Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/ | nfx8k-042011.htm |
| EX-99.2 - EXHIBIT 992 - NEWFIELD EXPLORATION CO /DE/ | ex992.htm |
Exhibit 99.1
Newfield Reports First Quarter 2011 Financial and Operating Results
FOR IMMEDIATE RELEASE
Houston – April 20, 2011 – Newfield Exploration Company (NYSE: NFX) today reported its unaudited first quarter 2011 financial and operating results. Newfield will be hosting a conference call at 8:30 a.m. CT on April 21, 2011. To participate in the call, dial 719-325-4804 or listen through the investor relations section of our website at http://www.newfield.com.
For the first quarter of 2011, Newfield recorded a net loss of $17 million, or $0.13 per diluted share (all per share amounts are on a diluted basis). The net loss for the first quarter includes a net unrealized loss on commodity derivatives of $237 million ($150 million after-tax), or $1.11 per share. Without the effect of this item, net income for the first quarter of 2011, rather than net loss, would have been $133 million, or $0.98 per share.
Revenues in the first quarter of 2011 were $545 million. Net cash provided by operating activities before changes in operating assets and liabilities was $361 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 2011 was 72 Bcfe. Natural gas production in the first quarter of 2011 was 45 Bcf, an average of 503 MMcf/d. Newfield’s oil liftings and liquids production in the first quarter of 2011 were 4.4 MMBbls, or an average of approximately 49,000 BOPD. Capital expenditures in the first quarter of 2011 were approximately $434 million.
2011 Production
Newfield’s production guidance for 2011 remains 312 – 323 Bcfe, an estimated increase of 8 – 12% over 2010 volumes. Second quarter 2011 production will be negatively impacted due to deferred production from Newfield’s non-operated Abu field, located on PM 318 offshore Malaysia. The field is currently off-line due to a mechanical failure associated with FPSO operations. Repairs to the system are expected to take 60-90 days. Newfield estimates that the impact to its second quarter net oil production will be a reduction of approximately 0.2 MMBbls, which is included in its second quarter guidance (found in this release) as well as within the Company’s unchanged production forecast for the full year.
2011 Capital Investments, Asset Sales
Newfield today increased its 2011 capital budget to $1.9 billion from its original budget of $1.7 billion. The budget excludes capitalized interest and overhead and the planned second quarter closing of the Company’s previously announced $308 million acquisition in the Uinta Basin. The increase in expenditures is substantially offset by increased cash flow from operations as a result of higher oil price realizations. The increase in planned investments is primarily related to the following:
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·
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New and ongoing leasing of acreage in an undisclosed resource play;
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·
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Increased service and labor costs throughout the Company’s areas of operation;
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·
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Efficiency gains in drilling; and
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·
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Capital investments in the Uinta Basin associated with the previously announced Uinta Basin acquisition.
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Newfield is in the process of selling certain non-strategic domestic assets. The planned sales are expected to be completed in the second half of 2011. The Company expects that proceeds will exceed $200 million.
Year-to-Date 2011 Operating Highlights:
Rocky Mountains
The largest contributor to Newfield’s 2011 estimated increase in domestic oil production is its Rocky Mountain focus area. Production in the first quarter of 2011 increased 27% over the same period of 2010. During the first quarter of 2011, Newfield’s sales were approximately 2.3 MMBOE, or 25,000 BOEPD. For the full year 2011, Newfield expects that its Rocky Mountain production will grow more than 25% over 2010 annual volumes and exit 2011 at a rate of approximately 33,000 BOEPD. Approximately two-thirds of the region’s production is oil.
Greater Monument Butte Field Area – Newfield continues to run five operated rigs in the Uinta Basin. Sales in the region averaged approximately 18,200 BOPD (net) during the first quarter as field inventory levels were drawn down to near-normal operating levels. The Company expects to grow 2011 production from the area by about 15% over 2010 levels.
During the first quarter, Newfield announced the signing of two separate purchase and sale agreements to acquire assets in the Uinta Basin from Harvest Natural Resources and an unnamed private company for $308 million. The transactions will add approximately 70,000 net acres in the Uinta Basin. The acreage is largely undeveloped and located adjacent and north of Monument Butte. The transactions are expected to close in the second quarter of 2011, pending customary closing processes.
