Exhibit 99.1
Newfield Reports Financial and Operating Results for Second Quarter 2009
FOR IMMEDIATE RELEASE
Houston – July 22, 2009 – Newfield Exploration Company (NYSE: NFX) today reported its unaudited second quarter 2009 financial and operating results. Newfield will be hosting a conference call at 8:30 a.m. (CDT) on July 23. To participate in the call, dial 719-325-4798 or listen through the website at http://www.newfield.com.
“Our second quarter results show the diligent efforts of our employees to lower costs and improve margins throughout our focus areas,” said President & CEO Lee K. Boothby. “We are seeing cost reductions throughout our operations. A combination of improving efficiencies in drilling and completions, falling service costs and a strong hedge position in 2009-2010 provides us with an advantage in today’s challenging environment. Our production volumes are strong. In fact, we expect to be in the top half of our guidance range for 2009 AND we intend to continue deferring completions in the Woodford, as well as defer completions on the remainder of our planned Granite Wash wells in 2009.
“We are intensely focused on how we are allocating capital in our business units today, ensuring that dollars are flowing to the areas with the best returns and the highest growth prospects. We intend to meet our production targets in 2009 and are confident that our portfolio will allow us to grow production at similar percentage levels, within cash flow, in 2010-11.”
Second Quarter 2009
For the second quarter of 2009, Newfield recorded a net loss of $39 million, or $0.30 per diluted share (all per share amounts are on a diluted basis). The loss reflects a net unrealized loss on commodity derivatives of $322 million ($208 million after-tax), or $1.58 per share.
Without the effect of this item, net income for the second quarter of 2009 would have been $169 million, or $1.28 per share.
Revenues in the second quarter of 2009 were $287 million. Net cash provided by operating activities before changes in operating assets and liabilities was $417 million. See “Explanation and Reconciliation of Non-GAAP Financial Measures” found after the financial statements in this release.
Newfield’s production in the second quarter of 2009 was 65 Bcfe, an increase of 12% over the second quarter of 2008. An additional 1 Bcfe was produced in Malaysia during the second quarter of 2009 but was not lifted due to timing of liftings. Capital expenditures in the second quarter of 2009 were $300 million.
Highlights
| Ø | Mid-Continent Update – Gross operated production from the Mid-Continent division has been running ahead of beginning of the year expectations, primarily due to increased production from the Granite Wash play. Current gross production from the Mid-Continent is 400 MMcfe/d, or 292 MMcfe/d net. |
| o | Horizontal Drilling Success at Stiles Ranch – Newfield’s first seven horizontal wells in the Granite Wash play had an average initial production rate of 22 MMcfe/d. All of the wells to date have been drilled in the Stiles Ranch field, located in Wheeler County, Texas. In the second quarter of 2009, Newfield increased its activity in the field and is today running three operated drilling rigs, all drilling horizontal wells. Newfield has an approximate 80% working interest in Stiles Ranch and substantially all of the acreage is held-by-production. A complete update on the Granite Wash activities can be found in a separate news release issued earlier today. |
