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Newfield Reports Third Quarter 2011 Financial and Operating Results

Company reiterates $1.9B capital budget, adjusts 2011 Production Guidance
3Q oil production up nearly 30% over prior year
Recent deep Wasatch wells test >1,000 BOEPD gross

HOUSTON, Oct. 19, 2011 /PRNewswire via COMTEX/ --

Newfield Exploration Company (NYSE: NFX) today reported its unaudited third quarter 2011 financial and operating results. In addition, the Company also adjusted its 2011 production guidance and reaffirmed its 2011 capital budget. Newfield will host a conference call at 8 a.m. CT on October 20, 2011. To participate in the call, dial 719-325-4921 or listen through the investor relations section of our website at http://www.newfield.com.

For the third quarter of 2011, Newfield recorded net income of $269 million, or $1.99 per diluted share (all per share amounts are on a diluted basis). Net income for the third quarter includes a net unrealized gain on commodity derivatives of $201 million ($129 million after-tax), or $0.95 per share. Without the effect of this item, net income for the third quarter of 2011 would have been $140 million, or $1.04 per share.

Revenues in the third quarter of 2011 were $628 million. Net cash provided by operating activities before changes in operating assets and liabilities was $409 million. See "Explanation and Reconciliation of Non-GAAP Financial Measures" found after the financial statements in this release.

Newfield's production in the third quarter of 2011 was 75.8 Bcfe. Natural gas production in the third quarter of 2011 was 45.4 Bcf, an average of approximately 494 MMcf/d. Newfield's oil liftings and liquids production in the third quarter of 2011 was 5.1 MMBbls, or an average of approximately 55,000 BOEPD. Capital expenditures in the third quarter of 2011 were approximately $679 million.

2011 Production Guidance

Newfield today adjusted its full year 2011 production guidance to 300 - 304 Bcfe (previous guidance was 312 - 316 Bcfe). Reconciliation to previous guidance is shown in the table below:


BCFE

Previous Guidance

312-316

3Q Adjustments to Guidance


Williston Basin deferred completions / other

(6)

Reduced capital expenditures

(3)

Non-strategic asset sales

(2)

Gulf of Mexico weather

(1)

Current Guidance

300-304*

*Includes approximately 4 Bcfe of production associated with new offshore developments in Malaysia and the Gulf of Mexico.

"We will simplify our game plan in 2012 and ensure that our best people and projects are aligned," said Lee K. Boothby, Chairman, President and CEO. "We are driving oil growth from fewer projects and I am confident in our ability to deliver and am excited about the opportunities ahead of us."

2011 Capital Investments, Asset Sales

Newfield reiterated its 2011 capital budget of $1.9 billion, excluding capitalized interest and overhead and approximately $300 million in acquisitions. Proceeds from non-strategic asset sales year-to-date are approximately $200 million. The Company continues to market other certain non-strategic domestic assets with expected total proceeds for the year possibly reaching $400 - $550 million.

Operating Highlights:

Rocky Mountains

Uinta Basin

Newfield has approximately 250,000 net acres in the Uinta Basin, where gross production recently reached a high of 24,500 BOPD.

The Company recently completed several additional Wasatch wells in the Central Basin, an area located immediately north of its Monument Butte field. Notable completions include the Lamb 1-19-3-1W, which had 24-hour gross initial production of 1,168 BOEPD and a 30-day gross average of 617 BOEPD, the Padilla 1-18-3-2W, which had 24-hour gross initial production of 1,102 BOEPD and the Miles 15-8-3-2, which had 24-hour gross initial production of approximately 850 BOEPD. A recent "best in class" deep Wasatch well was drilled and cased in 13 days from spud to rig release. The Company plans to complete five additional Wasatch wells in the fourth quarter.

Newfield has drilled seven horizontal wells in the Uteland Butte to date and four additional wells are planned before year end. Initial gross 24-hour production rates from the first six wells averaged approximately 500 BOEPD. The 14-14T well has averaged more than 200 BOEPD (gross) over its first four months of production.

With the ongoing optimization of the drilling campaign, the Company expects to increase its operated rig count from an average historical five-rig program to at least eight rigs in 2012. As a result, oil production growth from the region is expected to increase more than 25% in 2012 over 2011.

Williston Basin

In response to service cost pressures, Newfield is voluntarily reducing its activities in the Williston Basin. The Company has reduced its operated rig count and is deferring 13 completions into early 2012. Well production performance continues to be at or above expectations.