In addition, Newfield and partner, Ute Energy, recently executed a third Exploration and Development Agreement. As a result, Newfield added approximately 11,000 net Tribal acres. Inclusive of these recent transactions, Newfield will own interest in approximately 250,000 net acres in the Uinta Basin.
Williston Basin – Newfield is running five operated drilling rigs in the Williston Basin. Current net production is about 5,000 BOEPD and the Company has 10 wells in various stages of completion (average lateral length approximately 8,600’). Dedicated fracture stimulation services arrived in the field in April and completions are underway with initial volumes from the new wells expected late in the second quarter of 2011.
Substantially all of the Company’s planned wells in 2011 are super extended lateral (SXLs) wells. Three horizontal wells were recently completed with an average initial gross production rate (24-hour) of approximately 3,900 BOEPD. This average includes a recent record completion which had an initial gross production rate (24-hour average) of 4,468 BOEPD.
Newfield has approximately 161,000 net acres in the Williston Basin.
Southern Alberta Basin – To date, Newfield has drilled seven vertical wells, completed and placed on production two horizontal wells, and is preparing to drill an eighth vertical well. All of the wells to date have encountered oil. Newfield has 280,000 net acres in the play, located in Glacier County, Montana. Multiple prospective geologic formations throughout the acreage are planned for evaluation.
Mid-Continent
Granite Wash – Newfield continues to run a four-rig program in the Granite Wash play, located primarily in Wheeler County, Texas. To date, the Company has completed 39 wells in the play with gross initial production averaging approximately 16 MMcfe/d (24-hour rate). Newfield has successfully assessed 10 geologic intervals and additional prospective horizons remain. For 2011, the Company plans to drill 28 - 33 wells and grow production more than 20% over 2010. Current net production from the area is approximately 110 MMcfe/d.
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The 2011 Granite Wash program is focused on the “liquids-rich” geologic intervals within the play. Since 2009, Newfield has completed 21 wells in the high BTU Marmaton formations with initial 24-hour rates averaging over 17 MMcfe/d (gross). Recent Marmaton completions include: the Dupont1-1H with gross initial production of 22 MMcfe/d and the Britt Ranch G44W-14H with gross initial production of 22 MMcfe/d. Newfield continues to make efficiency gains in its drilling programs. A recent “best in class” 4,700’ lateral well was drilled and cased in 25 days. Newfield’s average working interest in the Granite Wash play is approximately 75%.
Over the last year, Newfield added more than 10,000 net acres in the Granite Wash play. Assessment of new areas is planned for the second half of 2011.
Woodford Shale – The Company’s activities in the Arkoma Basin are substantially focused on the “oily Woodford.” This relatively new play for the Company is prospective on approximately 15% of the Company’s 172,000 net acres in the basin.
The six most recent “oily Woodford” wells have an average lateral length of approximately 8,700’ and were drilled and completed for an average of approximately $8.3 million (gross). Newfield has an approximate 96% working interest in these wells. The peak gross initial production rates of five of these wells averaged more than 1,500 BOEPD and their 30-day average rate was 930 BOEPD.
For 2011, Newfield plans to run 2-3 operated rigs in the Arkoma Basin, primarily focusing on the oil and “liquids rich” portion of the play.
Onshore Texas
Eagle Ford Shale – Newfield is running 2 -3 operated rigs and continues to assess its 335,000 net acre position in the Maverick Basin (approximate 85% working interest). Drilling and completion operations in the basin ceased in October 2010 due to seasonal hunting stipulations. Activities resumed in February 2011. Contracted fracture stimulation services are in the field and five wells have been drilled and are planned for completion in the second quarter of 2011.
Recent wells have lateral lengths of approximately 5,000’ and are averaging less than 10 days to drill and case. Efficiency gains in drilling have reduced drill and case costs to less than $2 million (gross) per well. Completion services remain tight throughout the Eagle Ford Shale and are averaging $4.5 – $5.0 million (gross) per well.
International Oil Developments
First quarter 2011 net liftings from the Company’s oil assets in Southeast Asia were 1.5 MMBbls, or an average of about 16,600 BOPD. The largest contributor to Newfield’s international oil production was Malaysia where net liftings during the period averaged approximately 14,650 BOPD. A rig is actively drilling additional development wells today in the East Belumut field, located on PM 323. On PM 329, the East Piatu development is expected to commence production at about 10,000 BOPD (gross) in late 2011. Newfield has a 70% interest in East Piatu.
