Fourth Quarter 2008
For the fourth quarter of 2008, Newfield recorded a net loss of $789 million, or $6.09 per diluted share (all per share amounts are on a diluted basis). The loss reflects the following items:
- a $1.8 billion ($1.2 billion after-tax), or $8.82 per share, reduction in the carrying value of oil and gas properties due to significantly lower commodity prices at year-end 2008. This non-cash adjustment resulted from the application of full cost accounting rules;
- a net unrealized gain on commodity derivatives of $623 million ($401 million after-tax), or $3.07 per share;
- a goodwill impairment of $62 million or $0.48 per share.
Without the effect of the above items, net income for the fourth quarter of 2008 would have been $26 million, or $0.20 per share.
Revenues in the fourth quarter of 2008 were $338 million. Net cash provided by operating activities before changes in operating assets and liabilities was $243 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 2008 was 62 Bcfe. Capital expenditures in the fourth quarter of 2008 were $533 million.
Full Year 2008
For the full year 2008, Newfield reported a net loss of $373 million, or $2.88 per diluted share. The loss reflects the following items:
- a $1.8 billion ($1.2 billion after-tax), or $8.75 per share, reduction in the carrying value of oil and gas properties due to significantly lower commodity prices at year-end 2008. This non-cash adjustment resulted from the application of full cost accounting rules;
- a net unrealized gain on commodity derivatives of $665 million ($429 million after-tax), or $3.25 per share;
- a goodwill impairment of $62 million or $0.47 per share.
Without the effect of the above items, net income for 2008 would have been $415 million, or $3.14 per share.
Revenues for 2008 were $2.2 billion. Net cash provided by operating activities before changes in operating assets and liabilities was $857 million. 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 2008 was 236 Bcfe, an increase of 24% over 2007 volumes (adjusted for asset sales and acquisitions). Capital expenditures in 2008 were approximately $2.3 billion.
- Proved Reserves Increase 18% to 2.95 Tcfe at Year-End 2008 - Newfield added 758 Bcfe in 2008, stated before negative price related reserve revisions of 66 Bcfe. Reserve Life Index of approximately 13 years reflects continued growth in longer-lived "resource plays." (See news release dated January 29, 2009 for details)
- Approximately 75% of Total Year-End Reserves Located in Resource Plays - Mid-Continent and Rocky Mountain divisions posted combined reserve growth of 21%. Newfield has significant inventory of development drilling locations. Nearly two-thirds of 2009 capital budget allocated to these regions.
- Most Significant Reserve Additions Came in Mid-Continent Division - Newfield's Mid-Continent division reserves grew 26%. Division now comprises nearly 50% of total Company reserves. Reserves in the Mid-Continent region were added for finding and development costs of $1.80 per Mcfe, excluding the negative impact of price-related reserve revisions, and $2.02 per Mcfe including these revisions. See "Finding and Development Costs" found after the financial statements in this release.
- Woodford Shale Sets Production Record in Fourth Quarter 2008 - In mid-December 2008, gross operated production exceeded Newfield's year-end goal of 250 MMcfe/d. Total Woodford production volumes in 2008 increased 65% over 2007. Benefit of efficiency gains expected to grow production an additional 30% in 2009, despite running fewer operated rigs. A complete Woodford Shale update can be found in today's edition of the Company's @NFX publication on the website at http://www.newfield.com.
- Success with Initial Dual Lateral Woodford Completion - Newfield's first dual lateral completion in the Woodford had an initial gross production rate of 13 MMcfe/d and is currently producing 6 MMcfe/d after nearly three months of production. Each lateral was approximately 4,250 feet in length.
- Stiles Ranch Field Achieves Record Production - Production from the Stiles Ranch Field, located in the Texas Panhandle, recently reached a record gross production rate of 130 MMcfe/d. Newfield has an approximate 80% interest in the field.
- Monument Butte Field Benefits from Increased Activity Levels in 2008 -
- 2008 gross production grew 17% over 2007 levels, reaching 17,000 BOPD in late 2008.
- The Company has drilled 124 wells on 20-acre spacing in its Monument Butte Field, located in the Uinta Basin of the Rocky Mountains. The Company expects to drill more than 3,000 development wells to fully develop the field. Newfield has drilled more than 900 wells in the field since acquiring it in 2004.
- During 2007 and 2008, Newfield added 45,000 net acres north and adjacent to Monument Butte. The lands are owned by the Ute Tribe. Newfield has drilled 44 successful wells on this acreage out of 45 attempts to date. Results have been consistent with drilling in the main field area.
