THE WOODLANDS, Texas,
Feb. 21, 2012 /PRNewswire/ --
Newfield Exploration Company (NYSE: NFX) today reported its
unaudited fourth quarter and full-year 2011 financial results.
Newfield will host a conference call at 10
a.m. CST on February 22, 2012.
To participate in the call, dial 719-325-2481 or listen through the
investor relations section of our website at
http://www.newfield.com.
Fourth Quarter 2011
For the fourth quarter of 2011, Newfield recorded net income of
$68 million, or $0.51 per diluted share (all per share amounts
are on a diluted basis). Net income for the fourth quarter includes
a net unrealized loss on commodity derivatives of $93 million ($59
million after-tax), or $0.44
per share. Without the effect of this item, net income for
the fourth quarter of 2011 would have been $127 million, or $0.95 per share.
Revenues in the fourth quarter of 2011 were $677 million. Net cash provided by operating
activities before changes in operating assets and liabilities was
$387 million. See “Explanation and
Reconciliation of Non-GAAP Financial Measures” found after the
financial statements in this release.
Newfield’s oil and liquids liftings in the fourth quarter of
2011 were 6 MMBbls, or an average of approximately 64,000 BOPD.
This is about 9,000 BOPD higher than the third quarter of 2011 and
28% higher than the fourth quarter of 2010. Natural gas production
in the fourth quarter of 2011 was 44 Bcf, an average of 478 MMcf/d.
When combined, Newfield’s production in the fourth quarter of 2011
was 79 Bcfe, of which 44% was oil and liquids. Capital expenditures
in the fourth quarter of 2011 were $479
million.
Full-Year 2011
For 2011, Newfield recorded net income of $539 million, or $3.99 per diluted share. Revenues for 2011 were
$2.5 billion. Net cash provided by
operating activities before changes in operating assets and
liabilities was $1.5 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 2011 was 300 Bcfe, an
increase of 4% over 2010 production volumes. Oil and liquids
production grew more than 20% over 2010 levels and comprised
approximately 40% of the Company’s total production. Production
associated with approximately $400
million in non-strategic asset sales during the year would
have contributed an additional 4 Bcfe. Capital expenditures for
2011 were approximately $2.2 billion,
excluding acquisitions.
Year-End 2011 Reserves and Capital Expenditures
At year-end 2011, Newfield’s proved reserves were 3.9 Tcfe and
probable reserves were 2.6 Tcfe. This reflects growth of 5% and 4%,
respectively, over the prior year. The Company’s proved oil
reserves increased nearly 30% during 2011 while proved natural gas
reserves declined by 6% as compared to year-end 2010. Proved
developed reserves at year-end 2011 were 54% of total proved
reserves. Newfield’s present value of its proved reserves
discounted 10% (PV-10) increased by more than 20% over the prior
year to approximately $6 billion
(after-tax), which follows a more than 65% increase in PV-10 during
2010.
The following table details our proved reserves for the three
years ended 2009-2011:
Proved Oil and Gas
Reserves:
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
|
|
2011
|
|
2010
|
|
2009
|
|
|
|
|
|
|
(Bcfe)
|
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
3,712
|
|
3,616
|
|
2,950
|
|
|
|
Reserve additions
|
|
909
|
|
676
|
|
1,342
|
|
|
|
Reserve revisions
|
|
(288)
|
|
(289)
|
|
(384)
|
|
|
|
Sales
|
|
(122)
|
|
(3)
|
|
(35)
|
|
|
|
Production
|
|
(300)
|
|
(288)
|
|
(257)
|
|
|
|
End of year
|
|
3,911
|
|
3,712
|
|
3,616
|
|
|
Proved Developed
Reserves:
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
2,164
|
|
1,908
|
|
1,827
|
|
|
|
End of year
|
|
2,129
|
|
2,164
|
|
1,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Newfield’s proved natural gas reserves at year-end 2011 were 2.3
Tcf compared to 2.5 Tcf at year-end 2010 and 2.6 Tcf at year-end
2009. The Company’s proved crude oil and condensate reserves at
year-end 2011 were 263 million barrels compared to 204 million
barrels at year-end 2010 and 169 million barrels at year-end 2009.
