Newfield Reports First Quarter 2010 Results

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Apr 27, 2010, 05:48 ET

HOUSTON, April 27 /PRNewswire-FirstCall/ -- Newfield Exploration Company (NYSE: NFX) today reported its unaudited first quarter 2010 financial results. A separate operational update was released on April 26 and this release and the operational update release are available through the investor relations section of our website at http://www.newfield.com. Newfield will be hosting a conference call at 7:30 a.m. (CDT) on April 28. To participate in the call, dial 719-457-2731 or listen through the investor relations section of our website at http://www.newfield.com.

For the first quarter of 2010, Newfield recorded net income of $244 million, or $1.84 per diluted share (all per share amounts are on a diluted basis). Net income includes the effect of these items:

a net unrealized gain on commodity derivatives of $143 million ($91 million after-tax); and
an early redemption charge of $10 million ($6 million after-tax) associated with the purchase and payment of approximately $143 million of our $175 million aggregate principal amount of 7 5/8% Senior Notes due 2011 offset by a gain of $2 million ($1 million after-tax) resulting from the termination of the associated interest rate swap.

Without the effect of these items, net income for the first quarter of 2010 would have been $158 million, or $1.19 per share.

Revenues in the first quarter of 2010 were $458 million. Net cash provided by operating activities before changes in operating assets and liabilities was $393 million. See “Explanation and Reconciliation of Non-GAAP Financial Measures” found after the financial statements in this release.

Newfield’s production in the first quarter of 2010 was 67 Bcfe. Natural gas production in the first quarter of 2010 was 48 Bcf, an average of 533 MMcf/d. Newfield’s oil liftings in the first quarter of 2010 were 3.2 MMBbls, an average of approximately 35,550 BOPD. Capital expenditures in the first quarter of 2010 were approximately $360 million, excluding the previously announced $215 million acquisition of properties in the Maverick Basin from TXCO Resources Inc. (closed February 2010).

2010 Outlook

On Monday, Newfield announced that the Company intends to allocate additional capital in 2010 to its ongoing oil activities in the Uinta and Williston Basins. Newfield now expects to invest approximately $700 million in oil projects in 2010, or nearly 45% of its total budget. At current oil prices, Newfield’s growing crude oil volumes are expected to account for approximately 60% of 2010 revenues.

As a result of the re-allocation in expenditures, the Company’s 2010 domestic crude oil production is expected to increase throughout the remainder of 2010 and is expected to be at least 20% above 2009 domestic oil production. Spending reductions in planned gas development programs will offset these new oil investments. Newfield maintains its capital budget of $1.6 billion.

For the full year 2010, Newfield expects that its production will be in the upper half of its previous production guidance of 278 – 288 Bcfe, representing an expected increase of at least 10% over 2009 volumes. An intentional reduction in natural gas volumes in the second half of 2010 should be more than offset by our growing crude oil volumes.

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 second quarter and full year 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: [email protected]

1Q10 Actual Results
	1Q10 Actual
	Domestic		Int'l		Total
Production/Liftings
Natural gas – Bcf	48.0		–		48.0
Oil and condensate – MMBbls	1.8		1.4		3.2
Total Bcfe	58.6		8.4		67.0

Average Realized Prices (Note 1)
Natural gas – $/Mcf	$	6.34	$	–	$	6.34
Oil and condensate – $/Bbl	$	88.38	$	70.50	$	80.45
Mcf equivalent – $/Mcfe	$	7.91	$	11.75	$	8.40

Operating Expenses: (Note 2)
Lease operating
Recurring ($MM)	$	49.9	$	10.0	$	59.9
per/Mcfe	$	0.87	$	1.20	$	0.91
Major (workovers, repairs, etc.) ($MM)	$	6.0	$	1.2	$	7.2
per/Mcfe	$	0.10	$	0.14	$	0.11

Production and other taxes ($MM)	$	15.4	$	9.3	$	24.7
per/Mcfe	$	0.27	$	1.10	$	0.38

General and administrative (G&A), net ($MM)	$	35.5	$	0.9	$	36.4
per/Mcfe	$	0.62	$	0.11	$	0.55

Capitalized internal costs ($MM)					$	(20.3)
per/Mcfe					$	(0.31)

Interest expense ($MM)					$	37.7
per/Mcfe					$	0.57

Capitalized interest ($MM)					$	(12.3)
per/Mcfe					$	(0.19)

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 $5.04 per Mcf and the total oil and condensate average realized price would have been $69.82 per barrel. Note 2: Recurring lease operating expense includes transportation expense.

