@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.
October 21, 2008
This edition of @NFX includes:
| · | Fourth Quarter 2008 Estimates |
| · | Updated Tables Detailing Complete Hedging Positions |
HIGHLIGHTS
| - | We expect that our capital budget for 2009 will be $1.65 billion (including approximately $100 million of capitalized interest and overhead). This represents a $450 million decrease from our September 9, 2008, initial estimate of approximately $2.1 billion (including capitalized interest and overhead). Newfield expects to live within cash flow from operations in 2009. |
| - | Based on revised capital spending plans, Newfield expects production growth of 8 -13% in 2009 – or an expected range of 255 - 267 Bcfe. |
| - | Total company production guidance for 2008 was slightly increased to 235-238 Bcfe (previous range was 234-238 Bcfe). The increase relates to the pace of storm recoveries in the Gulf of Mexico. Production estimates for 2008 compare to 2007 actual production of approximately 190 Bcfe (adjusted for asset sales and acquisitions), representing an increase of approximately 25%. |
| - | NFX and partners today announced a significant deepwater discovery at the Dalmation Prospect. Please see details under the Gulf Coast section in this @NFX publication. |
Third Quarter 2008 Drilling Activity
&# 160; NFX Operated Non-Operated Gross Wells Dry Holes
| Mid-Continent | | | 28 | | | | 24 | | | | 52 | | | | 0 | |
| Rocky Mount. | | | 57 | | | | 3 | | | | 60 | | | | 0 | |
| Onshore GC | | | 19 | | | | 1 | | | | 26 | | | | 6 | |
| Gulf of Mexico | | | 0 | | | | 1 | | | | 1 | | | | 0 | |
| International | | | 3 | | | | 2 | | | | 5 | | | | 0 | |
| Total: | | | 107 | | | | 31 | | | | 144 | | | | 6 | |
Year-to-Date 2008 Drilling Activity
NFX Operated Non-Operated Gross Wells Dry Holes
| Mid-Continent | | | 95 | | | | 80 | | | | 176 | | | | 1 | |
| Rocky Mount. | | | 177 | | | | 11 | | | | 190 | | | | 2 | |
| Onshore GC | | | 48 | | | | 8 | | | | 68 | | | | 12 | |
| Gulf of Mexico | | | 3 | | | | 0 | | | | 4 | | | | 1 | |
| International | | | 8 | | | | 9 | | | | 18 | | | | 1 | |
| Total: | | | 331 | | | | 108 | | | | 456 | | | | 17 | |
MID-CONTINENT
THE WOODFORD SHALE
Our gross operated production from the Woodford Shale reached more than 220 MMcfe/d in September, up from 165 MMcfe/d at year end 2007. Gross production is expected to exit 2008 at approximately 250 MMcfe/d and production volumes in 2009 are expected to increase nearly 40% over 2008 levels.
The Woodford remains the most active play in Oklahoma and its development represents our largest capital expenditure. There are 736 industry horizontal wells drilled to date. We have operated more than 225 of these wells and have 165,000 net acres, of which approximately 80% is “held-by-production.”
The Woodford will remain our largest area of capital investment in 2009. We plan to run 12 operated rigs through the end of 2008 with this number increasing to 15 operated rigs in 2009. We have the option to add, or reduce, our rig count as service costs and/or commodity prices warrant.
We are currently completing our first dual lateral well (each lateral is 4,800’ in length) in the Woodford. The well was successfully drilled and completions are going as planned with first production in early November. Success with this concept could significantly lower development costs for the play. In November, we will spud our first “super extended” lateral of 8,000’ to 10,000’.
More than half of our operated rigs today are drilling from common pads. To date, we have completed and placed on production 59 wells drilled from pads. Cost improvements from the first well on a pad to the fourth well have ranged from 25% to as much as 75%. Pad drilling significantly decreases completed well costs through the elimination of roads, and by minimizing rig mobilization days between spuds, optimizing completion logistics as well as through reduced drilling days. In addition, pads allow for the use of common fracture stimulation sites that further reduce completion costs.
Woodford Firm Transportation Helps Maximize Future Price
In an effort to ensure that we minimize basis differentials, we have signed firm transportation for a substantial portion of our expected growth in the Woodford Shale. We have firm transportation on Midcontinent Express Pipeline (MEP) and sales to Laclede Energy Resources for a total of 360,000 dth/d of firm capacity in 2009. This will increase with Gulf Crossing Pipeline Company LLC beginning in March 2010 initially adding 100,000 dth/d. Firm transportation will incrementally expand to a maximum total of 600,000 dth/d in 2012.