Natural gas comprised about 60%, 67% and 72% of proved reserves at
year-end 2011, 2010 and 2009, respectively.
Our total proved reserve revisions in 2011 were 288 Bcfe.
Price-related and other revisions were negligible. Of proved
undeveloped natural gas reserves, 87 Bcfe were reclassified to
probable reserves as the Company directed capital to higher margin
oil drilling and the locations associated with these reserves moved
outside of a five-year development horizon. Negative performance
revisions in 2011 were 198 Bcfe, which included (i) well
performance as efforts to extend the Greater Monument Butte Unit
(GMBU) Green River section to the northwest encountered higher than
expected gas production, (ii) the timing of waterflood response
recognition in the GMBU, (iii) wellbore failures in gas reservoirs
along the Gulf Coast and (iv) offset well interference in older
vertical gas wells in the Mid-Continent, which were adversely
impacted by new horizontal well completions.
Beginning with the year-end 2009, SEC guidelines limit proved
undeveloped reserves to those expected to be developed within five
years. In long-lived resource plays with a lengthy inventory of
drilling locations, such as our Woodford Shale and Uinta Basin
plays, this time limit may have a material impact on the total
reserves that could otherwise be recognized as proved. At year-end
2011, a total of approximately 1.1 Tcfe, or 42%, of Newfield’s
probable reserves meet the definition of proved undeveloped
reserves except for the fact that their planned development timing
is beyond the prescribed five-year (2012-2016) development horizon
for proved reserves.
2011 Capital
Expenditures:
|
|
|
|
2011
|
|
|
|
(in
millions)
|
|
Domestic property
acquisitions:
|
|
|
|
|
|
Unproved
|
|
$
|
361
|
|
|
Proved
|
|
|
72
|
|
Domestic exploration and
development
|
|
|
1,775
|
|
International costs
incurred*
|
|
|
363
|
|
|
Total costs
incurred**
|
|
$
|
2,571
|
|
|
|
|
|
|
*
|
International costs incurred
includes $19 million (under the terms of the PSC) associated with
first oil from the East Piatu field offshore
Malaysia.
|
|
**
|
Total costs incurred include
$194 million of capitalized interest and overhead and $33 million
of asset retirement obligations.
|
|
|
|
Operational Highlights:
Rocky Mountains
Uinta Basin – Through several transactions in 2011, Newfield
added more than 75,000 net acres in the Central Basin of
Utah (north and adjacent to
Monument Butte) and today owns interest in approximately 230,000
net acres in the Uinta Basin. The acquisition introduced additional
play types including the Uteland Butte, Wasatch and Black Shale. Current Uinta Basin
net oil production is approximately 22,000 BOEPD net.
The Uinta Basin will be the centerpiece of Newfield’s domestic
oil growth in 2012. With a planned 7-8 rig program,
production from the area is expected to grow about 20% over 2011
levels. In the Central Basin, Newfield is currently drilling its
first pressured well in the Uteland Butte and multiple horizontal
tests of other pressured targets (Wasatch and Black Shale) are planned in 2012.
Initial results from these wells are expected in the second
quarter.
In late 2011 and early 2012, the Company announced two separate,
long-term agreements (seven and 10 years beginning in 2013 and
2014, respectively) with Salt Lake
City area refiners. These agreements captured 38,000 BOPD of
refining capacity.
Williston Basin – Newfield owns
approximately 100,000 net acres in the Williston Basin (includes 40,000 acres in Elm
Coulee) where current net production is approximately 7,500 BOEPD.
In late 2011, Newfield voluntarily slowed its drilling and
completion activities in the Williston Basin. As a result, the completion
of 17 wells was deferred into 2012. Subsequently, the Company
monetized a 23,000 acre package in Williams County, North Dakota for $276 million. Net production from these
assets was approximately 300 BOEPD. Eight of the uncompleted wells
were sold as part of this transaction. The remaining wells are
planned for completion in the first half of 2012.
In January 2012, Newfield resumed
its activity levels in the Williston Basin. Six of the nine remaining
deferred completions are in various stages and expected to commence
production in the first half of 2012. Three recent wells have
commenced production with average 24-hour initial production rates
of 2,900 BOEPD. The Company plans to operate 2-4 drilling rigs
in the Williston Basin throughout
2012 and production is expected to increase approximately 35% over
2011 levels.