2Q10 & FY10 Estimates
	2Q10 & FY10 Estimates
	Domestic		Int'l		Total
Production/Liftings	2Q10	FY10	2Q10	FY10	2Q10	FY10
Natural gas – Bcf	50 – 52	199 – 202	–	–	50 – 52	199 – 202
Oil and condensate – MMBbls	1.9 – 2.0	8.5 – 8.7	1.4 – 1.5	5.6 – 5.7	3.3 – 3.5	14.1 – 14.4
Total Bcfe	62 – 64	250 – 254	8 – 9	33 – 34	70 – 73	283 – 288

Average Realized Prices
Natural gas – $/Mcf	Note 1	Note 1
Oil and condensate – $/Bbl	Note 2	Note 2	Note 3	Note 3
Mcf equivalent – $/Mcfe

Operating Expenses:
Lease operating
Recurring ($MM)	$35 - $39	$148 - $157	$12 - $14	$43 - $45	$47 - $53	$191 - $202
per/Mcfe	$0.57 - $0.61	$0.59 - $0.62	$1.43 - $1.48	$1.30 - $1.34	$0.67 - $0.72	$0.67 - $0.72
Transportation ($MM)	$18 - $20	$70 - $73	-	-	$18 - $20	$70 - $73
per/Mcfe	$0.25 - $0.27	$0.28 - $0.29	-	-	$0.25 - $0.27	$0.28 - $0.29
Recurring w/ trans ($MM)	$53 - $59	$218 - $230	$12 - $14	$43 - $45	$65 - $73	$261 - $275
per/Mcfe	$0.86 - $0.92	$0.87 - $0.92	$1.43 - $1.48	$1.30 - $1.34	$0.93 - $0.99	$0.93 - $0.97
Major (workovers, etc.) ($MM)	$15 - $20	$34 - $38	$2 - $4	$20 - $22	$17 - $24	$54 - $60
per/Mcfe	$0.26 - $0.28	$0.14 - $0.15	$0.34 - $0.36	$0.61 - $0.64	$0.27 - $0.29	$0.19 - $0.20

Production/Taxes ($MM) (Note 4)	$15 - $18	$59 - $72	$15 - $19	$53 - $65	$30 - $37	$112 - $137
per/Mcfe	$0.25 - $0.26	$0.25 - $0.27	$1.93 - $1.97	$1.73 - $1.76	$0.46 - $0.47	$0.42 - $0.45

G&A, net ($MM)	$31 - $37	$129 - $143	$1 - $2	$4 - $5	$32 - $39	$133 - $148
per/Mcfe	$0.54 - $0.55	$0.54 - $0.55	$0.13 - $0.14	$0.12 - $0.13	$0.49 - $0.50	$0.49 - $0.50

Capitalized internal costs ($MM)					($19 - $23)	($75 - $92)
per/Mcfe					($0.29 - $0.30)	($0.29 - $0.30)

Interest expense ($MM)					$35 - $43	$137 - $168
per/Mcfe					$0.54 - $0.55	$0.53 - $0.54

Capitalized interest ($MM)					($11 - $13)	($41 - $51)
per/Mcfe					($0.16 - $0.17)	($0.15 - $0.16)

Tax rate (%) (Note 5)					35% - 37%	35% - 37%

Income taxes (%)
Current					14% - 16%	14% - 16%
Deferred					84% - 86%	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 88-92% 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 $75/Bbl oil and $5.00/MMBtu gas.
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 March 31,
	2010	2009

