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.
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July 27, 2004
This edition of @NFX includes:
| • | Update on recent drilling activities; |
| • | Guidance for the third quarter of 2004; and |
| • | Updated tables detailing complete hedging positions |
Onshore Gulf Coast
During the second quarter, we drilled 12 successful wells out of 16 total wells in Texas and Louisiana. We operated all of the wells drilled during the second quarter. We are currently operating seven rigs (including workovers and recompletes) and are participating in four outside operated wells onshore Texas and Louisiana.
We made two significant discoveries during the second quarter in our Onshore Gulf Coast drilling program – the Moose Prospect in Southern Louisiana and the Packenham Prospect in the Val Verde Basin of southwest Texas. Details follow.
Southern Louisiana — MOOSE Prospect
Moose was a wildcat discovery. The well was drilled to nearly 23,700’ to test a high potential exploration prospect in the prolific Deep Tuscaloosa Trend. The well offsets the giant Judge Digby field in Point Coupee Parish. We logged 50’ of net gas pay and are currently formulating a development plan for this discovery, which will include additional development well locations. BP operates Moose with Newfield holding a 25% working interest. We have an interest in more than 6,000 acres in and around this new discovery.
Packenham Discovery
Packenham is a Val Verde Basin exploratory discovery. Located in Terrell County, Texas, the well was drilled below 11,000’ and found 80’ of net gas pay. We expect first production from the discovery well in the third quarter of 2004. We immediately spud an offset well — the Poulter 38-01 — which is drilling now. We see the potential to drill at least three additional wells through a drilling program slated to begin in the fourth quarter. We have a 60% operated interest in the Packenham discovery and 3,500 acres in the area.
The Val Verde Basin is our most active onshore Gulf Coast drilling area in 2004. We hold more than 100,000 lease acres in the basin where we are working three geologic trends. We are planning to drill 2-3
additional exploratory prospects during 2004. Success with any one of the exploration wells could set up multiple development well locations.
West Caney Creek Field
We continued to drill development wells in our West Caney Creek Field, located in Wharton County, Texas. We are offsetting the Davis Locke #2 well (a first quarter 2004 success) with the Corbett G.U. #1 well. We drilled two successful development wells during the quarter — the Peach Creek G.U. #’s 6 and 10. The #6 well is on-line and the #10 well is expected to add about 10 MMcfe/d. We’ve drilled 11 successful wells in the field and we continue to plan development wells. Current field production is about 42 MMcfe/d (gross). We operate with working interests ranging from 58-77%.
La Reforma Field
We have drilled four successful wells in the La Reforma Field since acquiring in the EEX transaction in late 2002. The field is located in Hidalgo County, Texas. During the second quarter, we successfully drilled the Guerra D-1 well, which came on-line at 10 MMcfe/d. Total field production is about 16 MMcfe/d gross. We are planning to drill an offset well to the Guerra D-1 later this year, as well as the C-3 exploration well. Newfield operates the field with a 50% working interest.
La Rucia Ranch Field
Development drilling continues in the La Rucia Ranch Field, located in Hidalgo County, Texas. During the second quarter, the La Rucia Ranch #18 and #19 wells were successfully drilled. The #18 well found 116’ of net gas pay in two sands and came on-line at 3.5 MMcf/d. The #19 well found 146’ of net gas pay in three sands and is currently being completed. We are currently drilling the #20. Following the drilling of this well, we plan to drill at least 3-4 additional development wells in the field. We operate this field with a 67% working interest.
Dinn Ranch Field
We’ve recently drilled one successful development well and are in the process of drilling a second in the Dinn Ranch Field, located in Duvall County, Texas. The Buck Hamilton #9 well was successful and came on-line at more than 16 MMcfe/d and is now producing 11 MMcfe/d. The Buck Hamilton #10 well is currently drilling. Current gross field production at Dinn Ranch is about 50 MMcf/d.
East Texas
We plan to drill up to 20 wells in East Texas in 2004. We are active in three main fields — Oak Hill, Hallsville and Carthage. Year-to-date, we have drilled 12 wells. Our working interest ranges from 45-100%. During the second quarter, we drilled three successful wells in the Oak Hill field and three successful wells in the NE Hallsville field. All the wells had more than 100’ of net gas pay and initial production per well averages about 1.3 MMcfe/d.
Gulf of Mexico
In the Gulf of Mexico, we drilled 11 wells in the second quarter with two dry holes. Including workover and completion operations, seven rigs are currently active.