Mid-Continent
As a result of low natural gas prices, Newfield is decreasing
activities in the dry gas portion of the Woodford Shale (Arkoma
Basin) and in the Granite Wash. In the first quarter of 2012, the
Company curtailed approximately 2 Bcfe of production through the
deferred timing of completions and shut-ins in the Mid-Continent.
Natural gas production from the Mid-Continent region is expected to
decline approximately 5-10% in 2012. Current net daily production
in the region is approximately 350 MMcfe/d.
Granite Wash – Net production in the Granite Wash during 2011
averaged 105 MMcfe/d (current production is a record 150 MMcfe/d).
In late 2011, eight completions were deferred into 2012 as the
Company slowed activities in several areas to meet its capital
budget. All of the deferred completions are now on-line. Newfield
plans to reallocate capital in 2012 to the Cana Woodford play. Net
production for the year in the Granite Wash is expected to average
about 90 MMcfe/d, or a decrease of about 15% over 2011 levels. In
the first quarter of 2012, Newfield expects to run a single-rig
program, focused primarily on the condensate and “liquids rich”
Marmaton formation in Stiles/Britt
Ranch.
Woodford Shale – Net production in the Arkoma Woodford in 2011
averaged approximately 180 MMcfe/d (current net production is
approximately 160 MMcfe/d). With current low gas prices, the
Company has ceased drilling in the Arkoma Woodford for 2012 and
expects that annual net production from the Woodford Shale will
average about 160 MMcfe/d.
Cana Woodford – Newfield’s drilling efforts have shifted from
the Arkoma Woodford to the oil and “liquids rich” Cana Woodford,
located in the Anadarko Basin. The Company assembled a 125,000
net-acre lease position as a southeast extension of this play in
2011. The Company plans to operate up to seven rigs in 2012 to
assess this new acreage.
Onshore Gulf Coast
Current net daily production from the Onshore Gulf Coast region
is approximately 85 MMcfe/d. Newfield’s active program in the
Maverick Basin today encompasses more than 250,000 net acres. The
Company plans to run a single-rig program in 2012 and test four
super extended laterals (approximately 7,500’ laterals) in the
Eagle Ford Shale. Of the SXL wells, two have been drilled to date
and are awaiting completion. In addition, tests are planned in the
Austin Chalk, the Georgetown and
Glen Rose formations.
International
Newfield’s net oil production today in Malaysia is at a record 29,000 BOPD.
Production commenced in late 2011 from two new offshore
developments – East Piatu and Puteri. East Piatu is today producing
12,500 BOPD gross and Puteri is producing 8,000 BOPD gross.
Production from Malaysia in 2012
is expected to increase approximately 25% over 2011 levels.
In 2012, approximately $100
million will be invested in the development of the Pearl oil
field, located offshore China in
the Pearl River Mouth Basin. First production is expected in late
2013 or early 2014.
Gulf of Mexico
In early 2012, Newfield declared its Gulf of Mexico assets “non-strategic” and is
currently exploring options to maximize value. For 2012, Newfield’s
production is expected to decline approximately 10% from 2011
levels. The Company’s Pyrenees development commenced production in
February 2012 and is currently
producing about 3,300 BOEPD net.
Newfield Exploration Company is an independent energy company
engaged in the exploration, development and production of crude
oil, natural gas and natural gas liquids. Our domestic areas
of operation include the Mid-Continent, the Rocky Mountains and
onshore Texas.
Internationally, we focus on offshore oil developments 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 drilling
plans and planned capital expenditures, 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 in the Uinta Basin, the availability and cost of capital
resources, new regulations or changes in tax legislation, labor
conditions and severe weather conditions (such as hurricanes). In
addition, the drilling of oil and natural gas wells and the
production of hydrocarbons are subject to numerous governmental
regulations and operating risks. Other factors that could impact
forward-looking statements are described in "Risk Factors" in
Newfield's 2010 Annual Report on Form 10-K, Quarterly Reports on
Form 10-Q, and other subsequent public filings with the Securities
and Exchange Commission, which can be found at www.sec.gov.
Unpredictable or unknown factors not discussed in this press
release could also have material adverse effects on forward-looking
statements. Readers are cautioned not to place undue reliance on
forward-looking statements, which speak only as of the date hereof.
