acreage in
2010.
|
|
o
|
Blackfeet Nation Venture
– In
late 2009, Newfield reached an agreement with the Blackfeet Nation, adding
approximately 156,000 net acres in the Southern Alberta Basin. Including
its existing position, Newfield now owns interests in 221,000 net acres in
Glacier County, Montana. The area is geologically similar to the Williston
Basin and is prospective in the oil bearing Bakken, Three Forks and
Lodgepole formations. Newfield expects to drill up to 10 operated
exploratory wells on the acreage, with the first well expected to spud in
April 2010.
|
|
o
|
Marcellus Shale Entry –
In October 2009, Newfield signed a joint exploration agreement with Hess
Corporation and today owns an
interest in approximately 35,000 net acres in Susquehanna and Wayne
Counties, Pennsylvania. Newfield expects to drill 6-10 assessment wells on
the acreage, beginning in mid-2010.
|
|
·
|
Mid-Continent
Production Grew 18% in 2009; Expected to Grow 20% in 2010 – Gross
production from the Mid-Continent continues to grow and is currently more
than 500 MMcfe/d, or approximately 320 MMcfe/d net. The Company’s major
plays in the division are the Granite Wash and the Woodford
Shale.
|
|
o
|
Continued Success in
Granite Wash Horizontal Drilling Program, First 12 Wells Average Initial
Production of 20 MMcfe/d – Newfield continues to run four operated
rigs in the Granite Wash. All of the rigs are currently drilling in
Wheeler County, Texas. Newfield has an approximate 75% working interest in
Stiles Ranch, the Company’s largest producing asset in the play. Newfield
expects to drill about 20 wells in the play in 2010 and to test 4-6
additional horizons within the Granite Wash section. The Company owns
interests in approximately 40,000 net acres in the play.
|
2
In
mid-2009, Newfield announced that its first seven horizontal wells in Stiles
Ranch had an average gross initial production rate of 22 MMcfe/d. In late
2009/early 2010, Newfield completed six additional horizontal test wells and the
results are listed below. The average initial production rate of the first 12
horizontal wells in the Granite Wash play is 20 MMcfe/d (gross). Our 13th well
recently commenced production at 13.8 MMcfe/d and the rate continues to
increase. The six recent wells below were completed in the dry gas Atoka
formation.
|
Well
Name
|
IP
Rate
(MMcfe/d)
|
Lateral
Length
|
Working
Interest
|
|
D
Britt 4-4H
|
11.4
|
4,500’
|
84%
|
|
D
Britt 4-5H
|
14.8
|
4,700’
|
83%
|
|
Britt
8-4H
|
17.2
|
4,300’
|
66%
|
|
Britt
8-5H
|
20.0
|
4,200’
|
65%
|
|
Britt
7-9H
|
22.7
|
4,500’
|
51%
|
|
Britt
8-6H*
|
13.8
|
4,300’
|
66%
|
*commenced
production this week and rate continues to increase following recent fracture
stimulation
|
o
|
Woodford Shale
– Production recently reached a record of 329 MMcfe/d gross operated (191
MMcfe/d net) and is benefiting from the recent completion of wells drilled
in late 2009. The Company plans to run 6-8 operated rigs in the Woodford
in 2010 and to drill approximately 50 horizontal wells. The Woodford is
expected to grow about 25% in 2010.
|
|
o
|
Focus on
Super-Extended Laterals (SXLs) in 2010 – The Company expects that
about one-third of its 2010 wells in the Woodford will be SXLs (lateral
lengths greater than 5,000’). Newfield expects that its average Woodford
lateral length in 2010 will be approximately 6,000’, up from approximately
5,000’ in 2009 and 2006-07 average of less than
2,500’.
|
To date,
the Company has drilled 11 SXLs with an average lateral length of nearly 9,000’.
