Exhibit 99.2
@NFX is periodically published to keep shareholders aware of current operating activities at Newfield. It may include estimates of expected production volumes, costs and expenses, recent changes to hedging positions and commodity pricing.
April 23, 2008
This edition of @NFX includes:
| | • | | Highlights from the first quarter of 2008 |
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| | • | | Additional full year and second quarter 2008 guidance |
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| | • | | Updated tables detailing complete hedging positions |
1Q08 HIGHLIGHTS
| | 1) | | First quarter production of 55.1 Bcfe exceeds upper end of guidance range |
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| | 2) | | We raised 2008 production guidance to 224-234 Bcfe, an increase of 18-23% over pro forma 2007 production (previous guidance was 215-230 Bcfe) |
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| | 3) | | The Woodford development reaches production high of 187 MMcfe/d gross; extended lateral completions demonstrate superior economics; more than 80% of planned ‘08 wells will be extended laterals and drilled from multi-well pads; we signed additional firm transportation for our growing production |
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| | 4) | | We announced three exploration discoveries — 2 in deepwater GOM and one in the Pearl River Mouth Basin offshore China |
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| | 5) | | The Monument Butte field is producing a record 15,000 BOPD gross |
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| | 6) | | We drilled a significant well in our South Texas Sarita field, extended the limits of the field, setting up additional development locations and increasing the potential of a recent JV with a private company to the south of this field. |
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| | 7) | | We recently agreed to acquire a package of South Texas properties from a private company for $227 million. |
PRODUCTION GUIDANCE
Our production in the first quarter of 2008 was 55.1 Bcfe. Production results exceeded the upper end of earlier guidance due to higher than expected production volumes from the Woodford, increased oil sales from Malaysia and better than expected production from the deepwater Gulf of Mexico. All of our business units are growing in 2008. Production in the first quarter of 2008 was 10% higher than production in the fourth quarter of 2007 and 20% above the same period of last year (adjusted for asset sales and acquisitions).
We increased our 2008 production forecast to 224-234 Bcfe, up 18-23% over pro forma 2007 production. Previous 2008 guidance was 215-230 Bcfe. The increase reflects the strength of current production, a recently signed agreement for a bolt-on acquisition in South Texas (adds 4.5 Bcfe to estimated ‘08 production) and additional rigs in the Woodford and Monument Butte. The South Texas acquisition is expected to close around May 1 and current net production is 19 MMcfe/d.
MID-CONTINENT
The Mid-Continent region is our largest division with approximately 1.1 Tcfe of proved reserves at year-end 2007. Our most significant area of activity remains the Woodford Shale play, located in southeastern Oklahoma. We are the leader in the Woodford with 165,000 net acres. We also have approximately 50,000 acres in the Mountain Front Wash play, located in the Texas Panhandle and western Oklahoma.
THE WOODFORD
A record 46 active industry rigs in the Woodford —The Woodford remains the most active play in Oklahoma with a record 46 industry rigs currently running. To date, we have spud 183 horizontal wells. Industry has spud more than 548 horizontal wells and at the current pace 100 new horizontal wells are being spud per quarter in the Woodford.
Our Woodford production is growing —Since year-end 2007, our production in the Woodford Shale has increased nearly 15%. Our gross operated daily production is 187 MMcfe/d. We expect that our gross operated production will exit 2008 at more than 250 MMcfe/d, an increase of more than 50% over year-end 2007 production.
We signed additional firm transportation for our growing Woodford production —We recently signed an agreement to increase our firm transportation on the MidContinent Express Pipeline (MEP) by 100,000 dekatherms per day (dth/d). We now have 300,000 dth/d of firm transportation on the MEP and we dedicated up to an additional 150,000 dth/d of natural gas production as it becomes available, which may increase our firm capacity to 450,000 dth/d on the MEP. Under a previously announced separate agreement, we also have firm transportation of 40,000 dth/d in 2008, increasing to 50,000 dth/d in 2009, with Laclede Energy Resources, Inc.