Unless legally required, Newfield undertakes no obligation to
publicly update or revise any forward-looking statements.
For information,
contact:
|
|
Investor Relations:
|
Steve Campbell (281)
210-5200
|
|
|
Danny Aguirre (281)
210-5203
|
|
Media Relations:
|
Keith Schmidt (281)
210-5202
|
|
|
|
|
|
|
|
4Q11
Actual
|
|
4Q11 Actual
Results
|
|
Domestic
|
|
|
Int'l
|
|
|
Total
|
|
|
|
Production/Liftings(Note 1)
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - Bcf
|
|
44.1
|
|
|
0.1
|
|
|
44.2
|
|
|
|
Oil and condensate -
MMBbls
|
|
3.6
|
|
|
2.3
|
|
|
5.9
|
|
|
|
Total Bcfe
|
|
65.3
|
|
|
14.0
|
|
|
79.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Realized
Prices(Note 1,2)
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - $/Mcf
|
$
|
4.69
|
|
$
|
3.95
|
|
$
|
4.69
|
|
|
|
Oil and condensate -
$/Bbl
|
$
|
75.63
|
|
$
|
107.00
|
|
$
|
88.04
|
|
|
|
Mcf equivalent -
$/Mcfe
|
$
|
7.36
|
|
$
|
17.75
|
|
$
|
9.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
|
|
|
Lease operating
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Recurring
|
$
|
62.1
|
|
$
|
20.7
|
|
$
|
82.8
|
|
|
|
Major (workovers,
etc.)
|
$
|
9.9
|
|
$
|
1.9
|
|
$
|
11.8
|
|
|
|
Transportation
|
$
|
25.3
|
|
$
|
—
|
|
$
|
25.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating (per
Mcfe)
|
|
|
|
|
|
|
|
|
|
|
|
Recurring
|
$
|
0.98
|
|
$
|
1.48
|
|
$
|
1.07
|
|
|
|
Major (workovers,
etc.)
|
$
|
0.16
|
|
$
|
0.14
|
|
$
|
0.15
|
|
|
|
Transportation
|
$
|
0.40
|
|
$
|
—
|
|
$
|
0.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and other taxes
($MM)
|
$
|
12.2
|
|
$
|
72.7
|
|
$
|
84.9
|
|
|
|
per Mcfe
|
$
|
0.19
|
|
$
|
5.20
|
|
$
|
1.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
(G&A), net ($MM)
|
$
|
51.5
|
|
$
|
1.6
|
|
$
|
53.1
|
|
|
|
per Mcfe
|
$
|
0.81
|
|
$
|
0.11
|
|
$
|
0.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized internal costs
($MM)
|
|
|
|
|
|
|
$
|
(32.1)
|
|
|
|
|
|
per Mcfe
|
|
|
|
|
|
|
$
|
(0.41)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
($MM)
|
|
|
|
|
|
|
$
|
51.0
|
|
|
|
per Mcfe
|
|
|
|
|
|
|
$
|
0.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest
($MM)
|
|
|
|
|
|
|
$
|
(21.1)
|
|
|
|
per Mcfe
|
|
|
|
|
|
|
$
|
(0.27)
|
|
________________
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 1: Beginning in 2011,
Newfield reported NGLs with its reported oil production. For
comparative purposes, the following table depicts 4Q2010 production
and realized prices pro-forma this change:
|
|
|
|
Domestic
|
|
|
Int'l
|
|
|
Total
|
|
Production/Liftings
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - Bcf
|
|
49.9
|
|
|
—
|
|
|
49.9
|
|
|
|
Oil, condensate & NGLs-
MMBbls
|
|
2.7
|
|
|
1.9
|
|
|
4.6
|
|
|
|
Total Bcfe
|
|
66.0
|
|
|
11.3
|
|
|
77.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Realized
Prices
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - $/Mcf
|
$
|
5.19
|
|
$
|
—
|
|
$
|
5.19
|
|
|
|
Oil, condensate & NGLs -
$/Bbl
|
$
|
82.89
|
|
$
|
82.86
|
|
$
|
82.88
|
|
|
|
Mcf equivalent -
$/Mcfe
|
$
|
7.41
|
|
$
|
13.81
|
|
$
|
8.37
|
|
|
|
|
|
|
|
Note 2: Average realized prices
include the effects of hedging contracts. If the effects of these
contracts were excluded, the average realized price for total
natural gas would have been $3.54 per Mcf and the domestic and
total oil and condensate average realized prices would have been
$78.38 and $89.71 per barrel, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENT OF NET