Gulf of Mexico highlights include a deep shelf exploration discovery at West Cameron 77, and exploration successes at West Delta 133 and South Marsh Island 139. Details follow.
West Cameron 77 Discovery
The West Cameron 77 deep shelf test, located about 10 miles offshore Louisiana in about 40 feet of water, was a discovery. The WC 77 #1 well encountered approximately 120’ of net gas pay in two zones between
16,800’ — 17,600’. The well was deepened to 19,603’ (18,500’ vertical depth) and encountered an additional zone that appears to have possible pay over a large gross interval. We will evaluate this zone over the next 2-3 weeks as we complete the well. We are evaluating development plans for the discovery and expect first production from the field in early 2005. Depending on the depths of the pay sections completed in this wellbore, the field will qualify for 15-25 Bcf of royalty relief under the Minerals Management Service’s rules.
We operate the WC 77 discovery with a 45% working interest in a joint development area covering portions of WC 77 and WC 96, prior to payout. After payout, our interest, subject to a 25% back in by another operator, will be 33.75%.
We’ve drilled 12 successful deep shelf exploration wells out of 19 attempts to date. We expect to spud additional deep shelf tests in the remainder of 2004.
West Delta 133
The WD 133 #13 well found 150’ of net oil pay in five sands. The well was drilled to about 11,150’. The well is being completed and we expect first production in the fourth quarter of 2004. We own a 50% working interest in the new discovery.
South Marsh Island 139
The SMI 139 #1 discovery well found 15’ of net oil pay. The well was drilled to less than 10,000’. We have a 22.5% working interest in the well.
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High Island A-366
The HI A-366 #1 well was successful, finding about 150’ of net gas pay in five sands. We plan to set a platform and are evaluating drilling up to two additional field development wells to add additional reserves. We operate the development with a 39% working interest.
Glider Field — deepwater
On July 20, we commenced production from the Glider Field, located at Green Canyon 247/248 in about 3,400’ of water. The #3 well is now on-line and the #4 well is currently being completed. First production from the #4 well is expected in mid-August. Both the #3 and #4 subsea wells will be tied back to Shell’s Brutus platform. We have a 25% working interest in this Shell-operated development.
The Mississippi Canyon 291 #1 deepwater well, known as the Nelson Prospect, was a dry hole. We sold a 50% working interest in the well to another operator, whom, in return, agreed to pay 100% of the dry hole costs. We operated the well.
Gulf of Mexico Acquisition
On July 20, we closed on the acquisition of all of Denbury Resources Gulf of Mexico assets. After purchase price adjustments, total consideration is expected to be approximately $187 million, inclusive of the purchase of approximately $5 million in working capital. The following map details the properties and their relation to Newfield’s existing offshore assets.
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The transaction adds approximately 50 MMcfe/d of net gas production, of which 97 percent is natural gas. The acquisition was financed through cash on hand and the Company’s revolving credit facility.
Transaction Highlights:
| • | 38 Gulf of Mexico blocks, of which 32 are Company-operated. | |||
| • | 16 total fields. 90% of the reserves and 95% of the production come from seven fields. | |||
| • | 80% of the wells are Company-operated. | |||
| • | 95% of the reserves are Company-operated. | |||
| • | Average working interest in the properties is >75%. | |||
| • | Properties can be managed without additional G&A expense. | |||
Mid-Continent
We are operating 12 rigs and participating in five outside operated wells in the Mid-Continent. Year-to-date,
77 operated wells have been completed or are in various stages of completion. We have spud 30 outside operated wells, of which five are currently drilling, 12 are in various stages of completion and 13 are on-line.
Stiles Ranch and Buffalo Wallow
We are currently operating three rigs in these two Texas Panhandle areas (Hemphill and Wheeler Counties, Texas). Current gross production for the area is about 16 MMcfe/d. At Buffalo Wallow and Stiles Ranch, we are drilling deeper exploration wells to test prospective Granite Wash zones. We plan to drill about 20 wells in this area in 2004. Year-to-date, 12 wells have been drilled. We have a 100% working interest in these fields.
Arkoma Basin Play
This play play is located in Pittsburg, Hughes, Atokal, and Coal Counties, Oklahoma. We are currently operating four drilling rigs in the area. Year-to-date, we have drilled 22 wells in the area. Gross operated production for the area is now about 23 MMcf/d.
Grand Area
Year-to-date, we’ve drilled nearly 18 wells in the Grand Area and we are operating a one-rig program at this time. Current production is more than 15 MMcfe/d. In 2004, we plan to drill about 20 wells in this area.