| o | Woodford Shale – Since the beginning of the year, Newfield has released three operated rigs in the Woodford. The Company now has 10 operated rigs running under term contracts, with four of the remaining rigs rolling off of term contracts in the second half of 2009. The timing of rig contract expirations and the fact that more than 90% of the Company’s 165,000 net acres are now held-by-production provides flexibility. Due to the recent weakness in natural gas prices, Newfield has been intentionally slowing its pace of new well completions. Newfield has an inventory of about 25 wells that have been drilled but not completed. The timing of these completions largely depends on natural gas prices. Gross operated production in the Woodford is approximately 240 MMcfe/d, or about equal to the first quarter 2009 exit rate. |
| o | Woodford Gas Sales Now Flowing Through Mid-Continent Express – Last week, Newfield initiated firm gas sales through the new Arkoma Connector and into the Mid-Continent Express pipeline. Today, 100% of the Company’s Woodford gas is being sold under firm transportation agreements. Newfield’s realized prices for Mid-Continent properties are expected to improve to 75-85% of the Henry Hub Index as the Company utilizes firm transportation agreements that provide guaranteed pipeline capacity at a fixed price to move its natural gas production to the Perryville, Louisiana markets. |
| Ø | Deepwater Gulf of Mexico Update – Newfield recently announced two discoveries in the deepwater Gulf of Mexico -- Pyrenees and Winter. Since the beginning of 2008, Newfield has drilled seven successful wells out of eight exploration attempts in the deepwater Gulf and now has seven deepwater developments underway, providing significant future production growth. |
| o | Pyrenees Sidetrack Underway – Located at Garden Banks (GB) Block 293 in approximately 2,100’ of water, Pyrenees encountered approximately 125’ of net hydrocarbon pay in three separate intervals. Newfield and its partners recently contracted a deepwater rig and are in the process of sidetracking the well to test both shallower and deeper objectives. Newfield operates the development with a 40% working interest. |
o | Additional Prospects Around Pyrenees Added Through Recent GOM Lease Sale – In the most recent GOM lease sale, Newfield picked up four additional lease blocks associated with the “Pyrenees Complex.” New prospects include Mastiff (GB 338, 382) and Saluki (GB 381, 425) where Newfield operates with an 85% and a 100% working interest, respectively. The Company is in the process of selling down a portion of its interest in these prospects on a promoted basis. Exploratory drilling could occur as early as 2010. |
o | Winter – Winter (GB 605) is located in approximately 3,400’ of water. The well encountered approximately 44’ of net hydrocarbon pay in two sands and was temporarily abandoned. Partners are considering various development options, with first production anticipated in 2011. Newfield is the operator with a 30% working interest. |
| Ø | Monument Butte Update – Gross oil production from Monument Butte, located in the Uinta Basin of Utah, is about 16,000 BOPD. Differentials have narrowed recently to $12-$13 per barrel below WTI (including transportation expense). Newfield is running a three-rig program in the Monument Butte field today and plans to add a fourth operated rig in the third quarter of 2009. The Monument Butte field area covers approximately 180,000 gross acres, substantially all held by production. |
| Ø | Williston Basin Update –The Company has approximately 500,000 net acres, with nearly 200,000 acres in prospective development areas. Newfield has drilled 11 successful oil wells in the North Dakota portion of the Williston Basin and gross operated production is about 4,000 BOEPD. Newfield is currently running one operated rig in the basin. The most recent completion was the Moberg 1-29H well, located in McKenzie County, North Dakota. The well had initial production of 1,200 BOEPD. Newfield operates the well with a 72% 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 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 third 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: info@newfield.com