Deepwater Gulf of Mexico
The Company’s deepwater Gulf of Mexico production in the first quarter of 2011 was 8 Bcfe, or approximately 90 MMcfe/d. The Gladden oil development, located at Mississippi Canyon 800, commenced production late in the first quarter of 2011 and is producing about 6,000 BOEPD (gross). Newfield operates Gladden with a 57.5% working interest. In addition Pyrenees, located at Garden Banks 293, is expected to commence production in late 2011 at approximately 50 MMcf/d and 2,400 BCPD (gross). Outside-operated developments, Axe and Dalmatian, are scheduled for first production in 2013.
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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, 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. 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) 847-6081
Danny Aguirre (281) 668-2657
Media Relations: Keith Schmidt (281) 674-2650
Email: info@newfield.com
4
1Q11 Actual Results
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1Q11 Actual
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Domestic
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Int’l
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Total
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||||||||||
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Production/Liftings
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||||||||||||
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Natural gas – Bcf
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45.3 | – | 45.3 | |||||||||
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Oil, condensate and NGLs – MMBbls
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2.9 | 1.5 | 4.4 | |||||||||
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Total Bcfe
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62.5 | 9.0 | 71.5 | |||||||||
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Average Realized Prices Note 1
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||||||||||||
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Natural gas – $/Mcf
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$ | 5.51 | $ | – | $ | 5.51 | ||||||
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Oil, condensate and NGLs – $/Bbl
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$ | 71.82 | $ | 101.22 | $ | 81.86 | ||||||
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Mcf equivalent – $/Mcfe
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$ | 7.37 | $ | 16.87 | $ | 8.59 | ||||||
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Operating Expenses:
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Lease operating ($MM)
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Recurring
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$ | 48.6 | $ | 15.3 | $ | 63.9 | ||||||
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Major (workovers, etc.)
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$ | 6.1 | $ | 1.6 | $ | 7.7 | ||||||
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Transportation
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$ | 21.9 | $ | – | $ | 21.9 | ||||||
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Lease operating (per Mcfe)
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Recurring
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$ | 0.80 | $ | 1.71 | $ | 0.92 | ||||||
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Major (workovers, etc.)
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$ | 0.10 | $ | 0.18 | $ | 0.11 | ||||||
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Transportation
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$ | 0.36 | $ | – | $ | 0.31 | ||||||
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Production and other taxes ($MM)
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$ | 15.3 | $ | 55.5 | $ | 70.8 | ||||||
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per/Mcfe
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$ | 0.25 | $ | 6.20 | $ | 1.02 | ||||||
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General and administrative (G&A), net ($MM)
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$ | 36.3 | $ | 0.7 | $ | 37.0 | ||||||
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per/Mcfe
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$ | 0.60 | $ | 0.08 | $ | 0.53 | ||||||
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Capitalized internal costs ($MM)
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$ | 21.2 | ||||||||||
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per/Mcfe
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$ | 0.30 | ||||||||||
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Interest Expense ($MM)
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$ | (39.6 | ) | |||||||||
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per/Mcfe
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$ | (0.57 | ) | |||||||||
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Capitalized Interest ($MM)
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$ | 17.5 | ||||||||||
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per/Mcfe
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$ | 0.25 | ||||||||||
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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 $4.00 per Mcf and the domestic and total oil and condensate average realized prices would have been $75.83 and $84.51 per barrel, respectively.
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5
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2Q11 & FY11 Estimates
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Domestic
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Int’l
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Total
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|||||
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Production/Liftings
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2QE
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FY11
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2QE
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FY11
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2QE
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FY11
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Natural gas – Bcf
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47 – 49
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191 – 194
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–
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–
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47 – 49
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191 – 194
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Oil, condensate and NGLs – MMBbls
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2.9 – 3.5
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14.0 – 15.0
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1.1 – 1.4
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6.1 – 6.5
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4.0 – 4.9
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20.1 – 21.5
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Total Bcfe
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64 – 70
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275 – 284
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7 – 8
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37 – 39
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71 – 78
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312 – 323
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Average Realized Prices
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|||||||
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Natural gas – $/Mcf
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Note 1
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Note 1
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Oil, condensate and NGLs – $/Bbl
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Note 2
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Note 2
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Note 3
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Note 3
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Mcf equivalent – $/Mcfe
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Operating Expenses (per Mcfe):
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Lease Operating
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|||||||
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Recurring
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$0.71 - $0.79
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$0.69 - $0.77
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$1.90 - $2.16
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$1.66 - $1.93
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$0.83 - $0.92
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$0.76 - $0.85
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Major (workovers, etc.)