As previously reported, the first five SXL wells had average initial production
rates of approximately 10 MMcfe/d gross. The remainder of the SXLs (6) is in
various stages of completion.
|
·
|
Company Expects
Monument Butte Production to Grow 15% in 2010 – With an increase to
five operated rigs, Newfield expects that its Monument Butte oil
production will grow 15% in 2010. Located in the Uinta Basin of Utah, this
is the Company’s largest oil asset. Gross oil production from Monument
Butte is about 17,000 BOPD. The Monument Butte field area covers
approximately 180,000 net acres (including 63,000 net Ute Tribal acres).
The Company expects to drill approximately 275 wells in
2010.
|
|
o
|
Recent Success on Ute
Tribal Acreage Contributing to Monument Butte Growth – Over the
last year, Newfield has drilled 75 wells on Ute Tribal acreage, located
north and adjacent to Monument Butte. Two of the Company’s five operated
rigs are running on the Ute Tribal acreage where recent drilling has
encountered thicker Green River formations than previously estimated.
Newfield’s interest on the Ute Tribal acreage is approximately 70%.
Several of the recent completions are significant “step outs” from
existing development areas and initial production rates have ranged from
100 – 1,500 BOPD (gross). There are more than 1,300 producing wells in the
Monument Butte field. Newfield has drilled more than 900 wells since the
field was acquired in 2004. The average initial gross production rate for
a typical Monument Butte well has ranged from 65 – 80
BOPD.
|
|
·
|
Three Operated Rigs
Planned for 2010 Williston Basin Program – Newfield expects to run
three operated rigs in the Williston Basin throughout 2010. Newfield has
approximately 150,000 net acres in prospective development areas, located
primarily on the Nesson Anticline and west of the Nesson. In addition,
Newfield owns interest in approximately 54,000 net acres in the Elm Coulee
field. Newfield has drilled 14 successful oil wells in the North Dakota
portion of the Williston Basin since entering the region in late 2007. The
planned 2010 program will consist of development drilling along the Nesson
(Westberg and Lost Bear areas) as well as continued assessment of areas
west of the Nesson. Recent significant drilling results
include:
|
3
|
Well
Name
|
IP
Rate
(BOEPD)
|
Lateral
Length
|
Working
Interest
|
|
Clear
Creek State 1-36H
|
1,300
|
3,932’
|
50%
|
|
Arkadios
1-18H
|
1,686
|
4,079’
|
59%
|
|
Manta
Ray
|
Completing
|
4,043’
|
99%
|
|
·
|
2009 Malaysian Oil
Production Up 40% over 2008 – Newfield’s Malaysian production
benefited from its PM 323 developments – East Belumut and Chermingat.
Total liftings from Malaysia in 2009 totaled 5.3 MMBbls, or 14,500 BOPD
net. The Company is currently drilling the sixth of seven planned
development wells in the East Belumut
field.
|
|
·
|
Jade Exploration Test
Unsuccessful – In early 2010, Newfield drilled an unsuccessful
wildcat on a fault separated structure northeast of its existing Pearl
field development, located in the Pearl River Mouth Basin, offshore China.
The well was drilled for approximately $10 million. The Newfield operated
Pearl development is underway with first production expected in late
2012.
|
|
·
|
Deepwater Gulf of
Mexico Update – Newfield has five deepwater developments underway
in the deepwater Gulf of Mexico which are expected to provide significant
future production growth. An update on each of developments can be found
in the @NFX publication. The Company expects to participate in the
drilling of 2-3 deepwater wells in 2010. Highlights from 2009 and recent
events in deepwater include:
|
|
o
|
Fastball –
Located at Viosca Knoll 1003, Fastball commenced production in the fourth
quarter of 2009 and is currently producing 41 MMcf/d and 3,000 BOPD gross
(approximately 60 MMcfe/d). Newfield operates Fastball with a 66% working
interest.
|
|
o
|
Pyrenees
Complex – In the second quarter of 2009, Newfield announced a
significant operated discovery on its Pyrenees prospect, located at Garden
Banks 293. Newfield operates the development with a 40% working interest.