- The Company remains encouraged with our deep gas drilling beneath Monument Butte. The Company drilled six successful wells in 2008 to test the Wasatch, Mesa Verde, Blackhawk and Mancos Shale beneath the Monument Butte Field. Half of these wells were covered under a deep gas exploration agreement signed in late 2008 that allows for promoted exploratory drilling and progressive earning in approximately 71,000 net acres in which Newfield will retain a greater than 70% interest. The remaining three wells were drilled in the eastern portion of the field (covers 10,000 acres) where Newfield is operator and retains an 86% interest. Although results have been positive, the Company investments in this play in 2009 have been substantially curtailed due to commodity prices and our capital budget.
- Continued Positive Drilling Results from Williston Basin - Since 2007, Newfield has added more than 400,000 net acres in the Williston Basin. In 2008, the Company focused on assessing this acreage position, building an inventory of prospects and adding new acreage. Recent drilling has been focused in North Dakota on the southern end of the Nesson Anticline. Complete drilling results can be found in @NFX.
- Four Deepwater Gulf of Mexico Discoveries in 2008/early 2009 - Developments underway expected to generate significant production growth over the next three years. Newfield is currently drilling the first of two back-to-back deepwater wells.
- Malaysian Production Increases 145% in 2008 - All of Newfield's shallow water fields on PM 318 and PM 323 are now on-line. Although planned international activity levels have been reduced in 2009 due to capital budget constraints, production is expected to increase 10% over 2008 levels.
2009 Capital Budget, Hedging and Liquidity
As previously announced, Newfield's 2009 capital budget is aligned with anticipated cash flow and was set at $1.45 billion (including capitalized interest and overhead). As a comparison, Newfield invested $2.3 billion in 2008, including $236 million in acquisitions and $129 million of capitalized interest and overhead. Newfield currently has approximately $640 million of borrowings outstanding under its $1.25 billion credit facility.
Newfield's estimate for 2009 cash flow is anchored by its substantial hedge position. Approximately 70% of the Company's expected 2009 gas production is hedged with an average minimum price of nearly $8 per Mcf. Substantially all of Newfield's 2009 domestic oil production is hedged with half of this amount fixed at about $129 per barrel and the remainder with a floor price of $107 per barrel.
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 Anadarko and Arkoma Basins of 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 2009 results, estimated 2009 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: firstname.lastname@example.org
4Q08 Actual Results 4Q08 Actual Domestic Int'l Total Production/Liftings Note 1 Natural gas - Bcf 43.9 - 43.9 Oil and condensate - MMBbl 1.6 1.5 3.1 Total Bcfe 53.4 8.9 62.3 Average Realized Prices Note 2 Natural gas - $/Mcf $5.47 $- $5.47 Oil and condensate - $/Bbl $39.74 $44.46 $42.03 Mcf equivalent - $/Mcfe $5.69 $7.41 $5.94 Operating Expenses: Lease operating Recurring ($MM) $50.3 $17.5 $67.8 per/Mcfe $0.94 $1.96 $1.09 Major ($MM) $13.7 $- $13.7 per/Mcfe $0.26 $- $0.22 Production and other taxes ($MM) Note 3 $(4.2) $7.4 $3.2 per/Mcfe $(0.08) $0.83 $0.05 General and administrative (G&A), net ($MM) $34.6 $0.9 $35.5 per/Mcfe $0.65 $0.11 $0.57 Capitalized internal costs ($MM) $(16.3) per/Mcfe $(0.26) Interest expense ($MM) $28.7 per/Mcfe $0.46 Capitalized interest ($MM) $(16.2) per/Mcfe $(0.26) Note 1: Reflects approximately 3 Bcfe of deferred domestic gas production related to GOM storms. 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 gas would have been $4.52 per Mcf and the total oil and condensate average realized price would have been $45.17 per barrel. Note 3: Domestic production and other taxes includes refunds related to production and severance tax exemptions on some of our onshore wells. 