Substantially all of the recent completions were super extended laterals. The table below shows notable recent wells drilled and completed on average for approximately $11 million:

WELL

LOCATION

LATERAL LENGTH

24-HOUR GROSS IP RATE (BOEPD)

30-DAY GROSS CUMULATIVE (BOE)

Wisness Federal

Westberg

5,320'

5,198

52,583

Lawlar

Watford

9,569'

3,880

42,355

Holm

Watford

9,434'

3,217

38,393

Hoffman

Watford

9,081'

3,345

37,853

Staal

Watford

9,490'

4,014

43,637

Southern Alberta Basin

Newfield is nearing completion of its 2011 assessment program in the Southern Alberta Basin of northern Montana. To date, the Company has drilled seven vertical wells, two horizontal wells and is in the process of testing several vertical completions.

The Company's first horizontal well had initial gross production of approximately 225 BOEPD with less than one-third of the lateral producing. The second horizontal well was not fracture stimulated. Newfield's average working interest is approximately 85%.

To date, three of the vertical wells have been tested and flowed low volumes of oil. Newfield's work program to date satisfies about 80% of its commitments to hold its 340,000 acre position for a five-year period.

Mid-Continent

Woodford Shale

Newfield recently completed an additional seven wells in the "oily" portion of its Woodford Shale play, located in the Arkoma Basin of Oklahoma. To date, the Company has completed a total of 13 wells with an average 24-hour gross IP rate of more than 1,000 BOEPD. Average working interest for the 13 wells is approximately 90%.

Granite Wash

Newfield's production in the Granite Wash play located in the Texas Panhandle is approximately 170 MMcfe/d gross (120 MMcfe/d net). The Company is currently running three operated rigs in the Granite Wash with its activities primarily located in Wheeler County, Texas. To date, the Company has completed 57 wells in the Texas Panhandle portion of the play with 24-hour gross initial production averaging approximately 15 MMcfe/d. Newfield's average working interest in the play is approximately 80%.

Onshore Texas

Maverick Basin

Newfield continues to explore and assess its 335,000 net acre position in the Maverick Basin of South Texas. Recent drilling activity in the Eagle Ford Shale has focused on the "southern" portion of the Company's acreage along existing infrastructure. A pilot program in the West Asherton area (Dimmitt County, Texas) is underway with recent wells being drilled from pad locations to help determine optimal development spacing. To date, Newfield has completed 16 wells in West Asherton with average 24-hour gross initial production of 650 BOEPD. Estimated ultimate recovery from these wells is approximately 300 MBOE. The wells have been drilled in as few as seven days and gross completed well costs have averaged approximately $6.6 million.

Year-to-date, the Company has completed 24 wells in the Eagle Ford Shale, six wells in the Georgetown formation and two wells in the Pearsall Shale. Current gross production from the Maverick Basin is approximately 7,000 BOEPD. Newfield's average working interest in the region is approximately 80%.

International Oil Developments

Third quarter 2011 net liftings from the Company's oil assets in Southeast Asia were 1.6 MMBbls, or an average of about 17,400 BOPD. Net liftings in Malaysia during the period averaged approximately 15,700 BOPD. On PM 329, the East Piatu development is expected to commence production later this week at about 10,000 BOPD (gross). Newfield has a 70% interest in East Piatu.

Deepwater Gulf of Mexico

The Company's deepwater Gulf of Mexico net production in the third quarter of 2011 was 6.7 Bcfe, or approximately 75 MMcfe/d. Pyrenees, located at Garden Banks 293, is expected to commence production in December 2011 at approximately 50 MMcf/d and 2,400 BCPD gross with a 40% working interest.

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, Appalachia 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 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 from its Monument Butte field in Utah, 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 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

3Q11 Actual Results



3Q11 Actual


Domestic

Int'l

Total

Production/Liftings




Natural gas - Bcf

45.4

-

45.4

Oil, condensate and NGLs - MMBbls

3.4

1.7

5.1

Total Bcfe

65.8

10.1

75.8





Average Realized Prices Note 1




Natural gas - $/Mcf

$

5.72

$

-

$

5.72

Oil, condensate and NGLs - $/Bbl

$

74.56

$

109.62

$

86.16

Mcf equivalent - $/Mcfe

$

7.87

$

18.27

$

9.28








Operating Expenses:







Lease operating ($MM)







Recurring

$

60.7

$

18.1

$

78.8

Major (workovers, etc.)