MOUNTAIN FRONT WASH/STILES RANCH FIELD
Our working interest is predominately 100%, and we have approximately 50,000 net acres in the play, located in the Texas Panhandle and western Oklahoma. Drilling activity in Mountain Front Wash continues with 3 operated rigs running. Stiles Ranch hit a mid-year 2008 high of more than 110 MMcfe/d.
Horizontal drilling technology has dramatically changed the landscape of onshore drilling through more efficient reserve recovery and lower finding and development costs. The Stiles Ranch field, one of Newfield’s largest producing assets, has been developed to date with vertical wells. Our knowledge base from the Woodford Shale is now being applied to the future development of Stiles.
We recently performed a study on the feasibility of horizontal drilling in the Stiles Ranch field. Horizontal development has the potential to improve estimated recovery and lower F&D costs. We plan to test lateral lengths between 2,500’ and 4,000’. We are drilling our first horizontal well with a planned lateral length of 3,800’. We have an extensive inventory of drilling locations in Stiles Ranch – including up to 110 horizontal locations. We plan to dedicate at least 1 of 3 rigs next year to drilling horizontal wells.
ROCKY MOUNTAINS
MONUMENT BUTTE
Our largest producing oil asset in the Rocky Mountains is Monument Butte, located in the Uinta Basin of Utah. Current gross production is approximately 15,700 BOPD and is expected to increase to about 16,500 BOPD in November. In 2009, we will continue with a 5-rig operated program. Demand for black wax remains strong with 100% of 2008 and 2009 volumes sold under term contracts with area refiners.
Success continues with our 20-acre spaced development program. To date, we have drilled 115 successful wells on 20-acre spacing. Results continue to indicate the potential to drill as many as 2,500 wells on 20-acre spacing. These locations are in addition to the more than 1,000 locations remaining to drill the field down to 40-acre spacing. Our total acreage in the Monument Butte field area includes about 162,000 gross acres, which includes 62,000 acres with Ute Energy and the Ute Tribe.
Newfield is drilling its 40th well on Tribal acreage today – 38 of the 39 wells drilled to date have been successful. Recent wells on the Ute acreage have performed above expectations and are consistent with main field producing intervals to the south. One rig will be dedicated to drilling wells on this acreage throughout 2009.
We are assessing the deep gas potential beneath Monument Butte. Prospective targets include the Wasatch, Mesa Verde, Blackhawk, Mancos and Dakota. The play concept covers 82,000 acres and is held by production through our shallow Green River oil production at Monument Butte.
We have drilled the first two of several deep Mancos Shale tests beneath Monument Butte under a Deep Gas Exploration Agreement that is underway with Red Technology Alliance (RTA). The initial well is being completed and the second well is drilling to 18,500’.
Approximately 10,700 net acres in the immediate vicinity of recent deep gas tests were excluded from the agreement. Completion of our first operated deep gas test (NFX working interest 75%) is underway and a second well (NFX working interest 100%) is drilling.
GREATER WILLISTON BASIN
Our current net production from the area is approximately 2,500 BOEPD, and our activity level in the greater Williston Basin is expected to increase in 2009. We plan to operate three rigs throughout 2009. Plans include continued development and expansion along the Nesson Anticline and our exploration areas west of the Nesson and in Montana.
We have 473,000 gross acres (160,000 net) in the Williston Basin. Our acreage position has prospective targets that include the Bakken Shale, as well as the Madison, Red River and Three Forks/Sanish. We completed additional horizontal wells in the Bakken formation and early production results are summarized below:
| Ø | Larsen 1-16H: 710 BOEPD (Disclosed September 2) |
| Ø | Jorgenson 1-10H: 911 BOEPD (Disclosed September 2) |
| Ø | Jorgenson 1-4H: 622 BOEPD |
| Ø | Rolfsrud 1-32H: 590 BOEPD |
The Jorgenson 1-15H, our first Sanish/Three Forks horizontal well, is an apparent success and the well awaits completion at this time. Flow rates are expected in early November. We expect to drill four additional operated wells near this well in 2008.