Development of the field is underway with first production expected in
late 2011. Newfield has an 11-block area around Pyrenees with several
remaining prospects. The Saluki
prospect, located at Garden Banks 425, is expected to spud in
February 2010. Newfield will operate the Saluki prospect with a 50%
working interest (35% cost
interest).
|
|
o
|
Axe – Newfield
expects to participate in the non-operated Axe prospect, which is expected
to spud in March 2010. Axe is located at Desoto Canyon 4, in close
proximity to the Company’s 2008 Dalmatian
discovery. Dalmatian’s development is underway with first production
expected in 2011. Newfield has a 23% interest in Axe and a 37.5% interest
in Dalmatian.
|
2010 Production
Guidance
Our
production for 2010 is expected to be 278 – 288 Bcfe, an increase of 8 – 12%
over 2009. In 2010, we will invest approximately 70% of our budget, or
approximately $1 billion, in domestic resource plays. More than one-third of the
budget will be directed to oil plays. Production by area is shown in today’s
@NFX publication.
2010 Capital Budget, Hedging
and Liquidity
Newfield’s 2010 capital budget is $1.6
billion (including approximately $124 million in capitalized interest and
overhead). This budget approximates the Company’s estimate of 2010 cash flow
from operations and includes approximately $100 million for planned activities
on the acreage recently acquired in the Maverick Basin of Texas. The budget
excludes our $215 million purchase price for our recent acquisition of assets in
the Maverick Basin from TXCO Resources, Inc. As a comparison, Newfield invested
$1.4 billion in 2009. Newfield plans to provide a detailed overview of its 2010
investments and activities by area in its conference call on February 17.
Following Newfield’s recent issuance of senior subordinated notes, Newfield has
no outstanding borrowings under its $1.25 billion credit facility.
4
Approximately
70% of the Company’s expected 2010 gas production is hedged at a weighted
average minimum price of approximately $6.60 per MMbtu. Approximately 65%
of the Company’s expected 2010 domestic oil production is hedged at a weighted
average minimum price of approximately $108.00 per barrel. Complete details on
Newfield’s hedge position can be found on the Company’s website in the @NFX
publication.
Newfield
Exploration Company is an independent crude oil and natural gas exploration and
production company. The Company relies on a proven growth strategy of growing
reserves through an active drilling program and select acquisitions. Newfield's
domestic areas of operation include the Mid-Continent, the Rocky Mountains,
onshore Texas and the Gulf of Mexico. The Company has international operations
in Malaysia and China.
**This
release contains forward-looking information. All information other than
historical facts included in this release, such as information regarding
estimated or anticipated first quarter 2010 results, estimated capital
expenditures, cash flow, production and cost reductions, drilling and
development plans and the timing of activities, is forward-looking information.
Although Newfield believes that these expectations are reasonable, this
information is based upon assumptions and anticipated results that are subject
to numerous uncertainties and risks. Actual results may vary significantly from
those anticipated due to many factors, including drilling results, oil and gas
prices, industry conditions, the prices of goods and services, the availability
of drilling rigs and other support services, the availability of refining
capacity for the crude oil Newfield produces from its Monument Butte field in
Utah, the availability and cost of capital resources, labor conditions and
severe weather conditions (such as hurricanes). In addition, the drilling of oil
and gas wells and the production of hydrocarbons are subject to governmental
regulations and operating risks.