>80% of our planned wells in 2008 will be extended lateral completions —Extended laterals are significantly lowering our cost to find and develop reserves. Drilling results and recently processed 3-D seismic data indicate that we can drill more than 80% of our 2008 wells as extended laterals — up from an estimate of 50% at the beginning of 2008.
We are now producing from 20 extended lateral completions —We now have 20 extended lateral wells producing today — some of which have as much as 450 days of production. In addition, we have 6 extended laterals that commenced production in the last week and are cleaning up after fracture stimulation. There are 10 additional long laterals that have been drilled and will commence production in the next 30 days. The chart below illustrates performance from the 20 wells on-line today:
We are increasing our operated rig count —Currently, we are operating 11 rigs in the Woodford. Based on the success of recent drilling and cost reductions, a 12th drilling rig is being added for the remainder of 2008. We expect to drill nearly 120,000 feet of additional lateral in 2008 compared to 2007.
80% of our 2008 wells will be drilled from pads —Eight of our 11 operated rigs are drilling from multi-well pads. Pad drilling has helped to significantly decrease completed well costs through the elimination of roads, and by minimizing rig mobilization days between spuds. In addition, pads allow for the use of common fracture stimulation sites that further reduce completion costs. We expect that about 80% of our planned operated wells in 2008 will be drilled from multi-well pads, up from our beginning of the year estimate of 50%.
We continue to reduce the cost of our extended lateral wells —The most recent extended lateral wells have had initial gross production rates of more than 7 MMcfe/d and were drilled and completed for approximately $6.7 million (gross). Estimated ultimate gross recoveries are more than 4.5 Bcfe. Our recent wells have had lateral lengths of up to 4,700’ and are completed with nine fracture stimulation stages.
Standard lateral drill and complete costs down 15% —We also continue to reduce costs associated with our standard lateral completions (those with less than 3000’ of horizontal section). Our standard wells averaged approximately $5.7 million (gross) in 2007. Our most recent standard lateral wells, drilled from common pads, have averaged less than $5 million (gross). About 20% of
the wells we plan to drill in 2008 will be standard lateral completions.
Multiple spacing pilots ongoing throughout the acreage —We are conducting 16 spacing pilots in 2008 to determine optimal development well spacing. Ten of the pilots are being drilled on 40-acre spacing, four on 60-acre spacing and two on 80-acre spacing. To date, we have drilled and placed on production five development pilots that consist of 18 wells on varying development spacing, including 40, 60 and 80-acres. The production performance from these 18 wells is in line with our expectations.
Typical Woodford Well Economic Assumptions
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| Lease Burden: | | | 19.0 | % |
| Fixed LOE ($/MCF): | | $ | 0.45 | |
| Production Tax (% of Rev): | | | 7.09 | % |
| - Production Tax During Credit Period (% of Rev): | | | 1.09 | % |
| - Production Tax — Credit Period (Months): | | | 48 | |
| Wellhead Pricing vs. Henry Hub ($MCF) | | -$ | 0.75 | |
| Total Fuel Gas %: | | | 8.0 | % |
MOUNTAIN FRONT WASH
Our production in the Mountain Front Wash set a record in Q1 —We continue to grow our production in the Mountain Front Wash Play, located in the Texas Panhandle and western Oklahoma. Our production from the region set a new high of 110 MMcfe/d (gross) during the first quarter of 2008. Our interest is predominately 100% and we have approximately 50,000 net acres in the area.
ROCKY MOUNTAINS
Monument Butte
Increased black wax demand leads to addition of fifth drilling rig —Demand for black wax crude has increased and we entered into additional firm sales agreements with area refiners. We have added a fifth drilling rig in the field and expect to drill approximately 240 wells in 2008.
Monument Butte production reaches record 15,000 BOPD—Current production at Monument Butte is approximately 15,000 BOPD gross. We have drilled 680 wells in the field and doubled production since acquiring it in late 2004. The field has more than 1,000 producing oil wells. Production is expected to exit the year at more than 16,000 BOPD.