2Q09 Actual Results
| | | 2Q09 Actual | |
| | | Domestic | | | Int’l | | | Total | |
| Production/Liftings | | | | | | | | | |
| Natural gas – Bcf | | | 45.2 | | | | – | | | | 45.2 | |
| Oil and condensate – MMBbls | | | 1.9 | | | | 1.3 | | | | 3.2 | |
| Total Bcfe | | | 56.4 | | | | 8.2 | | | | 64.6 | |
| | | | | | | | | | | | | |
Average Realized Prices Note 1 | | | | | | | | | | | | |
| Natural gas – $/Mcf | | $ | 6.21 | | | $ | – | | | $ | 6.21 | |
| Oil and condensate – $/Bbl | | $ | 97.15 | | | $ | 47.29 | | | $ | 76.09 | |
| Mcf equivalent – $/Mcfe | | $ | 8.21 | | | $ | 7.86 | | | $ | 8.16 | |
| | | | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | | | |
| Lease operating | | | | | | | | | | | | |
Recurring ($MM) Note 2 | | $ | 40.0 | | | $ | 11.5 | | | $ | 51.5 | |
| per/Mcfe | | $ | 0.71 | | | $ | 1.40 | | | $ | 0.80 | |
| Major (workovers, repairs, etc.) ($MM) | | $ | 5.1 | | | $ | 0.3 | | | $ | 5.4 | |
| per/Mcfe | | $ | 0.09 | | | $ | 0.04 | | | $ | 0.08 | |
| | | | | | | | | | | | | |
| Production and other taxes ($MM) | | $ | 11.8 | | | $ | 2.8 | | | $ | 14.6 | |
| per/Mcfe | | $ | 0.21 | | | $ | 0.34 | | | $ | 0.23 | |
| | | | | | | | | | | | | |
| General and administrative (G&A), net ($MM) | | $ | 32.0 | | | $ | 1.8 | | | $ | 33.8 | |
| per/Mcfe | | $ | 0.57 | | | $ | 0.22 | | | $ | 0.52 | |
| | | | | | | | | | | | | |
| Capitalized internal costs ($MM) | | | | | | | | | | $ | (18.3 | ) |
| per/Mcfe | | | | | | | | | | $ | (0.28 | ) |
| | | | | | | | | | | | | |
| Interest expense ($MM) | | | | | | | | | | $ | 31.8 | |
| per/Mcfe | | | | | | | | | | $ | 0.49 | |
| | | | | | | | | | | | | |
| Capitalized interest ($MM) | | | | | | | | | | $ | (12.1 | ) |
| 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 $2.85 per Mcf and the total oil and condensate average realized price would have been $48.42 per barrel. Note 2: International recurring lease operating expenses in the second quarter of 2009 included a $1 million ($0.12 per Mcfe) benefit associated with a prior period adjustment on properties operated by others. | |
3Q09 Estimates
| | | 3Q09 Estimates | |
| | | Domestic | | | Int’l | | | Total | |
| Production/Liftings | | | | | | | | | |
| Natural gas – Bcf | | | 43.5 – 48.9 | | | | – | | | | 43.5 – 48.9 | |
| Oil and condensate – MMBbls | | | 1.5 – 1.6 | | | | 1.7 – 1.9 | | | | 3.2 – 3.5 | |
| Total Bcfe | | | 52.5 – 58.5 | | | | 10.4 – 11.5 | | | | 62.9 – 70.0 | |
| | | | | | | | | | | | | |
| 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) | | $ | 34.0 - $38.0 | | | $ | 21.7 - $24.0 | | | $ | 55.7 - $62.0 | |
| per/Mcfe | | $ | 0.64 - $0.65 | | | $ | 2.08 - $2.10 | | | $ | 0.88 - $0.89 | |
| Major (workover, repairs, etc.) ($MM) | | $ | 4.0 - $6.0 | | | $ | 0.9 - $1.0 | | | $ | 4.9 - $7.0 | |
| per/Mcfe | | $ | 0.08 - $0.10 | | | $ | 0.09 - $0.10 | | | $ | 0.08 - $0.10 | |
| | | | | | | | | | | | | |
Production and other taxes ($MM)Note 4 | | $ | 14.3 - $15.9 | | | $ | 9.6 - $10.6 | | | $ | 23.9 - $26.5 | |
| per/Mcfe | | $ | 0.27 - $0.28 | | | $ | 0.92 - $0.93 | | | $ | 0.37 - $0.39 | |
| | | | | | | | | | | | | |
| General and administrative (G&A), net ($MM) | | $ | 29.9 - $33.0 | | | $ | 1.4 - $1.6 | | | $ | 31.3 - $34.6 | |
| per/Mcfe | | $ | 0.56 - $0.57 | | | $ | 0.13 - $0.14 | | | $ | 0.49 - $0.50 | |
| | | | | | | | | | | | | |
| Capitalized internal costs ($MM) | | | | | | | | | | $ | (18.5 - $20.5 | ) |
| per/Mcfe | | | | | | | | | | $ | (0.29 – $0.30 | ) |
| | | | | | | | | | | | | |
| Interest expense ($MM) | | | | | | | | | | $ | 29.9 - $33.1 | |
| per/Mcfe | | | | | | | | | | $ | 0.47 - $0.48 | |
| | | | | | | | | | | | | |