Third Quarter 2004 Estimates
Natural Gas Production and Pricing
The Company’s natural gas production in the third quarter of 2004 is expected to be 47 – 51 Bcf (510 – 560 MMcf/d). The price the Company realizes for natural gas production from the Gulf of Mexico and onshore Gulf Coast typically averages $0.15 - $0.20 less than Henry Hub Index after basis differentials, transportation and handling charges. Realized gas prices for our Mid-Continent properties typically average $0.70 - - $0.80 less than Henry Hub Index after basis differentials, transportation and handling charges. Hedging gains or losses will affect price realizations.
Crude Oil Production and Pricing
Oil production in the third quarter of 2004 is expected to be 1.8 – 2.0 million barrels (19,000 – 21,000 BOPD). The price the Company receives for Gulf Coast production has typically averaged about $2 below the NYMEX West Texas Intermediate (WTI) price. Oil production from the Mid-Continent has typically sold at a $1.00 – $1.50 per barrel discount to WTI. Hedging gains or losses will affect price realizations.
Lease Operating and Other Expenses
LOE is expected to be $43 – $48 million ($0.72 – $0.80 per Mcfe) in the third quarter of 2004. Production taxes in the third quarter of 2004 are expected to be $12 – $14 million ($0.20 – $0.24 per Mcfe). These expenses vary and are subject to impact from, among other things, production volumes and commodity pricing, tax rates, service costs, the costs of goods and materials and workover activities.
General and Administrative Expense
G&A expense for the third quarter of 2004 is expected to be $17 – $19 million ($0.29 – $0.32 per Mcfe), net of capitalized direct internal costs. Capitalized G&A expense is expected to be $6 – $7 million. G&A expense includes stock and incentive compensation expense. Incentive compensation expense depends largely on net income.
Interest Expense
The non-capitalized portion of the Company’s interest expense for the third quarter of 2004 is expected to be $6 — $7 million ($0.10 — $0.11 per Mcfe). As of July 26, 2004, borrowings under the Company’s credit arrangements are $265 million. The remainder of long-term debt consists of three separate issuances of notes that in the aggregate total $550 million in principal amount. Capitalized interest for the third quarter of 2004 is expected to be about $5 — $7 million.
Income Taxes
Including both current and deferred taxes, the Company expects its consolidated income tax rate in the third quarter of 2004 to be about 35 — 39%. About 35% of the tax provision is expected to be deferred. Please see the tables below for our complete hedging positions
Natural Gas Hedge Positions
The following hedge positions for the third quarter of 2004 and beyond are as of July 27, 2004:
Third Quarter 2004
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 21,429 MMMBtus | $ | 5.06 | — | — | — | — | ||||||||||||||
| 11,595 MMMBtus | — | — | $ | 4.68 — $5.96 | $ | 3.00 — $5.25 | $ | 4.16 — $6.67 | ||||||||||||
| 2,250 MMMBtus | — | $ | 4.21 | — | $ | 4.20 — $4.21 | — | |||||||||||||
Fourth Quarter 2004
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 11,613 MMMBtus | $ | 5.40 | — | — | — | — | ||||||||||||||
| 9,795 MMMBtus | — | — | $ | 4.90 — $8.24 | $ | 3.00 — $5.25 | $ | 4.16 — $10.25 | ||||||||||||
| 8,850 MMMBtus | — | $ | 5.39 | — | $ | 4.20 — $5.50 | — | |||||||||||||
First Quarter 2005
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 5,807 MMMBtus | $ | 6.02 | — | — | — | — | ||||||||||||||
| 15,495 MMMBtus | — | — | $ | 5.32 — $9.88 | $ | 3.50 — $5.77 | $ | 4.16 — $10.25 | ||||||||||||
| 5,400 MMMBtus | — | $ | 5.49 | — | $ | 5.47 — $5.50 | — | |||||||||||||
Second Quarter 2005
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 4,860 MMMBtus | $ | 5.53 | — | — | — | — | ||||||||||||||
| 345 MMMBtus | — | — | $ | 3.50 — $4.16 | $ | 3.50 | $ | 4.16 | ||||||||||||
Third Quarter 2005