$

10.3

$

3.8

$

14.1

Transportation

$

22.3

$

-

$

22.3








Lease operating (per Mcfe)







Recurring

$

0.94

$

1.80

$

1.06

Major (workovers, etc.)

$

0.16

$

0.38

$

0.19

Transportation

$

0.35

$

-

$

0.30








Production and other taxes ($MM)

$

18.5

$

76.8

$

95.3

per/Mcfe

$

0.29

$

7.63

$

1.28








General and administrative (G&A), net ($MM)

$

49.1

$

1.4

$

50.5

per/Mcfe

$

0.76

$

0.14

$

0.68








Capitalized internal costs ($MM)





$

(29.7)

per/Mcfe





$

(0.40)








Interest Expense ($MM)





$

42.5

per/Mcfe





$

0.57








Capitalized Interest ($MM)





$

(23.6)

per/Mcfe





$

(0.32)









Note 1:

Average realized prices include the effects of hedging contracts. If the effects of these contracts were excluded, the average realized price for consolidated gas would have been $4.22 per Mcf and the domestic and consolidated oil and condensate average realized prices would have been $75.99 and $87.12 per barrel, respectively.



4Q11 & FY11 Estimates


Domestic

Int'l

Total

Production/Liftings

4QE

FY11

4QE

FY11

4QE

FY11

Natural gas - Bcf

46 - 48

183 - 186

0.2 - 0.2

0.2 - 0.2

46 - 48

183 - 186

Oil, condensate and NGLs - MMBbls

3.4 - 3.7

12.8 - 13.1

2.1 - 2.3

6.4 - 6.7

5.6 - 5.9

19.4 - 19.7

Total Bcfe

66 - 70

260 - 264

13 - 14

39 - 41

79 - 84

300 - 304








Average Realized Prices







Natural gas - $/Mcf

Note 1

Note 1





Oil, condensate and NGLs - $/Bbl

Note 2

Note 2

Note 3

Note 3



Mcf equivalent - $/Mcfe














Operating Expenses (per Mcfe):







Lease Operating







Recurring

$0.78 - $0.94

$0.83 - $0.88

$1.54 - $1.93

$1.73 - $1.86

$0.91 - $1.11

$0.95 - $1.01

Major (workovers, etc.)

$0.17 - $0.23

$0.15 - $0.16

$0.34 - $0.44

$0.72 - $0.76

$0.19 - $0.27

$0.22 - $0.24

Transportation

$0.33 - $0.44

$0.34 - $0.37

-

-

$0.28 - $0.37

$0.30 - $0.32








Production/Taxes Note 4

$0.26 - $0.34

$0.28 - $0.30

$4.85 - $6.28

$6.39 - $6.87

$1.01 - $1.31

$1.08 - $1.17








G&A, net

$0.63 - $0.76

$0.65 - $0.69

$0.12 - $0.16

$0.14 - $0.15

$0.55 - $0.65

$0.59 - $0.61








Capitalized internal costs





($0.33 - $0.40)

($0.34 - $0.38)








Interest Expense





$0.60 - $0.64

$0.56 - $0.59








Capitalized Interest





($0.23 - $0.29)

($0.25 - $0.29)








Tax rate (%)Note 5





36% - 38%

36% - 38%








Income taxes (%)







Current





18% - 22%

18% - 22%

Deferred





78% - 82%

78% - 82%








Note 1:

The price that the Company receives 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 90-95% of the Henry Hub Index.

Note 2:

The price the Company receives for its Gulf Coast oil production, excluding NGLs, typically averages about 105-110% of the NYMEX West Texas Intermediate (WTI) price. The price the Company receives for its oil production in the Rocky Mountains, excluding NGLs, is currently averaging $15-17 per barrel below the WTI price. Oil production from the Company's Mid-Continent properties, excluding NGLs, typically averages 90-95% of the WTI price.

Note 3:

Oil from the Company's operations in Malaysia typically sells at a slight discount to Tapis, or about 125-130% of the WTI price. Oil from the Company's operations in China typically sells $23-28 per barrel higher than the WTI price.

Note 4:

Guidance for production taxes determined using the average of the strip at 09/22/11 ($80.62/bbl, $3.84/mcf).

Note 5:

Tax rate applied to earnings excluding unrealized gains or losses on commodity derivatives.