| Capitalized interest ($MM) | | | | | | | | | | $ | (11.4 - $12.6 | ) |
| per/Mcfe | | | | | | | | | | $ | (0.18 - $0.19 | ) |
| | | | | | | | | | | | | |
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 in the third quarter of 2009, our realized prices for Mid-Continent properties should improve to 75-85% 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 Malaysia typically sells at a slight discount to Tapis, or about 85-90% of WTI. Oil production from China typically sells at $6 – $8 per barrel below WTI. Note 4: Guidance for production taxes determined using $65/Bbl oil and $4.50/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 June 30, | | | For the Six Months Ended June 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | | | | | | | | | | | |
| Oil and gas revenues | | $ | 287 | | | $ | 691 | | | $ | 549 | | | $ | 1,207 | |
| | | | | | | | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | | | | | | | |
Lease operating | | | 57 | | | | 58 | | | | 128 | | | | 117 | |
Production and other taxes | | | 15 | | | | 52 | | | | 24 | | | | 103 | |
Depreciation, depletion and amortization | | | 137 | | | | 166 | | | | 296 | | | | 323 | |
General and administrative | | | 34 | | | | 37 | | | | 66 | | | | 69 | |
| Ceiling test writedown | | | — | | | | — | | | | 1,344 | | | | — | |
Other | | | 5 | | | | — | | | | 7 | | | | — | |
Total operating expenses | | | 248 | | | | 313 | | | | 1,865 | | | | 612 | |
| | | | | | | | | | | | | | | | | |
| Income (loss) from operations | | | 39 | | | | 378 | | | | (1,316 | ) | | | 595 | |
| | | | | | | | | | | | | | | | | |
| Other income (expenses): | | | | | | | | | | | | | | | | |
Interest expense | | | (32 | ) | | | (28 | ) | | | (64 | ) | | | (47 | ) |
Capitalized interest | | | 12 | | | | 13 | | | | 26 | | | | 27 | |
Commodity derivative income (expense) | | | (81 | ) | | | (652 | ) | | | 197 | | | | (973 | ) |
Other | | | 2 | | | | — | | | | 5 | | | | 2 | |
| | | | (99 | ) | | | (667 | ) | | | 164 | | | | (991 | ) |
| | | | | | | | | | | | | | | | | |
| Loss before income taxes | | | (60 | ) | | | (289 | ) | | | (1,152 | ) | | | (396 | ) |
| Income tax benefit | | | (21 | ) | | | (45 | ) | | | (419 | ) | | | (88 | ) |
| | | | | | | | | | | | | | | | | |
| Net loss | | $ | (39 | ) | | $ | (244 | ) | | $ | (733 | ) | | $ | (308 | ) |
| | | | | | | | | | | | | | | | | |
| Loss per share: | | | | | | | | | | | | | | | | |
| Basic -- | | $ | (0.30 | ) | | $ | (1.89 | ) | | $ | (5.66 | ) | | $ | (2.39 | ) |
| | | | | | | | | | | | | | | | | |
| Diluted -- | | $ | (0.30 | ) | | $ | (1.89 | ) | | $ | (5.66 | ) | | $ | (2.39 | ) |
| | | | | | | | | | | | | | | | | |
Weighted average number of shares outstanding for basic loss per share | | | 130 | | | | 129 | | | | 129 | | | | 129 | |
Weighted average number of shares outstanding for diluted loss per share * | | | 130 | | | | 129 | | | | 129 | | | | 129 | |
| * Had we recognized net income for the three and six months ended June 30, 2009 and 2008, the weighted average number of shares outstanding for the computation of diluted earnings per share would have increased by 2 million shares for the three and six months ended June 30, 2009 and 3 million shares for the three and six months ended June 30, 2008. | |
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited, in millions) | | June 30, 2009 | | | December 31, 2008 | |
| | | | | | | |
| ASSETS | | | | | | |
| Current assets: | | | | | | |
Cash and cash equivalents | | $ | 38 | | | $ | 24 | |
Derivative assets | | | 549 | | | | 663 | |
Other current assets | | | 493 | | | | 519 | |
Total current assets | | | 1,080 | | | | 1,206 | |
| | | | | | | | | |
| Property and equipment, net (full cost method) | | | 4,789 | | | | 5,758 | |
| Derivative assets | | | 101 | | | | 247 | |
| Other assets | | | 88 | | | | 94 | |