For
information, contact:
Investor
Relations: Steve Campbell (281) 847-6081
Media
Relations: Keith Schmidt (281) 674-2650
Email:
info@newfield.com
5
4Q09 Actual
Results
|
4Q09
Actual
|
||||||||||||
|
Domestic
|
Int’l
|
Total
|
||||||||||
|
Production/Liftings
|
||||||||||||
|
Natural
gas – Bcf
|
45.7 | – | 45.7 | |||||||||
|
Oil
and condensate – MMBbls
|
1.7 | 1.4 | 3.1 | |||||||||
|
Total
Bcfe
|
56.2 | 8.4 | 64.6 | |||||||||
|
Average Realized
Prices
Note 1
|
||||||||||||
|
Natural
gas – $/Mcf
|
$ | 6.72 | $ | – | $ | 6.72 | ||||||
|
Oil
and condensate – $/Bbl
|
$ | 102.45 | $ | 77.43 | $ | 91.31 | ||||||
|
Mcf
equivalent – $/Mcfe
|
$ | 8.71 | $ | 12.91 | $ | 9.27 | ||||||
|
Operating
Expenses: Note
2
|
||||||||||||
|
Lease
operating
|
||||||||||||
|
Recurring
($MM)
|
$ | 45.7 | $ | 12.1 | $ | 57.8 | ||||||
|
per/Mcfe
|
$ | 0.83 | $ | 1.43 | $ | 0.91 | ||||||
|
Major
(workovers, repairs, etc.) ($MM)
|
$ | 5.4 | $ | 3.9 | $ | 9.3 | ||||||
|
per/Mcfe
|
$ | 0.10 | $ | 0.47 | $ | 0.15 | ||||||
|
Production and other taxes
($MM)
|
$ | 9.3 | $ | 15.5 | $ | 24.8 | ||||||
|
per/Mcfe
|
$ | 0.17 | $ | 1.84 | $ | 0.39 | ||||||
|
General and administrative
(G&A), net ($MM)
|
$ | 36.4 | $ | 1.8 | $ | 38.2 | ||||||
|
per/Mcfe
|
$ | 0.66 | $ | 0.21 | $ | 0.60 | ||||||
|
Capitalized
internal costs ($MM)
|
$ | (18.7 | ) | |||||||||
|
per/Mcfe
|
$ | (0.29 | ) | |||||||||
|
Interest
expense ($MM)
|
$ | 30.8 | ||||||||||
|
per/Mcfe
|
$ | 0.48 | ||||||||||
|
Capitalized
interest ($MM)
|
$ | (12.7 | ) | |||||||||
|
per/Mcfe
|
$ | (0.20 | ) | |||||||||
|
Note
1: Average realized prices include the effects of hedging contracts. If
the effects of these contracts were excluded, the average realized price
for total gas would have been $4.21 per Mcf and the total oil and
condensate average realized price would have been $71.29 per
barrel.
Note
2: Recurring lease operating expense includes transportation
expense.
|
||||||||||||
6
1Q10
Estimates
|
1Q10
Estimates
|
||||||||||||
|
Domestic
|
Int’l
|
Total
|
||||||||||
|
Production/Liftings
|
||||||||||||
|
Natural
gas – Bcf
|
45.6 – 50.4 | – | 45.6 – 50.4 | |||||||||
|
Oil
and condensate – MMBbls
|
1.6 – 1.7 | 1.3 – 1.4 | 2.9 – 3.1 | |||||||||
|
Total
Bcfe
|
54.9 – 60.7 | 7.7 – 8.5 | 62.6 – 69.2 | |||||||||
|
Average
Realized Prices
|
||||||||||||
|
Natural
gas – $/Mcf
|
Note
1
|
|||||||||||
|
Oil
and condensate – $/Bbl
|
Note
2
|
Note
3
|
||||||||||
|
Mcf
equivalent – $/Mcfe
|
||||||||||||
|
Operating
Expenses:
|
||||||||||||
|
Lease
operating
|
||||||||||||
|
Recurring
($MM)
|
$ | 54.9 - $60.7 | $ | 14.2 - $15.7 | $ | 69.1 - $76.4 | ||||||
|
per/Mcfe
|
$ | 1.01 - $1.03 | $ | 1.82 - $1.86 | $ | 1.11 - $1.13 | ||||||
|
Major
(workover, repairs, etc.) ($MM)
|
$ | 9.1 - $10.1 | $ | 0.4 - $0.5 | $ | 9.5 - $10.5 | ||||||
|
per/Mcfe
|
$ | 0.16 - $0.17 | $ | 0.04 - $0.05 | $ | 0.15 - $0.16 | ||||||
|
Production and other taxes
($MM)Note
4
|
$ | 17.1 - $18.9 | $ | 11.7 - $12.9 | $ | 28.8 - $31.8 | ||||||
|
per/Mcfe
|
$ | 0.31 - $0.32 | $ | 1.50 - $1.53 | $ | 0.46 - $0.47 | ||||||
|
General and administrative
(G&A), net ($MM)
|
$ | 34.2 - $37.8 | $ | 1.1 - $1.2 | $ | 35.3 - $39.0 | ||||||
|
per/Mcfe
|