CONSOLIDATED STATEMENT OF INCOME

(Unaudited, in millions, except per share data)

For the Three

Months Ended

September 30,


For theNine

Months Ended

September 30,


2011


2010


2011


2010









Oil and gas revenues

$ 628


$ 449


$ 1,794


$ 1,355









Operating expenses:








Lease operating

115


86


333


237

Production and other taxes

95


21


245


77

Depreciation, depletion and amortization

189


156


528


463

General and administrative

51


40


132


117

Other

-


-


-


10

Total operating expenses

450


303


1,238


904









Income from operations

178


146


556


451









Other income (expenses):








Interest expense

(43)


(39)


(124)


(116)

Capitalized interest

24


15


61


43

Commodity derivative income

262


131


249


414

Other

3


1


2


2

Total other income

246


108


188


343









Income before income taxes

424


254


744


794









Income tax provision

155


93


273


293









Net income

$ 269


$ 161


$ 471


$ 501









Earnings per share:








Basic --

$ 2.00


$ 1.22


$ 3.52


$ 3.80









Diluted --

$ 1.99


$ 1.20


$ 3.49


$ 3.75









Weighted-average number of shares outstanding

for basic earnings per share

134


132


134


132

Weighted-average number of shares outstanding

for diluted earnings per share

135


134



135


134





CONDENSED CONSOLIDATED BALANCE SHEET

(Unaudited, in millions)

September 30,

2011


December 31,

2010





ASSETS




Current assets:




Cash and cash equivalents

$ 31


$ 39

Derivative assets

170


197

Other current assets

507


495

Total current assets

708


731





Property and equipment, net (full cost method)

7,994


6,608

Derivative assets

67


39

Other assets

134


116

Total assets

$ 8,903


$ 7,494





LIABILITIES AND STOCKHOLDERS' EQUITY




Current liabilities:




Current liabilities

$ 967


$ 875

Derivative liabilities

6


53

Total current liabilities

973


928





Other liabilities

161


153

Derivative liabilities

1


46

Long-term debt

2,985


2,304

Deferred taxes

945


720

Total long-term liabilities

4,092


3,223









STOCKHOLDERS' EQUITY




Common stock and additional paid-in capital

1,432


1,410

Accumulated other comprehensive loss

(10)


(12)

Retained earnings

2,416


1,945

Total stockholders' equity

3,838


3,343

Total liabilities and stockholders' equity

$ 8,903


$ 7,494



CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited, in millions)

For the

Nine Months Ended

September 30,


2011


2010

Cash flows from operating activities:




Net income

$ 471


$ 501

Adjustments to reconcile net income to net cash provided by operating activities:




Depreciation, depletion and amortization

528


463

Deferred tax provision

234


259

Stock-based compensation

20


16

Commodity derivative income

(249)


(414)

Cash receipts on derivative settlements, net

156


345

Other non-cash charges

2


3


1,162


1,173

Net changes in operating assets and liabilities

11


134

Net cash provided by operating activities

1,173


1,307





Cash flows from investing activities:




Additions to oil and gas properties and other, net

(1,746)


(1,202)

Acquisitions of oil and gas properties

(299)


(209)

Proceeds from sales of oil and gas properties

202


14

Redemptions of investments

1


5

Net cash used in investing activities

(1,842)


(1,392)





Cash flows from financing activities:




Net proceeds (repayments) under credit arrangements

(69)


(384)

Net proceeds from issuance of senior notes

750


--

Net proceeds from issuance of senior subordinated notes

--


694

Repayment of senior notes

--


(175)

Other

(20)


--

Net cash provided by financing activities

661


135









Increase (decrease) in cash and cash equivalents

(8)


50

Cash and cash equivalents, beginning of period

39


78





Cash and cash equivalents, end of period

$ 31


$ 128


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 third quarter of 2011 stated without the effect of certain items to net income is shown below:



3Q11




(in millions)


Net income

$ 269



Net unrealized gain on commodity derivatives (1)

(201)



Income tax adjustment for above item

72



Earnings stated without the effect of the above items

$ 140




(1) The determination of "Net unrealized gain on commodity derivatives" for the third quarter of 2011 is as follows:



3Q11




(in millions)


Commodity derivative income

$ 262



Cash receipts on derivative settlements, net

(61)



Net unrealized gain on commodity derivatives

$ 201




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:



3Q11




(in millions)


Net cash provided by operating activities

$ 444



Net change in operating assets and liabilities

(35)



Net cash provided by operating activities before changes in operating assets and liabilities

$ 409




SOURCE Newfield Exploration Company