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 5,206 MMMBtus | $ | 5.53 | — | — | — | — | ||||||||||||||
| 345 MMMBtus | — | — | $ | 3.50 — $4.16 | $ | 3.50 | $ | 4.16 | ||||||||||||
Fourth Quarter 2005
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 5,025 MMMBtus | $ | 5.64 | — | — | — | — | ||||||||||||||
| 345 MMMBtus | — | — | $ | 3.50 — $4.16 | $ | 3.50 | $ | 4.16 | ||||||||||||
Natural Gas 3-Way Collars
| Floors | Collars | |||||||
Third Quarter 2004 | ||||||||
| 1,350 MMMBtus | $ | 3.50 | $ | 4.50 - $6.08 | ||||
| 900 MMMBtus | $ | 3.50 | $ | 4.50 - $6.10 | ||||
| 1,800 MMMBtus | $ | 3.76 | $ | 4.76 - $5.20 | ||||
| 900 MMMBtus | $ | 3.61 | $ | 4.61 - $5.20 | ||||
| 1,800 MMMBtus | $ | 3.62 | $ | 4.62 - $5.20 | ||||
Fourth Quarter 2004 | ||||||||
| 450 MMMBtus | $ | 3.50 | $ | 4.50 - $6.08 | ||||
| 300 MMMBtus | $ | 3.50 | $ | 4.50 - $6.10 | ||||
| 600 MMMBtus | $ | 3.76 | $ | 4.76 - $5.20 | ||||
| 300 MMMBtus | $ | 3.61 | $ | 4.61 - $5.20 | ||||
| 600 MMMBtus | $ | 3.62 | $ | 4.62 - $5.20 | ||||
These 3-way collar contracts are standard natural gas collar contracts with respect to the periods, volumes and prices stated above. The collar contracts have floor and ceiling prices per MMMBtu as per the table above until the market price drops below the floor price above. Below the floor price, these contracts effectively result in realized prices that are on average $1.00 per MMMBtu higher than the cash price that otherwise would have been realized.
Crude Oil Hedge Positions
The following hedge positions for the third quarter of 2004 and beyond are as of July 27, 2004:
Third Quarter 2004
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 264,000 Bbls | $ | 32.18 | — | — | — | — | ||||||||||||||
| 390,000 Bbls | — | — | $ | 26.35 — $31.56 | $ | 22.00 — $27.50 | $ | 26.35 — $34.50 | ||||||||||||
| 379,000 Bbls* | — | — | $ | 25.76 — $29.91 | $ | 25.00 — $26.00 | $ | 29.70 — $30.05 | ||||||||||||
Fourth Quarter 2004
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 204,000 Bbls | $ | 29.85 | — | — | — | — | ||||||||||||||
| 330,000 Bbls | — | — | $ | 27.14 — $32.51 | $ | 27.00 — $27.50 | $ | 30.65 — $34.50 | ||||||||||||
| 379,000 Bbls* | — | — | $ | 25.76 — $29.91 | $ | 25.00 — $26.00 | $ | 29.70 — $30.05 | ||||||||||||
First Quarter 2005
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 141,000 Bbls | $ | 27.37 | — | — | — | — | ||||||||||||||
| 240,000 Bbls | — | — | $ | 27.00 — $31.76 | $ | 27.00 | $ | 30.65 — $32.30 | ||||||||||||
| 90,000 Bbls* | — | — | $ | 25.00 — $29.70 | $ | 25.00 | $ | 29.70 | ||||||||||||
Second Quarter 2005
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 51,000 Bbls | $ | 22.63 | — | — | — | — | ||||||||||||||
| 150,000 Bbls | — | — | $ | 27.00 — $31.45 | $ | 27.00 | $ | 30.65 — $32.10 | ||||||||||||
Third Quarter 2005
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 51,000 Bbls | $ | 22.63 | — | — | — | — | ||||||||||||||
Fourth Quarter 2005
| Weighted Average | Range | |||||||||||||||||||
| Volume | Fixed | Floors | Collars | Floor | Ceiling | |||||||||||||||
| 51,000 Bbls | $ | 22.63 | — | — | — | — | ||||||||||||||
*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 $21.00 per barrel. Below $21.00 per barrel, these contracts effectively result in realized prices that are on average $4.61 per barrel higher than the cash price that otherwise would have been realized.
Any publicly announced changes to the above estimates, as well as periodic drilling updates, will be available through @NFX. Through our web page at www.newfld.com, stockholders may register to receive @NFX by e-mail distribution.
**Certain of the statements set forth in this @NFX regarding estimated or anticipated third quarter 2004 operating and financial data, capital expenditures, drilling plans and other activities and production volumes 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 and other factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2003. In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks.