"Our first quarter operating results were solid and we're off to a great
start in 2009, despite the macro-challenges in our industry today," said
First Quarter 2009
For the first quarter of 2009, Newfield recorded a net loss of
$1.3 billion( $854 millionafter-tax), or $6.59per 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. This non-cash adjustment resulted from the application of full cost accounting rules. Using the quarter-end natural gas price of $3.63per 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 Mountainregions; and
- a net unrealized gain on commodity derivatives of
$73 million( $49 millionafter-tax), or $0.38per share.
Without the effect of the above items, net income for the first quarter of
2009 would have been
Revenues in the first quarter of 2009 were
Newfield's production in the first quarter of 2009 was 63 Bcfe. Capital
expenditures in the first quarter of 2009 were
- Williston Basin Acreage Grows, Successful Drilling Results - Newfield
recently added an additional 14,400 net acres in the Williston Basin
North Dakota. The Company has approximately 500,000 net acres, with nearly 200,000 acres in prospective development areas. Newfield has drilled 10 successful oil wells in the Williston Basin and gross operated production is approximately 4,800 BOPD. Recent drilling has been focused in North Dakotaon the southern end of the Nesson Anticline. Results from the most recent wells are below:
- The Gladys 1-9H is a Bakken completion with a 24-hour average
gross initial production rate of 1,328 BOEPD. This was a 4,000'
lateral, located in McKenzie County,
North Dakota. Newfield operates the well with a 48% working interest.
- The Wisness 1-4H is a Bakken completion with a 24-hour average
gross initial production rate of 1,256 BOEPD. This was a 4,400'
lateral, located in McKenzie County,
North Dakota. Newfield operates the well with a 40% working interest.
- The Moberg 1-29H is currently drilling. The well is expected to
have an 8,500' lateral completion. The well, located in McKenzie
North Dakota, is operated by Newfield, with a 72% working interest.
- Mid-Continent Region Update - Gross operated production from the Mid-Continent division is about 400 MMcfe/d, or nearly 300 MMcfe/d net. Both metrics are recent Company records.
- Stiles Ranch Field Achieves Record Production - Production from the Stiles Ranch Field, located in the Texas Panhandle, recently reached record gross production of 145 MMcfe/d. Newfield recently added a rig in the field and has three rigs drilling horizontal wells. Newfield has an approximate 80% working interest in the field.
- Woodford Shale Update - Newfield recently released an operated rig in the Woodford and now has 11 operated rigs under term contract in the field, with six of the remaining rigs rolling off of term contract in 2009. The timing of rig contract expirations and the fact that more than 90% of the Company's 165,000 net acres now held-by-production provide Newfield with operational flexibility in the second half of 2009. Due to the recent weakness in natural gas prices and a continued decline in service costs, Newfield has been intentionally slowing its pace of new well completions. Gross operated production in the Woodford is approximately 240 MMcfe/d. The average lateral length in 2009 is expected to be more than 5,000' in length.
- Mid-Continent Express to Improve Realized Gas Prices - Beginning
late in the second quarter of 2009, Newfield's realized prices for
Mid-Continent properties are expected to improve to 80-85% of the
Henry Hub Index as the Company begins to utilize firm
transportation agreements that provide guaranteed pipeline
capacity at a fixed price to move this natural gas production to
- Monument Butte Update - Gross oil sales from Monument Butte, located
in the Uinta Basin of
Utah, are currently averaging about 19,000 BOPD, up from approximately 17,000 BOPD at year-end 2008. The increased sales volumes reflect improved demand for Black Wax crude. Differentials have narrowed recently to approximately $12per barrel below WTI (including transportation expense). Newfield continues to run a three-rig program in the Monument Butte field area, which covers approximately 180,000 gross acres. Substantially all of the acreage is held by production.