Success continues with our 20-acre spacing program —To date, we have drilled 65 wells on 20-acre spacing. Results indicate the potential to drill an additional 1,000-2,500 wells on 20-acre spacing. These well locations are in addition to the more than 1,000 locations remaining to drill the field down to 40-acre spacing.
Mancos Shale —We are drilling the first of several deep Mancos Shale tests beneath Monument Butte under a Deep Gas Exploration Agreement signed earlier this year with Red Technology Alliance. The well is being drilled to a total depth of 16,600 feet. In addition to the Mancos Shale, other prospective targets include the Wasatch, Mesa Verde and Blackhawk formations. All of these are known gas producers in the region. The agreement allows for promoted exploratory drilling and progressive earning in approximately 71,000 net acres in which we will retain a greater than 70% interest. Approximately 10,700 net acres in the immediate vicinity of recent deep gas tests were excluded from the agreement. We plan to drill several operated Mancos Shale prospects in the excluded area in the second half of 2008 (NFX WI: 85%). Under a separate JV, we are currently participating in the completion and testing of two Mancos Shale wells in the area.
Williston Basin
We now have nearly 250,000 gross acres in the Williston Basin —We have assembled 244,000 gross acres (160,000 net acres) in the Williston Basin. Our acreage position, which was built over the last three years, has prospective targets that include the Bakken, as well as the Madison and Red River formations. We expect to drill 10 operated wells in the area in 2008 and to participate in several outside operated wells. Our current net production from the area is about 2,550 BOEPD.
We have several alliances and joint ventures throughout the region and are drilling our third Bakken well along the Nesson Anticline. This well is on our Lost Bear Prospect area. A separate structure is currently testing. We expect to have results from these wells in the second quarter.
Pinedale Field, Green River Basin
Through an agreement reached in 2007 with BP, we retained operatorship of our interests in the Pinedale field and increased our working interest to 85%. Year-to-date, we have completed four new wells with flow rates between 5 and 8 MMcfe/d. Our current production from Pinedale is approximately 25 MMcf/d net. We plan to drill 6-7 wells here in 2008.
GULF COAST
Deepwater GOM Exploration Discoveries —We recently drilled two successful exploration wells in the deepwater Gulf of Mexico. The Gladden prospect, located at Mississippi Canyon 800, found 80 feet of net oil pay. An updip location is being drilled that is expected to be completed in May. The Anduin West prospect, located at Mississippi Canyon 754, found 30 feet of net gas and condensate pay. The well is being completed and a production test is planned in the next week. We are the operator of both discoveries and have a 47.5% working interest in Gladden and a 50% working interest in Anduin West. We have production handling agreements in place with nearby host facilities and expect first production from both fields in late 2009.
Success on 19 of 28 bids in recent OCS Lease Sale —In the March 2008 Federal OCS Lease Sale, we were high-bidder on 19 of 28 lease blocks (14 located in deepwater). If all blocks are awarded, the net investment will be approximately $70 million. We now have an inventory of prospects that will allow us to drill 3-5 wells per year for the next several years. A map of our deepwater inventory and its proximity to infrastructure is shown below:
We agreed to acquire a package of South Texas assets for $227 MM —We recently agreed to acquire a package of South Texas properties from a private company for $227 million. Current net production associated with the properties is approximately 19 MMcfe/d. Risked proved and probable reserves for the acquisition are 100 Bcfe, about half of which is classified as proved under SEC guidelines. Newfield has identified more than 100 drilling locations on the acquired acreage and sees the potential to add more than 200 Bcfe of total reserves from this acquisition. The acquisition is expected to close within a week and will be financed under our $1.25 billion revolver. Some of the transaction’s attributes are outlined below:
| • | | Geographic “fit” — The assets are located in the heart of our South Texas focus area, where we have been active since the late 1990s. The geographic region is known for multi-pay fields and active producing trends, including the Wilcox and Vicksburg formations. The properties can be actively developed without additional personnel. |
| • | | Expansion — The acquisition adds 47,000 gross acres (32,000 net acres) in two of Texas’ most prolific producing trends. Lower risk Wilcox drilling opportunities exist in Bee and Live Oak Counties. The transaction adds about 11,000 acres in the Vicksburg Trend in Brooks County, located adjacent to current Newfield activities. |
Following the closing of this transaction, we will own interests in more than 400,000 gross acres and nearly 700 producing wells in Texas.