Continued development drilling in our Westberg prospect area is planned, where we have drilled three successful wells to date and identified 22 development locations from earlier successes and additional infill drilling locations. We also plan continued development drilling in our Lost Bear prospect area where we have drilled three successful wells to date and identified 5-10 development locations.
In 2009, we will assess our acreage position west of the Nesson and in Montana. Two wells are planned in our Big Valley area and four wells are planned in our large acreage positions in the Southern Alberta Basin and northeastern Williston Basin.
GULF COAST REGION
Newfield and partners recently announced a significant deepwater Gulf of Mexico discovery at the Dalmatian prospect, located at Desoto Canyon Block 48. The well found more than 120' measured depth of net high quality dry gas pay. The discovery is located in about 5,900’ of water.
The discovery will be developed via a subsea tie to existing infrastructure. Newfield has a 37.5% working interest. Partners include: Murphy Oil Corporation (operator) with a 50% working interest, and Mariner Energy with a 12.5% working interest.
In addition to Dalmation, we own working interests between 23% and 50% in nine contiguous blocks offsetting this discovery. We have five additional amplitude prospects in the area that we are evaluating for future exploration and development potential.
In addition to Dalmation, we have four additional deepwater developments:
Gladden: The MC 800#1 updip sidetrack tested approximately 5,600 BOEPD. We expect first production in late 2009 or early 2010. We operate and have a 47.5% working interest.
Anduin West: Located at Mississippi Canyon 754, the well tested 18 MMcf/d and 2,400 BCPD. We expect first production in late 2009.
Fastball: Located at VK 1003, this single well development will be a sub-sea tieback to existing infrastructure with first production expected in late 2009 or early 2010. We operate Fastball with a 66% working interest.
Glider: Operator Shell plans to spud the Glider #5 development well in Green Canyon Block 248 during the second quarter of 2009. This well will be drilled in proximity to the original Glider discovery well drilled in 1996. Plans call for production in late 2009. We have a 25% working interest in Glider.
SOUTH TEXAS
Newfield has an interest in nearly 500,000 acres in Texas.
Newfield is active under two separate joint ventures with ExxonMobil in South Texas that cover nearly 140,000 (gross) acres. Newfield’s interest in these ventures is approximately 50%. Production from the Sarita field area is approximately 67 MMcfe/d (gross). At Sarita, we have established pay in a new fault block with our SKE B-96 well, which logged nearly 200' of net pay.
We made a potential discovery with J. G. Kenedy #1 in Kenedy County, Texas. The well was drilled to 18,142' with casing and completion operations already begun. We are currently drilling below 17,000' on the Kenedy #2, which is being drilled on a separate structure on this 35,000 acre block, which lies just east of our prolific Sarita Field. We have a 50% working interest. The potential gross size of this prospect is 80 - 100 BCFE.
INTERNATIONAL
MALAYSIA
Current gross production in Malaysia is more than 35,000 BOPD. Although exploration expenditure will be curtailed in 2009, development of our oil fields will continue. In shallow water Malaysia, we have a 50% interest in PM 318 and a 60% operated interest in PM 323. We expect to spud the Paus-1 exploration well in the first quarter of 2009 in Deepwater Block 2C. We are the operator with a 40% working interest. Other partners include Petronas Carigali (40%) and Mitsubishi (20%).
CHINA
Current production from two fields on Blocks 04/36 and 05/36 is 18,000 BOPD gross or approximately 2,000 BOPD net to NFX. Newfield holds a 12% interest in the unit. The operator, Anadarko, is planning to drill 25-30 additional development wells in the complex and production is expected to further increase in 2009.