**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 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
For information, contact:
1Q09 Actual Results 1Q09 Actual Domestic Int'l Total Production/Liftings Note 1 Natural gas - Bcf 44.8 - 44.8 Oil and condensate - MMBbls 1.8 1.2 3.0 Total Bcfe 55.4 7.2 62.6 Average Realized Prices Note 2 Natural gas - $/Mcf $ 5.48 $ - $ 5.48 Oil and condensate - $/Bbl $ 97.34 $ 40.67 $ 74.42 Mcf equivalent - $/Mcfe $ 7.55 $ 6.78 $ 7.46 Operating Expenses: Lease operating Recurring ($MM) $ 47.6 $ 12.2 $ 59.8 per/Mcfe $ 0.85 $ 1.70 $ 0.95 Major (workovers, repairs, etc.) ($MM) Note 3 $ 10.9 $ 0.2 $ 11.1 per/Mcfe $ 0.20 $ 0.03 $ 0.18 Production and other taxes ($MM) Note 4 $ 6.7 $ 2.4 $ 9.1 per/Mcfe $ 0.12 $ 0.34 $ 0.15 General and administrative (G&A), net ($MM) $ 32.2 $ 0.2 $ 32.4 per/Mcfe $ 0.58 $ 0.03 $ 0.52 Capitalized internal costs ($MM) $ (16.0) per/Mcfe $ (0.26) Interest expense ($MM) $ 32.1 per/Mcfe $ 0.51 Capitalized interest ($MM) $ (14.1) per/Mcfe $ (0.22) Note 1: Reflects approximately 2 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 $3.48 per Mcf and the total oil and condensate average realized price would have been $35.66 per barrel. Note 3: Domestic major expense of
$4 millionwas recorded in the first quarter related to a non-operated well in deepwater GOM. Note 4: Domestic production and other taxes includes refunds related to production and severance tax exemptions on some of our onshore wells. 2Q09 Estimates 2Q09 Estimates Domestic Int'l Total Production/Liftings Natural gas - Bcf 45.0 - 48.6 - 45.0 - 48.6 Oil and condensate - MMBbls 1.5 - 1.7 1.5 - 1.7 3.0 - 3.4 Total Bcfe 54.0 - 58.8 9.0 - 10.2 63.0 - 69.0 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) $46.2 - $51.0 $15.4 - $17.0 $61.6 - $68.0 per/Mcfe $0.86 - $0.87 $1.66 - $1.71 $0.97 - $0.99 Major (workover, repairs, etc.) ($MM) $10.0 - $11.8 $1.1 - $1.3 $11.1 - $13.1 per/Mcfe $0.18 - $0.20 $0.12 - $0.14 $0.17 - $0.19 Production and other taxes ($MM) Note 4 $14.5 - $16.1 $5.0 - $5.5 $19.5 - $21.6 per/Mcfe $0.27 - $0.28 $0.54 - $0.56 $0.30 - $0.32 General and administrative (G&A), net ($MM) $30.6 - $33.7 $1.4 - $1.6 $32.0 - $35.3 per/Mcfe $0.57 - $0.58 $0.15 - $0.16 $0.50 - $0.52 Capitalized internal costs ($MM) $(18.6 - $20.5) per/Mcfe $(0.28 - $0.30) Interest expense ($MM) $29.3 - $32.7 per/Mcfe $0.46 - $0.48 Capitalized interest ($MM) $(11.8 - $13.0) per/Mcfe $(0.18 - $0.20) Tax rate (%)Note 5 36-38 Income taxes (%) Current 14% - 16% Deferred 84% - 86%
Note 1: Gas prices in the Mid-Continent, after basis differentials, transportation and handling charges, typically average 70 - 80% of the Henry Hub Index. Beginning late in the second quarter of 2009, our realized prices for Mid-Continent properties should improve to 80-85% of the Henry Hub Index as we begin to utilize our agreements that provide guaranteed pipeline capacity at a fixed price to move this natural gas production to the Perryville markets. Gas prices in the Gulf Coast, after basis differentials, transportation and handling charges, are expected to average $0.50 - $0.75 per MMBtu less than the Henry Hub Index.