Sarita Field Area
B-94 well a significant extension to Sarita development —We recently drilled our 26th successful well — the B-94 — under our South Texas joint venture with Exxon-Mobil. The B-94 was a 7,000’ step out that significantly expanded the productive area of the Sarita Field. Production under the joint venture set a new high in the first quarter of 85 MMcfe/d (gross). We have a 50% interest and expect to run 2-4 rigs throughout 2008.
Exploration well to spud next week on 42,000 acre JV with private co —Last year, we entered into a joint venture with a private company covering 42,000 acres southeast of Sarita and acquired 3-D seismic data. The success of the B-94 well high grades the potential of this new area. We plan to spud the first of two high potential 2008 exploration wells next week. We have identified prolific targets at depths of up to 20,000’. We have a 50% working interest in the venture.
In theSouth Texas Lobo Trend, we also had a discovery with the Salinas GU #1 that is currently producing 7 MMcf/d. We just finished drilling an offset, the Salinas GU #2, which confirms the same productive zone as the #1. The Salinas GU #3, another offset, will spud next. We have an 84% working interest in the Salinas wells.
In theVal Verde Basin, we recently extended the Poulter Field with the Poulter 2704 well, which flowed 6 MMcf/d from the Strawn formation. An offset to that well is planned for later this year.
INTERNATIONAL
Offshore China
Offshore China Exploration Discovery —We made an oil discovery during the first quarter of 2008 with the LF7-2-1 exploration well, located in the Pearl River Mouth Basin. The well found nearly 60 feet of net oil pay and tested the first of a series of features on a structural ridge. Additional drilling is planned for late 2008 or early 2009. We operate the discovery with a 100% interest, subject to the Chinese National Offshore Oil Company’s right to take a 51% interest during development. A separate exploratory well drilled during the quarter, the HZ28-1-1, was not commercial.
Malaysia
Puteri, E. Belumut, Chermingat production slated for second quarter —The Puteri production platform, located on PM 318, is undergoing final commissioning and the export pipeline has been installed. We expect the field to commence first oil production in the second quarter and ramp up to 6,000-8,000 BOPD (gross). We recently installed the production facility for the East Belumut and Chermingat fields, located on PM 323. A rig is on location and we expect production from the fields to begin in the second quarter. The combined rate from these fields will ramp up to 15,000
BOPD (gross). The Abu Field, PM 318, has ramped up to a planned production rate of 15,000 BOPD (gross) and the field achieved payout in the first quarter of 2008 — less than 10 months from the date of first production. Newfield has a 50% interest in PM 318 and a 60% operated interest in PM 323.
The Puteri platform, located on PM 318 in Malaysia, is undergoing final commissioning.