Total assets | | $ | 6,058 | | | $ | 7,305 | |
| | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | |
| Current liabilities | | $ | 818 | | | $ | 1,085 | |
| | | | | | | | | |
| Other liabilities | | | 113 | | | | 92 | |
| Long-term debt | | | 2,292 | | | | 2,213 | |
| Deferred taxes | | | 288 | | | | 658 | |
Total long-term liabilities | | | 2,693 | | | | 2,963 | |
| | | | | | | | | |
| Commitments and contingencies | | | — | | | | — | |
| | | | | | | | | |
| STOCKHOLDERS’ EQUITY | | | | | | | | |
| Common stock | | | 1 | | | | 1 | |
| Additional paid-in capital | | | 1,359 | | | | 1,335 | |
| Treasury stock | | | (33 | ) | | | (32 | ) |
| Accumulated other comprehensive loss | | | (11 | ) | | | (11 | ) |
| Retained earnings | | | 1,231 | | | | 1,964 | |
Total stockholders’ equity | | | 2,547 | | | | 3,257 | |
Total liabilities and stockholders’ equity | | $ | 6,058 | | | $ | 7,305 | |
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited, in millions) | | For the Six Months Ended June 30, | |
| | | 2009 | | | 2008 | |
| Cash flows from operating activities: | | | | | | |
Net loss | | $ | (733 | ) | | $ | (308 | ) |
Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | |
| Depreciation, depletion and amortization | | | 296 | | | | 323 | |
Deferred tax benefit | | | (420 | ) | | | (113 | ) |
Stock-based compensation | | | 15 | | | | 12 | |
Ceiling test writedown | | | 1,344 | | | | — | |
Commodity derivative (income) expense | | | (197 | ) | | | 973 | |
Cash receipts (payments) on derivative settlements | | | 459 | | | | (668 | ) |
| | | | 764 | | | | 219 | |
Changes in operating assets and liabilities | | | (52 | ) | | | (47 | ) |
| Net cash provided by operating activities | | | 712 | | | | 172 | |
| | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | |
Additions to oil and gas properties and other, net | | | (790 | ) | | | (1,320 | ) |
Net redemptions of investments | | | 14 | | | | 48 | |
| Net cash used in investing activities | | | (776 | ) | | | (1,272 | ) |
| | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | |
Net proceeds under credit arrangements | | | 78 | | | | 268 | |
Net proceeds from issuance of senior subordinated notes | | | — | | | | 592 | |
Other | | | — | | | | 18 | |
Net cash provided by financing activities | | | 78 | | | | 878 | |
| | | | | | | | | |
| | | | | | | | | |
| Increase (decrease) in cash and cash equivalents | | | 14 | | | | (222 | ) |
| Cash and cash equivalents, beginning of period | | | 24 | | | | 250 | |
| | | | | | | | | |
| Cash and cash equivalents, end of period | | $ | 38 | | | $ | 28 | |
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 second quarter of 2009 stated without the effects of certain items to net loss is shown below:
| | | | 2Q09 | |
| | | (in millions) | |
| Net loss | | $ | (39 | ) |
Net unrealized loss on commodity derivatives (1) | | | 322 | |
Income tax adjustment for above item | | | (114 | ) |
| Earnings stated without the effect of the above item | | $ | 169 | |
(1) The determination of “Net unrealized loss on commodity derivatives” for the second quarter of 2009 is as follows:
| | | | 2Q09 | |
| | | (in millions) | |
| Commodity derivative expense | | $ | (81 | ) |
| Cash receipts on derivative settlements | | | (248 | ) |
Option premiums associated with derivatives settled during the period | | | 7 | |
Net unrealized loss on commodity derivatives | | $ | (322 | ) |
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:
| | | | 2Q09 | |
| | | (in millions) |
| Net cash provided by operating activities | | $ | 363 | |
Net change in operating assets and liabilities | | | 54 | |
Net cash provided by operating activities before changes in operating assets and liabilities | | $ | 417 | |
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