$ | 0.63 - $0.64 | $ | 0.14 - $0.15 | $ | 0.57 - $0.58 | ||||||
|
Capitalized
internal costs ($MM)
|
$ | (19.4 - $21.5 | ) | |||||||||
|
per/Mcfe
|
$ | (0.31 - $0.32 | ) | |||||||||
|
Interest
expense ($MM)
|
$ | 39.0 - $43.1 | ||||||||||
|
per/Mcfe
|
$ | 0.62 - $0.64 | ||||||||||
|
Capitalized
interest ($MM)
|
$ | (11.5 - $12.7 | ) | |||||||||
|
per/Mcfe
|
$ | (0.18 - $0.19 | ) | |||||||||
|
Tax
rate (%)Note
5
|
35% - 37 | % | ||||||||||
|
Income
taxes (%)
|
||||||||||||
|
Current
|
14% - 16 | % | ||||||||||
|
Deferred
|
84% - 86 | % | ||||||||||
|
Note
1: The price that we receive for natural gas production from the Gulf of
Mexico and onshore Gulf Coast, after basis differentials, transportation
and handling charges, typically averages $0.25 - $0.50 per MMBtu less than
the Henry Hub Index. Realized natural gas prices for our
Mid-Continent properties, after basis differentials, transportation and
handling charges, typically average 85-90% of the Henry Hub
Index.
Note
2: The price we receive for our Gulf Coast oil production typically
averages about 90-95% of the NYMEX West Texas Intermediate (WTI) price.
The price we receive for our oil production in the Rocky Mountains is
currently averaging about $12-$14 per barrel below the WTI price. Oil
production from our Mid-Continent properties typically averages 80-85% of
the WTI price.
Note
3: Oil sales from our operations in Malaysia typically sell at a slight
discount to Tapis, or about 90-95% of WTI. Oil sales from our operations
in China typically sell at $4-$6 per barrel less than the WTI
price.
Note
4: Guidance for production taxes determined using $70/Bbl oil and
$5.50/MMBtu gas.
Note
5: Tax rate applied to earnings excluding unrealized gains or losses
on commodity derivatives.
|
||||||||||||
7
|
CONSOLIDATED
STATEMENT OF INCOME
(Unaudited,
in millions, except per share data)
|
For
the
Three
Months Ended
December
31,
|
For
the
Twelve
Months Ended
December
31,
|
||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Oil
and gas revenues
|
$ | 414 | $ | 338 | $ | 1,338 | $ | 2,225 | ||||||||
|
Operating
expenses:
|
||||||||||||||||
|
Lease operating
|
67 | 81 | 259 | 265 | ||||||||||||
|
Production and other
taxes
|
25 | 3 | 63 | 157 | ||||||||||||
|
Depreciation, depletion and
amortization
|
147 | 193 | 587 | 697 | ||||||||||||
|
General and
administrative
|
38 | 36 | 144 | 141 | ||||||||||||
|
Ceiling
test writedown
|
— | 1,863 | 1,344 | 1,863 | ||||||||||||
|
Other
|
— | 4 | 8 | 4 | ||||||||||||
|
Total operating
expenses
|
277 | 2,180 | 2,405 | 3,127 | ||||||||||||
|
Income
(loss) from operations
|
137 | (1,842 | ) | (1,067 | ) | (902 | ) | |||||||||
|
Other
income (expenses):
|
||||||||||||||||
|
Interest expense
|
(31 | ) | (29 | ) | (126 | ) | (112 | ) | ||||||||
|
Capitalized
interest
|
12 | 17 | 51 | 60 | ||||||||||||
|
Commodity derivative
income
|
63 | 655 | 252 | 408 | ||||||||||||
|
Other
|
1 | 1 | 5 | 11 | ||||||||||||
|
Total other income
(expenses)
|
45 | 644 | 182 | 367 | ||||||||||||
|
Income
(loss) before income taxes
|
182 | (1,198 | ) | (885 | ) | (535 | ) | |||||||||
|
Income
tax provision (benefit)
|
69 | (409 | ) | (343 | ) | (162 | ) | |||||||||
|
Net
income (loss)
|