INCOME
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in millions, except
per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the
Three Months
Ended
December
31,
|
|
For the
Twelve
Months Ended
December
31,
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
revenues
|
$
|
677
|
|
$
|
528
|
|
$
|
2,471
|
|
$
|
1,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
120
|
|
|
89
|
|
|
453
|
|
|
326
|
|
Production and other
taxes
|
|
85
|
|
|
49
|
|
|
330
|
|
|
126
|
|
Depreciation, depletion
and amortization
|
|
239
|
|
|
181
|
|
|
767
|
|
|
644
|
|
General and
administrative
|
|
53
|
|
|
39
|
|
|
185
|
|
|
156
|
|
Ceiling test and other
impairments
|
|
—
|
|
|
7
|
|
|
—
|
|
|
7
|
|
Other
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Total
operating expenses
|
|
497
|
|
|
365
|
|
|
1,735
|
|
|
1,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from
operations
|
|
180
|
|
|
163
|
|
|
736
|
|
|
614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income
(expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
(51)
|
|
|
(40)
|
|
|
(175)
|
|
|
(156)
|
|
Capitalized
interest
|
|
21
|
|
|
15
|
|
|
82
|
|
|
58
|
|
Commodity derivative
income (expense)
|
|
(54)
|
|
|
(98)
|
|
|
195
|
|
|
316
|
|
Other
|
|
—
|
|
|
(5)
|
|
|
2
|
|
|
(3)
|
|
Total other
income (expense)
|
|
(84)
|
|
|
(128)
|
|
|
104
|
|
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income
taxes
|
|
96
|
|
|
35
|
|
|
840
|
|
|
829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
28
|
|
|
13
|
|
|
301
|
|
|
306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
$
|
68
|
|
$
|
22
|
|
$
|
539
|
|
$
|
523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
0.51
|
|
$
|
0.17
|
|
$
|
4.03
|
|
$
|
3.97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
$
|
0.51
|
|
$
|
0.17
|
|
$
|
3.99
|
|
$
|
3.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average number of
shares outstanding for basic income per share
|
|
134
|
|
|
133
|
|
|
134
|
|
|
132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average number of
shares outstanding for diluted income per share
|
|
135
|
|
|
134
|
|
|
135
|
|
|
134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED BALANCE
SHEET
|
|
|
|
|
|
|
(Unaudited, in
millions)
|
|
|
|
|
|
|
|
|
December
31,
|
|
December
31,
|
|
|
|
2011
|
|
2010
|
|
ASSETS
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
76
|
|
$
|
39
|
|
Derivative
assets
|
|
129
|
|
|
197
|
|
Other current
assets
|
|
570
|
|
|
495
|
|
Total current assets
|
|
775
|
|
|
731
|
|
|
|
|
|
|
|
|
|
Property and
equipment, net (full cost method)
|
|
8,020
|
|
|
6,608
|
|
Derivative
assets
|
|
61
|
|
|
39
|
|
Other
assets
|
|
135
|
|
|
116
|
|
Total assets
|
$
|
8,991
|
|
$
|
7,494
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS'
EQUITY
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
Derivative
liabilities
|
|
50
|
|
|
53
|
|
Other current
liabilities
|
|
882
|
|
|
875
|
|
Total current liabilities
|
|
932
|
|
|
928
|
|
|
|
|
|
|
|
|
|
Other
liabilities
|
|
179
|
|
|
153
|
|
Derivative
liabilities
|
|
3
|
|
|
46
|
|
Long-term
debt
|
|
3,006
|
|
|
2,304
|
|
Deferred
taxes
|
|
951
|
|
|
720
|
|
Total long-term liabilities
|
|
4,139
|
|
|
3,223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS'
EQUITY
|
|
|
|
|
|
|
Common stock and additional
paid-in capital
|
|
1,446
|
|
|
1,410
|
|
Accumulated other comprehensive
loss
|
|