FOURTH QUARTER 2008 ESTIMATES
| | | Domestic | | | Int’l | | | Total | |
| Production/Liftings* | | | | | | | | | |
| Natural gas – Bcf | | | 42.0 – 44.2 | | | | – | | | | 42.0 – 44.2 | |
| Oil and condensate – MMBbl | | | 1.8 – 1.9 | | | | 1.4 – 1.5 | | | | 3.2 – 3.4 | |
| Total Bcfe | | | 52.8 – 54.6 | | | | 8.3 – 8.7 | | | | 61.1 – 63.3 | |
| | | | | | | | | | | | | |
| Average Realized Prices | | | | | | | | | | | | |
| Natural gas – $/Mcf | | Note 1 | | | | | | | | | |
| Oil and condensate – $/Bbl | | Note 2 | | | Note 3 | | | | | |
| Mcf equivalent – $/Mcfe | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | | | |
| Lease operating | | | | | | | | | | | | |
| Recurring ($MM) | | $ | 39.4 - $43.6 | | | $ | 13.3 - $14.7 | | | $ | 52.7 - $58.3 | |
| per/Mcfe | | $ | 0.75 - $0.80 | | | $ | 1.60 - $1.69 | | | $ | 0.86 - $0.92 | |
| Major (workover, repairs, etc.) ($MM) | | $ | 8.3 - $9.1 | | | $ | 0.7 - $0.8 | | | $ | 9.0 - $9.9 | |
| per/Mcfe | | $ | 0.16 - $0.17 | | | $ | 0.08 - $0.09 | | | $ | 0.14 - $0.16 | |
| | | | | | | | | | | | | |
Production and other taxes ($MM)Note 4 | | $ | 19.7 - $21.8 | | | $ | 15.8 - $17.5 | | | $ | 35.5 - $39.3 | |
| per/Mcfe | | $ | 0.37 - $0.40 | | | $ | 1.90 - $2.00 | | | $ | 0.58 - $0.62 | |
| | | | | | | | | | | | | |
| General and administrative (G&A), net ($MM) | | $ | 35.4 - $39.1 | | | $ | 1.5 - $1.7 | | | $ | 36.9 - $40.8 | |
| per/Mcfe | | $ | 0.67 - $0.72 | | | $ | 0.18 - $0.20 | | | $ | 0.60 - $0.64 | |
| | | | | | | | | | | | | |
| Capitalized G&A ($MM) | | | | | | | | | | $ | (17.2 - $19.1 | ) |
| per/Mcfe | | | | | | | | | | $ | (0.28 - $0.30 | ) |
| | | | | | | | | | | | | |
| Interest expense ($MM) | | | | | | | | | | $ | 32.0 - $36.0 | |
| per/Mcfe | | | | | | | | | | $ | 0.52 - $0.57 | |
| | | | | | | | | | | | | |
| Capitalized interest ($MM) | | | | | | | | | | $ | (15.0 - $17.0 | ) |
| per/Mcfe | | | | | | | | | | $ | (0.25 - $0.27 | ) |
| | | | | | | | | | | | | |
Tax rate (%)Note 5 | | | | | | | | | | | 37 - 40 | % |
| | | | | | | | | | | | | |
| Income taxes (%) | | | | | | | | | | | | |
| Current | | | | | | | | | | | 15 - 20 | % |
| Deferred | | | | | | | | | | | 80 - 85 | % |
| | | | | | | | | | | | | |
*Reflects approximately 3 Bcfe of deferred domestic gas production related to GOM storms. Note 1: 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 2: Oil prices in the Gulf Coast typically equal the NYMEX WTI price. Rockies oil prices average about $15 per barrel below WTI. Oil production from the Mid-Continent typically averages 96 – 98% of WTI. Note 3: Oil in Malaysia typically sells at a slight discount to Tapis, or about 90% of WTI. Oil production from China typically sells at $10 - $15 per barrel below WTI. Note 4: Guidance for production taxes determined using $70/Bbl oil and $7/MMBtu gas. Note 5: Tax rate applied to earnings excluding unrealized gains or losses on commodity derivatives. | |
NATURAL GAS HEDGE POSITIONS
Please see the tables below for our complete hedging positions.