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$0.24 - $0.29
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$0.16 - $0.21
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$1.91 - $2.26
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$0.62 - $0.78
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$0.41 - $0.49
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$0.21 - $0.28
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Transportation
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$0.34 - $0.38
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$0.35 - $0.39
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-
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-
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$0.31 - $0.34
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$0.31 - $0.34
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Production/Taxes Note 4
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$0.39 - $0.44
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$0.33 - $0.40
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$5.04 - $6.89
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$4.71 - $5.31
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$0.86 - $1.09
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$0.85 - $0.99
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G&A, net
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$0.60 - $0.63
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$0.62 - $0.67
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$0.22 - $0.25
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$0.15 - $0.17
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$0.56 - $0.59
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$0.57 - $0.61
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Capitalized internal costs
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($0.34 - $0.39)
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($0.32 - $0.36)
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Interest Expense
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$0.51 - $0.56
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$0.48 - $0.53
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Capitalized Interest
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($0.21 - $0.24)
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($0.18 - $0.22)
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Tax Rate (%)Note 5
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36% - 38%
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36% - 38%
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Income Taxes (%)
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Current
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18% - 22%
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18% - 22%
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Deferred
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78% - 82%
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78% - 82%
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Note 1:
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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 88-92% of the Henry Hub Index.
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Note 2:
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The price the Company receives for its Gulf Coast oil production, excluding NGLs, typically averages about 93-97% 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 about $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.
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Note 3:
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Oil sales from the Company’s operations in Malaysia typically sell at a slight discount to Tapis, or today about 105-110% of WTI. Oil sales from the Company’s operations in China typically sell at a premium of up to $4 per barrel greater than the WTI price.
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Note 4:
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Guidance for production taxes determined using the average of the strip at 04/11/11 ($111.19/bbl, $4.36/mcf).
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Note 5:
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Tax rate applied to earnings excluding unrealized gains or losses on commodity derivatives.
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6
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CONSOLIDATED STATEMENT OF INCOME
(Unaudited, in millions, except per share data)
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For the
Three Months Ended
March 31,
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2011
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2010
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Oil and gas revenues
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$ | 545 | $ | 458 | ||||
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Operating expenses:
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||||||||
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Lease operating
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93 | 67 | ||||||
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Production and other taxes
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71 | 25 | ||||||
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Depreciation, depletion and amortization
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166 | 147 | ||||||
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General and administrative
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37 | 36 | ||||||
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Other
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— | 8 | ||||||
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Total operating expenses
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367 | 283 | ||||||
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Income from operations
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178 | 175 | ||||||
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Other income (expenses):
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||||||||
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Interest expense
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(40 | ) | (38 | ) | ||||
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Capitalized interest
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18 | 12 | ||||||
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Commodity derivative income (expense)
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(182 | ) | 237 | |||||
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Other
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(1 | ) | 2 | |||||
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Total other income (expenses)
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(205 | ) | 213 | |||||
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Income (loss) before income taxes
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(27 | ) | 388 | |||||
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Income tax provision (benefit)
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(10 | ) | 144 | |||||
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Net income (loss)
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$ | (17 | ) | $ | 244 | |||
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Earnings (loss) per share:
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||||||||
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Basic --
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$ | (0.13 | ) | $ | 1.87 | |||
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Diluted --
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$ | (0.13 | ) | $ | 1.84 | |||
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Weighted-average number of shares outstanding
for basic earnings (loss) per share
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133 | 130 | ||||||
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Weighted-average number of shares outstanding
for diluted earnings (loss) per share*
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133 | 133 | ||||||
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* Had the Company recognized net income for the three month period ended March 31, 2011, the weighted average number of shares outstanding for the computation of diluted earnings per share would have increased by two million shares.