Note 2: 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 85 - 90% of WTI.
Note 3: Oil in
Note 4: Guidance for production taxes determined using
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, 2009 2008 Oil and gas revenues $ 262 $ 515 Operating expenses: Lease operating 71 59 Production and other taxes 9 51 Depreciation, depletion and amortization 159 157 General and administrative 32 32 Ceiling test writedown 1,344 -- Other 2 -- Total operating expenses 1,617 299 Income (loss) from operations (1,355) 216 Other income (expenses): Interest expense (32) (19) Capitalized interest 14 13 Commodity derivative income (expense) 278 (321) Other 3 3 263 (324) Loss before income taxes (1,092) (108) Income tax benefit (398) (44) Net loss $(694) $(64) Loss per share: Basic -- $(5.35) $(0.50) Diluted -- $(5.35) $(0.50) Weighted average number of shares outstanding for basic loss per share 130 129 Weighted average number of shares outstanding for diluted loss per share * 130 129 * Had we recorded net income for the three months ended
March 31, 2009and 2008, the weighted average number of shares outstanding for the computation of diluted earnings per share would have been 131 million for both periods. CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited, in millions) March 31, December 31, 2009 2008 ASSETS Current assets: Cash and cash equivalents $38 $24 Derivative assets 775 663 Other current assets 506 519 Total current assets 1,319 1,206 Property and equipment, net (full cost method) 4,622 5,758 Derivative assets 203 247 Other assets 99 94 Total assets $6,243 $7,305 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities $1,044 $1,085 Other liabilities 108 92 Long-term debt 2,287 2,213 Deferred taxes 232 658 Total long-term liabilities 2,627 2,963 Commitments and contingencies - - STOCKHOLDERS' EQUITY Common stock 1 1 Additional paid-in capital 1,339 1,335 Treasury stock (25) (32) Accumulated other comprehensive loss (13) (11) Retained earnings 1,270 1,964 Total stockholders' equity 2,572 3,257 Total liabilities and stockholders' equity $6,243 $7,305 CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited, in millions) For the Three Months Ended March 31, 2009 2008 Cash flows from operating activities: Net loss $(694) $(64) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 159 157 Deferred tax benefit (403) (63) Stock-based compensation 8 5 Ceiling test writedown 1,344 - Commodity derivative (income) expense (278) 321 Cash receipts (payments) on derivative settlements 211 (40) 347 316 Changes in operating assets and liabilities 2 (44) Net cash provided by operating activities 349 272 Cash flows from investing activities: Additions to oil and gas properties and other, net (414) (501) Net (purchases) redemptions of investments 7 46 Net cash used in investing activities (407) (455) Cash flows from financing activities: Net proceeds under credit arrangements 73 -- Other (1) 13 Net cash provided by financing activities 72 13 Increase (decrease) in cash and cash equivalents 14 (170) Cash and cash equivalents, beginning of period 24 250 Cash and cash equivalents, end of period $ 38 $ 80 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 first quarter of 2009 stated without the effects of certain items to net loss is shown below: 1Q09 (in millions) Net loss $ (694) Ceiling test writedown 1,344 Net unrealized gain on commodity derivatives (1) (73) Income tax adjustment for above items (465) Earnings stated without the effect of the above items $112 (1) The determination of "Net unrealized gain on commodity derivatives" for the first quarter of 2009 is as follows: 1Q09 (in millions) Commodity derivative income $ 278 Cash receipts on derivative settlements (211) Option premiums associated with derivatives settled during the period 6 Net unrealized gain on commodity derivatives $ 73 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: 1Q09 (in millions) Net cash provided by operating activities $ 349 Net change in operating assets and liabilities (2) Net cash provided by operating activities before changes in operating assets and liabilities $ 347