Oil and gas revenues	$ 458	$ 262

Operating expenses:
Lease operating	67	71
Production and other taxes	25	9
Depreciation, depletion and amortization	147	159
General and administrative	36	32
Ceiling test writedown	—	1,344
Other	8	2
Total operating expenses	283	1,617

Income (loss) from operations	175	(1,355)

Other income (expenses):
Interest expense	(38)	(32)
Capitalized interest	12	14
Commodity derivative income	237	278
Other	2	3
Total other income (expenses)	213	263

Income (loss) before income taxes	388	(1,092)

Income tax provision (benefit)	144	(398)

Net income (loss)	$ 244	$ (694)

Income (loss) per share:
Basic --	$ 1.87	$ (5.35)

Diluted --	$ 1.84	$ (5.35)

Weighted average number of shares outstanding or basic income (loss) per share	130	130
Weighted average number of shares outstanding for diluted income (loss) per share *	133	130
* Had we recognized net income for the three month period ended March 31, 2009, the weighted average number of shares outstanding for the computation of diluted earnings per share would have increased by 1 million shares


CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited, in millions)	March 31, 2010	December 31, 2009

ASSETS
Current assets:
Cash and cash equivalents	$ 112	$ 78
Derivative assets	349	269
Other current assets	517	546
Total current assets	978	893

Property and equipment, net (full cost method)	5,671	5,247
Derivative assets	75	19
Other assets	103	95
Total assets	$ 6,827	$ 6,254

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities	$ 890	$ 873
Current debt	32	—
Total current liabilities	922	873

Other liabilities	159	142
Long-term debt	2,189	2,037
Deferred taxes	537	434
Total long-term liabilities	2,885	2,613

Commitments and contingencies	—	—

STOCKHOLDERS' EQUITY
Common stock	1	1
Additional paid-in capital	1,410	1,389
Treasury stock	(47)	(33)
Accumulated other comprehensive loss	(10)	(11)
Retained earnings	1,666	1,422
Total stockholders' equity	3,020	2,768
Total liabilities and stockholders' equity	$ 6,827	$ 6,254


CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited, in millions)	For the Three Months Ended March 31,
	2010	2009
Cash flows from operating activities:
Net income (loss)	$ 244	$ (694)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	147	159
Deferred tax provision (benefit)	131	(403)
Stock-based compensation	6	8
Ceiling test writedown	—	1,344
Commodity derivative income	(237)	(278)
Cash receipts on derivative settlements	102	211
	393	347
Changes in operating assets and liabilities	21	2
Net cash provided by operating activities	414	349

Cash flows from investing activities:
Additions to oil and gas properties and other, net	(340)	(405)
Acquisitions of oil and gas properties	(217)	(9)
Redemptions of investments	1	7
Net cash used in investing activities	(556)	(407)

Cash flows from financing activities:
Net proceeds (repayments) under credit arrangements	(364)	73
Net proceeds from issuance of senior subordinated notes	686	—
Repayment of senior notes	(143)	—
Other	(3)	(1)
Net cash provided by financing activities	176	72


Increase in cash and cash equivalents	34	14
Cash and cash equivalents, beginning of period	78	24

Cash and cash equivalents, end of period	$ 112	$ 38

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 first quarter of 2010 stated without the effect of certain items to net income is shown below:

	1Q10
	(in millions)
Net income	$ 244
Net unrealized gain on commodity derivatives (1)	(143)
Early redemption charge	10
Termination of interest rate swap	(2)
Income tax adjustment for above items	49
Earnings stated without the effect of the above items	$ 158

(1) The determination of "Net unrealized gain on commodity derivatives" for the first quarter of 2010 is as follows:

	1Q10
	(in millions)
Commodity derivative income	$ 237
Cash receipts on derivative settlements	(102)
Option premiums associated with derivatives settled during the period	8
Net unrealized gain on commodity derivatives	$ 143

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:

	1Q10
	(in millions)
Net cash provided by operating activities	$ 414
Net change in operating assets and liabilities	(21)
Net cash provided by operating activities before changes in operating assets and liabilities	$ 393