1Q09 Estimates 1Q09 Estimates Domestic Int'l Total Production/Liftings Note 1 Natural gas - Bcf 42.1 - 46.6 - 42.1 - 46.6 Oil and condensate - MMBbl 1.4 - 1.6 1.4 - 1.5 2.8 - 3.1 Total Bcfe 50.7 - 56.0 8.3 - 9.1 59.0 - 65.1 Average Realized Prices Natural gas - $/Mcf Note 2 Oil and condensate - $/Bbl Note 3 Note 4 Mcf equivalent - $/Mcfe Operating Expenses: Lease operating Recurring ($MM) $52.4 - $57.9 $15.2 - $16.8 $67.6 - $74.7 per/Mcfe $1.03 - $1.04 $1.83 - $1.85 $1.14 - $1.16 Major (workover, repairs, etc.) ($MM) $8.8 - $9.7 - $8.8 - $9.7 per/Mcfe $0.17 - $0.18 - $0.15 - $0.16 Production and other taxes ($MM) Note 5 $14.1 - $15.5 $5.1 - $5.7 $19.2 - $21.2 per/Mcfe $0.27 - $0.28 $0.61 - $0.63 $0.32 - $0.33 General and administrative (G&A), net ($MM) $32.7 - $36.1 $1.5 - $1.7 $34.2 - $37.8 per/Mcfe $0.64 - $0.65 $0.18 - $0.19 $0.57 - $0.59 Capitalized internal costs($MM) ($17.1 - $18.9) per/Mcfe ($0.28 - $0.30) Interest expense ($MM) $29.2 - $32.3 per/Mcfe $0.48 - $0.50 Capitalized interest ($MM) ($15.4 - $17.0) per/Mcfe ($0.25 - $0.27) Tax rate (%) Note 6 36% - 38% Income taxes (%) Current 14% - 16% Deferred 84% - 86% Note 1: Reflects approximately 1.75 Bcfe of deferred domestic gas production related to GOM storms. Note 2: Gas prices in the Mid-Continent, after basis differentials, transportation and handling charges, typically average 70 - 80% of the Henry Hub Index. Gas prices in the Gulf Coast, after basis differentials, transportation and handling charges, are expected to average $0.40 - $0.60 per MMBtu less than the Henry Hub Index. Note 3: Oil prices in the Gulf Coast typically average 90 - 95% of NYMEX WTI price. Rockies oil prices average about $12 - $14 per Barrel below WTI. Oil production from the Mid-Continent typically averages 96 - 98% of WTI. Note 4: Oil in Malaysia typically sells at a slight discount to Tapis, or about 90% of WTI. Oil production from China typically sells at $10 - $15 per barrel below WTI. Note 5: Guidance for production taxes determined using $50/Bbl oil and $5/MMBtu gas. Note 6: 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 For the Three Months Ended Twelve Months Ended December 31, December 31, 2008 2007 2008 2007 Oil and gas revenues $338 $398 $2,225 $1,783 Operating expenses: Lease operating 81 46 265 314 Production and other taxes 3 38 157 101 Depreciation, depletion and amortization 193 143 697 682 Ceiling test and other impairments 1,863 - 1,863 - General and administrative 36 47 141 155 Other 4 - 4 - Total operating expenses 2,180 274 3,127 1,252 Income (loss) from operations (1,842) 124 (902) 531 Other income (expenses): Interest expense (29) (22) (112) (102) Capitalized interest 17 12 60 47 Commodity derivative income (expense) 655 (145) 408 (188) Other 1 4 11 6 644 (151) 367 (237) Income (loss) from continuing operations before income taxes (1,198) (27) (535) 294 Income tax provision (benefit) (409) (2) (162) 122 Income (loss) from continuing operations (789) (25) (373) 172 Income from discontinued operations, net of tax - 338 - 278 Net income (loss) $(789) $313 $(373) $450 Earnings (loss) per share: Basic -- Income (loss) from continuing operations $(6.09) $(0.20) $(2.88) $1.35 Income from discontinued operations, net of tax - 2.63 - 2.17 $(6.09) $2.43 $(2.88) $3.52 Diluted -- Income (loss) from continuing operations $(6.09) $(0.19) $(2.88) $1.32 Income from discontinued operations, net of tax - 2.57 - 2.12 $(6.09) $2.38 $(2.88) $3.44 Weighted average number of shares outstanding for basic earnings (loss) per share 130 128 129 128 Weighted average number of shares outstanding for diluted earnings (loss) per share * 130 131 129 131 * Had we recorded net income for the three and twelve month periods ended December 31, 2008, the weighted average number of shares outstanding for the computation of diluted earnings per share would have been 131 million and 132 million, respectively. CONDENSED CONSOLIDATED BALANCE SHEET December 31, December 31, (Unaudited, in millions) 2008 2007 ASSETS Current assets: Cash and cash equivalents $24 $250 Short-term investments - 120 Derivative assets 688 72 Other current assets 519 485 Total current assets 1,231 927 Oil and gas properties, net (full cost method) 5,714 5,923 Derivative assets 222 17 Other assets 138 119 Total assets $7,305 $6,986 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities $1,093 $929 Other liabilities 92 322 Long-term debt 2,213 1,050 Deferred taxes 650 1,104 Total long-term liabilities 2,955 2,476 Commitments and contingencies - - STOCKHOLDERS' EQUITY Common stock 1 1 Additional paid-in capital 1,335 1,278 Treasury stock (32) (32) Accumulated other comprehensive loss (11) (3) Retained earnings 1,964 2,337 Total stockholders' equity 3,257 3,581 Total liabilities and stockholders' equity $7,305 $6,986 CONDENSED CONSOLIDATED STATEMENT For the OF CASH FLOWS Twelve Months Ended (Unaudited, in millions) December 31, 2008 2007 Cash flows from operating activities: Net income (loss) $(373) $450 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Income from discontinued operations, net of tax - (278) Depreciation, depletion and amortization 697 682 Ceiling test and other impairments 1,863 - Stock-based compensation 26 23 Commodity derivative (income) expense (408) 188 Cash (payments) receipts on derivative settlements (750) 180 Deferred tax provision (benefit) (198) 30 857 1,275 Changes in operating assets and liabilities (3) (109) Net cash provided by continuing activities 854 1,166 Net cash used in discontinued activities - (12) Net cash provided by operating activities 854 1,154 Cash flows from investing activities: Additions to oil and gas properties and other (2,087) (1,943) Acquisition of oil and gas properties (223) (658) Proceeds from (purchase price adjustment related to) sales of oil and gas properties 9 1,344 Proceeds from sale of UK subsidiaries, net of cash on hand at sale date - 491 Purchases of investments (22) (271) Redemption of investments 70 172 Net cash used in continuing activities (2,253) (865) Net cash used in discontinued activities - (41) Net cash used in investing activities (2,253) (906) Cash flows from financing activities: Net proceeds under credit arrangements 561 - Net proceeds from issuance of senior subordinated notes 592 - Repayment of senior notes - (125) Payments to discontinued operations - (38) Proceeds from issuances of common stock 21 32 Stock-based compensation excess tax benefit - 14 Purchases of treasury stock (1) - Net cash provided by (used in) continuing activities 1,173 (117) Net cash provided by discontinued activities - 38 Net cash provided by (used in) financing activities 1,173 (79) Effect of exchange rate changes on cash and cash equivalents - 1 Increase (decrease) in cash and cash equivalents (226) 170 Cash and cash equivalents from continuing operations, beginning of period 250 52 Cash and cash equivalents from discontinued operations, beginning of period - 28 Cash and cash equivalents, end of period $24 $250 Explanation and Reconciliation of Non-GAAP Financial Measures Earnings Stated Without the Effects of Certain Items Earnings stated without the effects of certain items is a non-GAAP financial measure. Earnings without the effects of these items are presented because they affect the comparability of operating results from period to period. In addition, earnings without the effects of these items are more comparable to earnings estimates provided by securities analysts. A reconciliation of earnings for the fourth quarter and full year 2008 stated without the effects of certain items to net income is shown below: 4Q08 2008 (in millions) Net loss $(789) $(373) Ceiling test writedowns 1,801 1,801 Goodwill impairment 62 62 Net unrealized gain on commodity derivatives (1) (623) (665) Income tax adjustment for above items (425) (410) Earnings stated without the effect of the above items $26 $415 (1) The determination of "Net unrealized gain on commodity derivatives" for the fourth quarter and full year 2008 are as follows: 4Q08 2008 (in millions) Commodity derivative income $655 $408 Cash payments (receipts) on derivative settlements (1) (33) 248 Option premiums associated with derivatives settled during the period 1 9 Net unrealized gain on commodity derivatives $623 $665 (1) 2008 excludes the $502 million payment to reset 2009-10 crude oil hedges. 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 (used in) 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: 4Q08 2008 (in millions) Net cash provided by operating activities $232 $854 Net change in operating assets and liabilities 11 3 Net cash provided by operating activities before changes in operating assets and liabilities $243 $857 Finding and Development Costs Newfield believes that the analysis of F&D cost is a useful tool in helping to evaluate capital productivity. We calculate F&D cost by dividing development, exploitation and exploration capital expenditures by reserve additions for the period. Acquisitions, land, seismic and asset retirement obligations are included in the calculation. Due to the significant drop in commodity prices in late 2008, we have presented the F&D costs in this release both including and excluding the impact of negative price-related reserve revisions to highlight the impact that the significant drop in prices during 2008 had on net reserve additions and to help provide comparability with F&D costs in prior periods. The metrics provided in this release should be read and utilized in conjunction with our financial statements which are prepared in accordance with generally accepted accounting principles and our Annual Report on Form 10-K.
SOURCE Newfield Exploration Company