$ | 113 | $ | (789 | ) | $ | (542 | ) | $ | (373 | ) | |||||
|
Income
(loss) per share:
|
||||||||||||||||
|
Basic
--
|
$ | 0.87 | $ | (6.09 | ) | $ | (4.18 | ) | $ | (2.88 | ) | |||||
|
Diluted
--
|
$ | 0.86 | $ | (6.09 | ) | $ | (4.18 | ) | $ | (2.88 | ) | |||||
|
Weighted
average number of shares outstanding
for basic income (loss) per
share
|
130 | 130 | 130 | 129 | ||||||||||||
|
Weighted
average number of shares outstanding
for diluted income (loss) per
share *
|
133 | 130 | 130 | 129 | ||||||||||||
|
*
Had we recognized net income for the three month period ended December 31,
2008 and the twelve month periods ended December 31, 2009 and 2008, the
weighted average number of shares outstanding for the computation of
diluted earnings per share would have increased by 1 million, 2 million
and 3 million shares, respectively.
|
||||||||||||||||
8
|
CONDENSED
CONSOLIDATED BALANCE SHEET
(Unaudited,
in millions)
|
December
31,
2009
|
December
31,
2008
|
||||||
|
ASSETS
|
||||||||
|
Current
assets:
|
||||||||
|
Cash and cash
equivalents
|
$ | 78 | $ | 24 | ||||
|
Derivative assets
|
269 | 663 | ||||||
|
Other current
assets
|
546 | 519 | ||||||
|
Total current
assets
|
893 | 1,206 | ||||||
|
Property
and equipment, net (full cost method)
|
5,247 | 5,758 | ||||||
|
Derivative
assets
|
19 | 247 | ||||||
|
Other
assets
|
95 | 94 | ||||||
|
Total assets
|
$ | 6,254 | $ | 7,305 | ||||
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||||
|
Current
liabilities
|
$ | 873 | $ | 1,085 | ||||
|
Other
liabilities
|
142 | 92 | ||||||
|
Long-term
debt
|
2,037 | 2,213 | ||||||
|
Deferred
taxes
|
434 | 658 | ||||||
|
Total long-term
liabilities
|
2,613 | 2,963 | ||||||
|
Commitments
and contingencies
|
— | — | ||||||
|
STOCKHOLDERS’
EQUITY
|
||||||||
|
Common
stock
|
1 | 1 | ||||||
|
Additional
paid-in capital
|
1,389 | 1,335 | ||||||
|
Treasury
stock
|
(33 | ) | (32 | ) | ||||
|
Accumulated
other comprehensive loss
|
(11 | ) | (11 | ) | ||||
|
Retained
earnings
|
1,422 | 1,964 | ||||||
|
Total stockholders’
equity
|
2,768 | 3,257 | ||||||
|
Total liabilities and
stockholders’ equity
|
$ | 6,254 | $ | 7,305 | ||||
9
|
CONDENSED
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited,
in millions)
|
For
the
Twelve
Months Ended
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Cash
flows from operating activities:
|
||||||||
|
Net loss
|
$ | (542 | ) | $ | (373 | ) | ||
|
Adjustments
to reconcile net loss to net cash provided by
operating
activities:
|
||||||||
|
Depreciation,
depletion and amortization
|
587 | 697 | ||||||
|
Deferred tax
benefit
|
(391 | ) | (198 | ) | ||||
|
Stock-based
compensation
|
28 | 26 | ||||||
|
Ceiling test and other
impairments
|
1,344 | 1,863 | ||||||
|
Commodity derivative
income
|
(252 | ) | (408 | ) | ||||
|
Cash receipts (payments) on
derivative settlements
|
883 | (750 | ) | |||||
| 1,657 | 857 | |||||||
|
Changes in operating assets and
liabilities
|
(79 | ) | (3 | ) | ||||
|
Net cash provided by operating
activities
|
1,578 | 854 | ||||||
|
Cash
flows from investing activities:
|
||||||||
|
Additions to oil and gas
properties and other, net
|
(1,376 | ) | (2,301 | ) | ||||
|
Net redemptions of
investments
|
20 | 48 | ||||||