2008 CAPITAL BUDGET
Capital expenditures in the first quarter of 2008 were $514 million, in line with our first quarter budget. We increased our 2008 capital budget to $2 billion from an initial budget of $1.6 billion. The budget excludes approximately $115 million of capitalized interest and overhead. The increase reflects the following:
| § | | the recently signed agreement for a $227 million acquisition of properties in South Texas and subsequent development drilling activities; |
| § | | bidding success at the most recent Gulf of Mexico lease sale; |
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| § | | development capital for the recent Anduin West and Gladden deepwater GOM discoveries; |
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| § | | an additional drilling rig in the Woodford; and |
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| § | | an additional drilling rig in Monument Butte |
1Q08 ACTUAL RESULTS AND 2Q08 ESTIMATES
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| | | | 1Q08 Actuals | | | 2Q08 Guidance |
| | | | Domestic | | Int’l | | Total | | | Domestic | | Int’l | | Total |
Production/Liftings | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas-Bcf | | | | 40.4 | | | | — | | | | 40.4 | | | | | 40.7 - 43.5 | | | | — | | | | 40.7 - 43.5 | |
| Oil and condensate-MMBbl | | | | 1.4 | | | | 1.0 | | | | 2.4 | | | | | 1.3 - 1.4 | | | | 0.75 - 0.85 | | | | 2.0 - 2.2 | |
| Total Bcfe | | | | 48.9 | | | | 6.2 | | | | 55.1 | | | | | 48.5 - 51.9 | | | | 4.5 - 5.1 | | | | 53 - 57 | |
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Average Realized PricesNote 1 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas-$/Mcf | | | $ | 7.89 | | | $ | — | | | $ | 7.89 | | | | Note 2
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| Crude oil-$/Bbl | | | $ | 47.16 | | | $ | 85.38 | | | $ | 63.28 | | | | Note 3
| | Note 4
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| Mcf equivalent-$/Mcfe | | | $ | 7.88 | | | $ | 14.23 | | | $ | 8.60 | | | | | | | | | | | | | | |
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Operating Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Recurring ($ MM) | | | $ | 38.6 | | | $ | 12.5 | | | $ | 51.1 | | | | $ | 39.9 - $44.1 | | | $ | 10.5 - $11.6 | | | $ | 50.4 - $55.7 | |
| per/Mcfe | | | $ | 0.79 | | | $ | 2.01 | | | $ | 0.93 | | | | $ | 0.81 - $0.87 | | | $ | 2.17 - $2.45 | | | $ | 0.93 - $1.00 | |
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| Major (workovers, repairs, etc) ($MM) | | | $ | 7.9 | | | $ | — | | | $ | 7.9 | | | | $ | 5.3 - $5.9 | | | $ | 0.8 - $0.9 | | | $ | 6.1 - $6.8 | |
| per/Mcfe | | | $ | 0.16 | | | $ | — | | | $ | 0.14 | | | | $ | 0.11 - $0.12 | | | $ | 0.17 - $0.19 | | | $ | 0.11 - $0.12 | |
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Production and other taxes ( $MM)Note 5 | | | $ | 21.7 | | | $ | 29.3 | | | $ | 51.1 | | | | $ | 29.3 - $32.4 | | | $ | 21.6 - $23.9 | | | $ | 51.0 - $56.3 | |
| per/Mcfe | | | $ | 0.44 | | | $ | 4.71 | | | $ | 0.93 | | | | $ | 0.60 - $0.64 | | | $ | 4.47 - $5.06 | | | $ | 0.94 - $1.01 | |
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General and administrative (G&A), net ($MM) | | | $ | 30.8 | | | $ | 0.8 | | | $ | 31.6 | | | | $ | 33.1 - $36.6 | | | $ | 1.3 - $1.5 | | | $ | 34.4 - $38.1 | |
| per/Mcfe | | | $ | 0.63 | | | $ | 0.13 | | | $ | 0.57 | | | | $ | 0.67 - $0.72 | | | $ | 0.28 - $0.31 | | | $ | 0.63 - $0.68 | |
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| Capitalized G&A ($MM) | | | | | | | | | | | $ | (15.5 | ) | | | | | | | | | | | $ | (15.5 - $17.1 | ) |
| per/Mcfe | | | | | | | | | | | $ | (0.28 | ) | | | | | | | | | | | $ | (0.29 - $0.31 | ) |
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Interest expense ($MM) | | | | | | | | | | | $ | 19.3 | | | | | | | | | | | | $ | 18.4 - $20.4 | |
| per/Mcfe | | | | | | | | | | | $ | 0.35 | | | | | | | | | | | | $ | 0.34 - $0.37 | |
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Capitalized interest ($MM) | | | | | | | | | | | $ | (13.4 | ) | | | | | | | | | | | $ | (13.4 - $14.8 | ) |
| per/Mcfe | | | | | | | | | | | $ | (0.24 | ) | | | | | | | | | | | $ | (0.25 - $0.27 | ) |
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Effective tax rate (%) | | | | | | | | | | | | 40.4 | % | | | | | | | | | | | | 39.0 | % |
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Income taxes (%) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current | | | | | | | | | | | | 24 | % | | | | | | | | | | | | 22% - 25 | % |
| Deferred | | | | | | | | | | | | 76 | % | | | | | | | | | | | | 75% - 78 | % |
Note 1: Actual 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 $7.54 per Mcf and the total oil and condensate average realized price would have been $85.18 per barrel.