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7
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CONDENSED CONSOLIDATED BALANCE SHEET
(Unaudited, in millions)
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March 31,
2011
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December 31,
2010
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ASSETS
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||||||||
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Current assets:
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||||||||
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Cash and cash equivalents
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$ | 56 | $ | 39 | ||||
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Derivative assets
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153 | 197 | ||||||
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Other current assets
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498 | 495 | ||||||
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Total current assets
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707 | 731 | ||||||
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Property and equipment, net (full cost method)
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6,858 | 6,608 | ||||||
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Derivative assets
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28 | 39 | ||||||
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Other assets
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123 | 116 | ||||||
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Total assets
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$ | 7,716 | $ | 7,494 | ||||
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LIABILITIES AND STOCKHOLDERS’ EQUITY
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||||||||
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Current liabilities:
|
||||||||
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Current liabilities
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$ | 783 | $ | 875 | ||||
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Derivative liabilities
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148 | 53 | ||||||
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Total current liabilities
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931 | 928 | ||||||
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Other liabilities
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157 | 153 | ||||||
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Derivative liabilities
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133 | 46 | ||||||
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Long-term debt
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2,428 | 2,304 | ||||||
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Deferred taxes
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739 | 720 | ||||||
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Total long-term liabilities
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3,457 | 3,223 | ||||||
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STOCKHOLDERS’ EQUITY
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||||||||
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Common stock and additional paid-in capital
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1,409 | 1,410 | ||||||
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Accumulated other comprehensive loss
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(9 | ) | (12 | ) | ||||
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Retained earnings
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1,928 | 1,945 | ||||||
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Total stockholders’ equity
|
3,328 | 3,343 | ||||||
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Total liabilities and stockholders’ equity
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$ | 7,716 | $ | 7,494 | ||||
8
|
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited, in millions)
|
For the
Three Months Ended
March 31,
|
|||||||
|
2011
|
2010
|
|||||||
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Cash flows from operating activities:
|
||||||||
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Net income (loss)
|
$ | (17 | ) | $ | 244 | |||
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
|
||||||||
|
Depreciation, depletion and amortization
|
166 | 147 | ||||||
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Deferred tax provision (benefit)
|
(33 | ) | 131 | |||||
|
Stock-based compensation
|
6 | 6 | ||||||
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Commodity derivative (income) expense
|
182 | (237 | ) | |||||
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Cash receipts on derivative settlements, net
|
55 | 102 | ||||||
|
Other
|
2 | — | ||||||
| 361 | 393 | |||||||
|
Changes in operating assets and liabilities
|
(52 | ) | 21 | |||||
|
Net cash provided by operating activities
|
309 | 414 | ||||||
|
Cash flows from investing activities:
|
||||||||
|
Additions to oil and gas properties and other, net
|
(469 | ) | (342 | ) | ||||
|
Acquisitions of oil and gas properties
|
— | (217 | ) | |||||
|
Proceeds from sales of oil and gas properties
|
62 | 2 | ||||||
|
Redemption of investments
|
— | 1 | ||||||
|
Net cash used in investing activities
|
(407 | ) | (556 | ) | ||||
|
Cash flows from financing activities:
|
||||||||
|
Net proceeds (repayments) under credit arrangements
|
124 | (364 | ) | |||||
|
Net proceeds from issuance of senior subordinated notes
|
— | 694 | ||||||
|
Repayment of senior notes
|
— | (143 | ) | |||||
|
Other
|
(9 | ) | (11 | ) | ||||
|
Net cash provided by financing activities
|
115 | 176 | ||||||
|
Increase in cash and cash equivalents
|
17 | 34 | ||||||
|
Cash and cash equivalents, beginning of period
|
39 | 78 | ||||||
|
Cash and cash equivalents, end of period
|
$ | 56 | $ | 112 | ||||
9
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 2011 stated without the effect of certain items to net income (loss) is shown below:
| 1Q11 | ||||
| (in millions) | ||||
|
Net loss
|
$ | (17 | ) | |
|
Net unrealized loss on commodity derivatives (1)
|
237 | |||
|
Income tax adjustment for above item
|
(87 | ) | ||
|
Earnings stated without the effect of the above items
|
$ | 133 | ||
(1) The determination of “Net unrealized loss on commodity derivatives” for the first quarter of 2011 is as follows:
| 1Q11 | ||||
| (in millions) | ||||
|
Commodity derivative expense
|
$ | 182 | ||
|
Cash receipts on derivative settlements, net
|
55 | |||
|
Net unrealized loss on commodity derivatives
|
$ | 237 | ||
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:
| 1Q11 | ||||
| (in millions) | ||||
|
Net cash provided by operating activities
|
$ | 309 | ||
|
Net change in operating assets and liabilities
|
52 | |||
|
Net cash provided by operating activities before changes
in operating assets and liabilities
|
$ | 361 | ||
10