|
Net cash used in investing
activities
|
(1,356 | ) | (2,253 | ) | ||||
|
Cash
flows from financing activities:
|
||||||||
|
Net proceeds (repayments) under
credit arrangements
|
(176 | ) | 561 | |||||
|
Net proceeds from issuance of
senior subordinated notes
|
— | 592 | ||||||
|
Other
|
8 | 20 | ||||||
|
Net cash provided by (used in)
financing activities
|
(168 | ) | 1,173 | |||||
|
Increase
(decrease) in cash and cash equivalents
|
54 | (226 | ) | |||||
|
Cash
and cash equivalents, beginning of period
|
24 | 250 | ||||||
|
Cash
and cash equivalents, end of period
|
$ | 78 | $ | 24 | ||||
10
Explanation and
Reconciliation of Non-GAAP Financial Measures
Earnings Stated Without the
Effect of Certain Items
Earnings
stated without the effect of certain items is a non-GAAP financial measure.
Earnings without the effect of these items are presented because they affect the
comparability of operating results from period to period. In addition, earnings
without the effect of these items are more comparable to earnings estimates
provided by securities analysts.
A
reconciliation of earnings for the fourth quarter and full year 2009 stated
without the effect of certain items to net income is shown below:
| 4Q09 | 2009 | |||||||
|
(in
millions)
|
||||||||
|
Net
income
|
$ | 113 | $ | (542 | ) | |||
|
Ceiling test
writedown
|
—
|
1,344 | ||||||
|
Net unrealized loss on
commodity derivatives (1)
|
112 | 604 | ||||||
|
Income tax adjustment for
above items
|
(39 | ) | (706 | ) | ||||
|
Tax benefit associated with
deferred tax assets
in Malaysia
|
— | (24 | ) | |||||
|
Earnings
stated without the effect of the above items
|
$ | 186 | $ | 676 | ||||
(1) The
determination of “Net unrealized loss on commodity derivatives” for the fourth
quarter and full year 2009 is as follows:
| 4Q09 | 2009 | |||||||
|
(in
millions)
|
||||||||
|
Commodity
derivative income
|
$ | 63 | $ | 252 | ||||
|
Cash
receipts on derivative settlements
|
(182 | ) | (883 | ) | ||||
|
Option
premiums associated with derivatives settled
during
the period
|
7 | 27 | ||||||
|
Net unrealized
loss on commodity derivatives
|
$ | (112 | ) | $ | (604 | ) | ||
Net Cash Provided by
Operating Activities Before Changes in Operating Assets and
Liabilities
Net cash
provided by operating activities before changes in operating assets and
liabilities is presented because of its acceptance as an indicator of an oil and
gas exploration and production company’s ability to internally fund exploration
and development activities and to service or incur additional debt. This measure
should not be considered as an alternative to net cash provided by operating
activities as defined by generally accepted accounting principles.
A
reconciliation of net cash provided by operating activities before changes in
operating assets and liabilities to net cash provided by operating activities is
shown below:
| 4Q09 | 2009 | |||||||
|
(in
millions)
|
||||||||
|
Net
cash provided by operating activities
|
$ | 361 | $ | 1,578 | ||||
|
Net change in operating assets
and liabilities
|
81 | 79 | ||||||
|
Net
cash provided by operating activities before changes
in
operating assets and liabilities
|
$ | 442 | $ | 1,657 | ||||
11