Note 2: Gas prices in the Mid-Continent, after basis differentials, transportation and handling charges, typically average 75-85% 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 about $5 per barrel below the NYMEX WTI price. Rockies oil prices average about $13-$15 per barrel below WTI. Oil production from the Mid-Continent typically sells at a $1.00-$1.50 per barrel below WTI.
Note 4: Oil in Malaysia typically sells at Tapis, or about 95% of WTI. Oil production from China typically sells at $10-$15 per barrel below WTI.
Note 5: Guidance for production taxes determined using $100/Bbl oil and $10/MMBtu gas.
NATURAL GAS HEDGE POSITIONS
Please see the tables below for our complete hedging positions.
The following hedge positions for the second quarter of 2008 and beyond are as of April 23, 2008:
Second Quarter 2008
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| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 25,325 MMMBtus | | $ | 7.96 | | | | — | | | | — | | | | — | | | | — | |
| 5,715 MMMBtus | | | — | | | | — | | | $ | 7.64-$9.34 | | | $ | 7.00-$8.00 | | | $ | 9.00-$9.70 | |
| 5,460 MMMBtus | | | — | | | $ | 8.64 | | | | — | | | $ | 8.58-$8.70 | | | | — | |
Third Quarter 2008
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| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 26,220 MMMBtus | | $ | 7.97 | | | | — | | | | — | | | | — | | | | — | |
| 5,760 MMMBtus | | | — | | | | — | | | $ | 7.64-$9.34 | | | $ | 7.00-$8.00 | | | $ | 9.00-$9.70 | |
| 5,520 MMMBtus | | | — | | | $ | 8.64 | | | | — | | | $ | 8.58-$8.70 | | | | — | |
Fourth Quarter 2008
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| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 9,445 MMMBtus | | $ | 8.04 | | | | — | | | | — | | | | — | | | | — | |
| 15,965 MMMBtus | | | — | | | | — | | | $ | 8.03-$10.70 | | | $ | 7.00-$9.00 | | | $ | 9.00-$17.60 | |
| 6,100 MMMBtus** | | | — | | | | — | | | $ | 8.70-$13.92 | | | $ | 8.00-$9.00 | | | $ | 11.72-$20.10 | |
| 1,860 MMMBtus | | | — | | | $ | 8.64 | | | | — | | | $ | 8.58-$8.70 | | | | — | |
First Quarter 2009
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| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 900 MMMBtus | | $ | 9.00 | | | | — | | | | — | | | | — | | | | — | |
| 21,150 MMMBtus | | | — | | | | — | | | $ | 8.09-$10.88 | | | $ | 8.00-$9.00 | | | $ | 9.67-$17.60 | |
| 9,000 MMMBtus** | | | — | | | | — | | | $ | 8.70-$13.92 | | | $ | 8.00-$9.00 | | | $ | 11.72-$20.10 | |
Second Quarter 2009
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 3,185 MMMBtus | | $ | 8.40 | | | | — | | | | — | | | | — | | | | — | |
| 4,095 MMMBtus | | | — | | | | — | | | $ | 8.00-$10.50 | | | $ | 8.00 | | | $ | 8.97-$13.00 | |
Third Quarter 2009
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 3,220 MMMBtus | | $ | 8.40 | | | | — | | | | — | | | | — | | | | — | |
| 4,140 MMMBtus | | | — | | | | — | | | $ | 8.00-$10.50 | | | $ | 8.00 | | | $ | 8.97-$13.00 | |
Fourth Quarter 2009
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 1,085 MMMBtus | | $ | 8.40 | | | | — | | | | — | | | | — | | | | — | |
| 1,395 MMMBtus | | | — | | | | — | | | $ | 8.00-$10.50 | | | $ | 8.00 | | | $ | 8.97-$13.00 | |
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| ** | | These 3-way collar contracts are standard natural gas collar contracts with respect to the periods, volumes and prices stated above. The contracts have floor and ceiling prices per MMBtu as per the table above until the price drops below a weighted average price of $7.20 per MMBtu. Below $7.20 per MMBtu, these contracts effectively result in realized prices that are on average $1.50 per MMBtu higher than the cash price that otherwise would have been realized |
The following table details the expected impact to pre-tax income from the settlement of our derivative contracts, outlined above, at various NYMEX gas prices, net of premiums paid for these contracts (in millions).