(10)
|
|
|
(12)
|
|
Retained earnings
|
|
2,484
|
|
|
1,945
|
|
Total
stockholders' equity
|
|
3,920
|
|
|
3,343
|
|
Total
liabilities and stockholders' equity
|
$
|
8,991
|
|
$
|
7,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED STATEMENT
OF CASH FLOWS
|
|
|
|
|
(Unaudited, in
millions)
|
|
|
|
|
|
|
|
|
|
|
For
the
Twelve
Months Ended
December
31,
|
|
|
|
|
2011
|
|
2010
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
539
|
|
$
|
523
|
|
|
Adjustments to reconcile net
income to net cash
|
|
|
|
|
|
|
|
|
provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion
and amortization
|
|
|
767
|
|
|
644
|
|
|
Deferred tax
provision
|
|
|
208
|
|
|
247
|
|
|
Stock-based
compensation
|
|
|
29
|
|
|
22
|
|
|
Commodity derivative
income
|
|
|
(195)
|
|
|
(316)
|
|
|
Cash receipts on
derivative settlements, net
|
|
|
195
|
|
|
456
|
|
|
Ceiling test and other
impairments
|
|
|
—
|
|
|
7
|
|
|
Other non-cash
charges
|
|
|
6
|
|
|
7
|
|
|
|
|
|
1,549
|
|
|
1,590
|
|
|
Changes in operating assets and
liabilities
|
|
|
40
|
|
|
40
|
|
|
Net cash
provided by operating activities
|
|
|
1,589
|
|
|
1,630
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
Additions to oil and gas
properties and other
|
|
|
(2,340)
|
|
|
(1,658)
|
|
|
Acquisitions of oil and
gas properties
|
|
|
(304)
|
|
|
(313)
|
|
|
Proceeds from sales of
oil and gas properties
|
|
|
406
|
|
|
12
|
|
|
Redemptions of
investments
|
|
|
2
|
|
|
8
|
|
|
Net cash
used in investing activities
|
|
|
(2,236)
|
|
|
(1,951)
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
Net repayments under
credit arrangements
|
|
|
(49)
|
|
|
(249)
|
|
|
Net proceeds from
issuance of senior notes
|
|
|
742
|
|
|
—
|
|
|
Net proceeds from
issuance of senior subordinated notes
|
|
|
—
|
|
|
686
|
|
|
Repayment of senior
notes
|
|
|
—
|
|
|
(175)
|
|
|
Other
|
|
|
(9)
|
|
|
20
|
|
|
Net cash
provided by financing activities
|
|
|
684
|
|
|
282
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and
cash equivalents
|
|
|
37
|
|
|
(39)
|
|
|
Cash and cash equivalents,
beginning of period
|
|
|
39
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end
of period
|
|
$
|
76
|
|
$
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 of 2011 stated without the
effect of certain items to net income is shown below:
|
|
|
|
|
|
|
|
|
4Q11
|
|
|
|
|
|
|
|
(in
millions)
|
|
|
|
Net income
|
$
|
68
|
|
|
|
|
Net unrealized loss on commodity
derivatives(1)
|
|
93
|
|
|
|
|
Income tax adjustment for above
items
|
|
(34)
|
|
|
|
Earnings stated without the
effect of the above items
|
$
|
127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) The determination of
"Net unrealized loss on commodity derivatives" for the fourth
quarter 2011 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4Q11
|
|
|
|
|
|
|
|
(in
millions)
|
|
|
Commodity derivative
expense
|
$
|
(54)
|
|
|
Cash receipts on derivative
settlements, net
|
|
(39)
|
|
|
|
|
Net unrealized loss on commodity
derivatives
|
$
|
(93)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
4Q11
|
|
2011
|
|
|
|
|
(in
millions)
|
|
Net cash provided by operating
activities
|
|
$
|
416
|
|
$
|
1,589
|
|
|
Net change in operating
assets and liabilities
|
|
|
(29)
|
|
|
(40)
|
|
Net cash provided by operating
activities before changes
|
|
|
|
|
|
|
|
|
in operating assets and
liabilities
|
|
$
|
387
|
|
$
|
1,549
|
|
|
|
|
|
|
|
|
|
|
|
SOURCE Newfield Exploration Company