| | | | | | | | | | | | | | | | | | | | | |
| | | Gas Prices |
| | | $5.00 | | $6.00 | | $7.00 | | $8.00 | | $9.00 |
| | | |
2008 | | | | | | | | | | | | | | | | | | | | |
| 2nd Quarter | | $ | 110 | | | $ | 73 | | | $ | 37 | | | $ | 3 | | | $ | (26 | ) |
| 3rd Quarter | | $ | 113 | | | $ | 76 | | | $ | 38 | | | $ | 2 | | | $ | (27 | ) |
| 4th Quarter | | $ | 93 | | | $ | 66 | | | $ | 39 | | | $ | 7 | | | $ | (9 | ) |
| | | |
Total 2008 | | $ | 316 | | | $ | 215 | | | $ | 114 | | | $ | 12 | | | $ | (62 | ) |
| | | | | | | | | | | | | | | | | | | | | |
2009 | | $ | 136 | | | $ | 97 | | | $ | 58 | | | $ | 12 | | | $ | (5 | ) |
In conjunction with our recent acquisition of properties in the Rocky Mountains, we hedged basis associated with 50% of the proved producing fields from August 2007 through full-year 2012. The weighted average hedged differential during this period was $(1.18) per Mcf.
Approximately 31% of our natural gas production correlates to Houston Ship Channel, 25% to CenterPoint/East, 19% to Panhandle Eastern Pipeline, 10% to Waha, 7% to Colorado Interstate, 8% to others.
CRUDE OIL HEDGE POSITIONS
The following hedge positions for the second quarter of 2008 and beyond are as of April 23, 2008:
Second Quarter 2008
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 819,000 Bbls** | | | — | | | | — | | | $ | 33.00-$50.29 | | | $ | 32.00-$35.00 | | | $ | 49.50-$52.90 | |
Third Quarter 2008
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 828,000 Bbls** | | | — | | | | — | | | $ | 33.00-$50.29 | | | $ | 32.00-$35.00 | | | $ | 49.50-$52.90 | |
Fourth Quarter 2008
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 828,000 Bbls** | | | — | | | | — | | | $ | 33.00-$50.29 | | | $ | 32.00-$35.00 | | | $ | 49.50-$52.90 | |
First Quarter 2009
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 810,000 Bbls** | | | — | | | | — | | | $ | 33.33-$50.62 | | | $ | 32.00-$36.00 | | | $ | 50.00-$54.55 | |
Second Quarter 2009
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 819,000 Bbls** | | | — | | | | — | | | $ | 33.33-$50.62 | | | $ | 32.00-$36.00 | | | $ | 50.00-$54.55 | |
Third Quarter 2009
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 828,000 Bbls** | | | — | | | | — | | | $ | 33.33-$50.62 | | | $ | 32.00-$36.00 | | | $ | 50.00-$54.55 | |
Fourth Quarter 2009
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 828,000 Bbls** | | | — | | | | — | | | | $33.33-$50.62 | | | | $32.00-$36.00 | | | | $50.00-$54.55 | |
First Quarter 2010
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 90,000 Bbls | | $ | 93.40 | | | | — | | | | — | | | | — | | | | — | |
| 810,000 Bbls** | | | — | | | | — | | | | $35.22-$51.59 | | | | $32.00-$38.00 | | | | $50.00-$53.50 | |
Second Quarter 2010
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 90,000 Bbls | | $ | 93.40 | | | | — | | | | — | | | | — | | | | — | |
| 819,000 Bbls** | | | — | | | | — | | | $ | 35.22-$51.59 | | | $ | 32.00-$38.00 | | | $ | 50.00-$53.50 | |
Third Quarter 2010
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 90,000 Bbls | | $ | 93.40 | �� | | | — | | | | — | | | | — | | | | — | |
| 828,000 Bbls** | | | — | | | | — | | | $ | 35.22-$51.59 | | | $ | 32.00-$38.00 | | | $ | 50.00-$53.50 | |
Fourth Quarter 2010
| | | | | | | | | | | | | | | | | | | | | |
| | | Weighted Average | | Range |
| Volume | | Fixed | | Floors | | Collars | | Floor | | Ceiling |
| 90,000 Bbls | | $ | 93.40 | | | | — | | | | — | | | | — | | | | — | |
| 828,000 Bbls** | | | — | | | | — | | | $ | 35.22-$51.59 | | | $ | 32.00-$38.00 | | | $ | 50.00-$53.50 | |
| | |
| ** | | These 3-way collar contracts are standard crude oil collar contracts with respect to the periods, volumes and prices stated above. The contracts have floor and ceiling prices per barrel as per the table above until the price drops below a weighted average price of $27.60 per barrel. Below $27.60 per barrel, these contracts effectively result in realized prices that are on average $6.32 per barrel higher than the cash price that otherwise would have been realized. |
The following table details the expected impact to pre-tax income from the settlement of our derivative contracts, outlined above, at various NYMEX oil prices, net of premiums paid for these contracts (in millions).
| | | | | | | | | | | | | | | | | | | | | |
| | | Oil Prices |
| | | $50.00 | | $60.00 | | $70.00 | | $80.00 | | $90.00 |
| | | |
2008 | | | | | | | | | | | | | | | | | | | | |
| 2nd Quarter | | $ | — | | | $ | (8 | ) | | $ | (16 | ) | | $ | (24 | ) | | $ | (33 | ) |
| 3rd Quarter | | $ | (1 | ) | | $ | (9 | ) | | $ | (17 | ) | | $ | (25 | ) | | $ | (33 | ) |
| 4th Quarter | | $ | — | | | $ | (8 | ) | | $ | (17 | ) | | $ | (25 | ) | | $ | (33 | ) |
| | | |
Total 2008 | | $ | (1 | ) | | $ | (25 | ) | | $ | (50 | ) | | $ | (74 | ) | | $ | (99 | ) |
| | | |
| | | | | | | | | | | | | | | | | | | | | |
2009 | | $ | (1 | ) | | $ | (32 | ) | | $ | (65 | ) | | $ | (97 | ) | | $ | (130 | ) |
| | | | | | | | | | | | | | | | | | | | | |
2010 | | $ | 15 | | | $ | (16 | ) | | $ | (52 | ) | | $ | (89 | ) | | $ | (125 | ) |
We provide information regarding our outstanding hedging positions in our annual and quarterly reports filed with the SEC and in our electronic publication — @NFX. This publication can be found on Newfield’s web page athttp://www.newfield.com. Through the web page, you may elect to receive @NFX through e-mail distribution.
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 the drilling of a balanced risk/reward portfolio and select acquisitions. Newfield’s domestic areas of operation include the U.S. onshore Gulf Coast, the Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains and the Gulf of Mexico. The Company has international operations in Malaysia and China.
**The statements set forth in this publication regarding estimated or anticipated second quarter 2008 results, estimated full-year 2008 production, drilling and development plans, the timing of activities, the timing of initial production and future rates of production from wells, fields and regions, expected cost reductions in the Woodford Play and the expected ultimate recovery of reserves from wells are forward looking and are based upon assumptions and anticipated results that are subject to numerous uncertainties. 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 capital resources, the availability of refining capacity for the crude oil we produces from our Monument Butte field in Utah and labor conditions. In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks.