The following hedge positions for the fourth quarter of 2008 and beyond are as of October 20, 2008:
Fourth Quarter 2008
| | | 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
| | | 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 | |
| 16,505 MMMBtus | | $ | 8.33 | | | | — | | | | — | | | | — | | | | — | |
| 13,485 MMMBtus | | | — | | | | — | | | $ | 8.00 — $11.83 | | | $ | 8.00 | | | $ | 8.97 — $14.37 | |
Third Quarter 2009
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 16,660 MMMBtus | | $ | 8.33 | | | | — | | | | — | | | | — | | | | — | |
| 13,620 MMMBtus | | | — | | | | — | | | $ | 8.00 — $11.83 | | | $ | 8.00 | | | $ | 8.97 — $14.37 | |
Fourth Quarter 2009
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 9,265 MMMBtus | | $ | 8.42 | | | | — | | | | — | | | | — | | | | — | |
| 8,435 MMMBtus | | | — | | | | — | | | $ | 8.23 — $11.20 | | | $ | 8.00 — $8.50 | | | $ | 8.97 — $14.37 | |
First Quarter 2010
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 5,400 MMMBtus | | $ | 8.55 | | | | — | | | | — | | | | — | | | | — | |
| 5,700 MMMBtus | | | — | | | | — | | | $ | 8.50 — $10.44 | | | $ | 8.50 | | | $ | 10.00 — $11.00 | |
Second Quarter 2010
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 1,820 MMMBtus | | $ | 8.01 | | | | — | | | | — | | | | — | | | | — | |
Third Quarter 2010
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 1,840 MMMBtus | | $ | 8.01 | | | | — | | | | — | | | | — | | | | — | |
Fourth Quarter 2010
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 620 MMMBtus | | $ | 8.01 | | | | — | | | | — | | | | — | | | | — | |
*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 | | | | | | | | | | | | | | | | | | | | |
| Total 2008 | | $ | 92 | | | $ | 65 | | | $ | 37 | | | $ | 6 | | | $ | (10 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| 2009 | | | | | | | | | | | | | | | | | | | | |
| 1st Quarter | | $ | 83 | | | $ | 60 | | | $ | 38 | | | $ | 9 | | | | — | |
| 2nd Quarter | | $ | 92 | | | $ | 63 | | | $ | 34 | | | $ | 5 | | | $ | (12 | ) |
| 3rd Quarter | | $ | 92 | | | $ | 63 | | | $ | 33 | | | $ | 4 | | | $ | (12 | ) |
| 4th Quarter | | $ | 34 | | | $ | 23 | | | $ | 13 | | | $ | 2 | | | $ | (5 | ) |
| Total 2009 | | $ | 301 | | | $ | 209 | | | $ | 118 | | | $ | 20 | | | $ | (29 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| 2010 | | | | | | | | | | | | | | | | | | | | |
| Total 2010 | | $ | 52 | | | $ | 37 | | | $ | 21 | | | $ | 6 | | | $ | (7 | ) |
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 fourth quarter of 2008 and beyond are as of October 20, 2008:
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 | | $ | 128.93 | | | | — | | | | — | | | | — | | | | — | |
| 810,000 Bbls | | | — | | | $ | 107.11 | | | | — | | | $ | 104.50 — $109.75 | | | | — | |
Second Quarter 2009
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 819,000 Bbls | | $ | 128.93 | | | | — | | | | — | | | | — | | | | — | |
| 819,000 Bbls | | | — | | | $ | 107.11 | | | | — | | | $ | 104.50 — $109.75 | | | | — | |
Third Quarter 2009
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 828,000 Bbls | | $ | 128.93 | | | | — | | | | — | | | | — | | | | — | |
| 828,000 Bbls | | | — | | | $ | 107.11 | | | | — | | | $ | 104.50 — $109.75 | | | | — | |
Fourth Quarter 2009
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 828,000 Bbls | | $ | 128.93 | | | | — | | | | — | | | | — | | | | — | |
| 828,000 Bbls | | | — | | | $ | 107.11 | | | | — | | | $ | 104.50 — $109.75 | | | | — | |
First Quarter 2010
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 90,000 Bbls | | $ | 93.40 | | | | — | | | | — | | | | — | | | | — | |
| 810,000 Bbls | | | — | | | | — | | | $ | 127.97— $170.00 | | | $ | 125.50 — $130.50 | | | $ | 170.00 | |
Second Quarter 2010
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 90,000 Bbls | | $ | 93.40 | | | | — | | | | — | | | | — | | | | — | |
| 819,000 Bbls | | | — | | | | — | | | $ | 127.97— $170.00 | | | $ | 125.50 — $130.50 | | | $ | 170.00 | |
Third Quarter 2010
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 90,000 Bbls | | $ | 93.40 | | | | — | | | | — | | | | — | | | | — | |
| 828,000 Bbls | | | — | | | | — | | | $ | 127.97— $170.00 | | | $ | 125.50 — $130.50 | | | $ | 170.00 | |
Fourth Quarter 2010
| | | Weighted Average | | | Range | |
| Volume | | Fixed | | | Floors | | | Collars | | | Floor | | | Ceiling | |
| 90,000 Bbls | | $ | 93.40 | | | | — | | | | — | | | | — | | | | — | |
| 828,000 Bbls | | | — | | | | — | | | $ | 127.97— $170.00 | | | $ | 125.50 — $130.50 | | | $ | 170.00 | |
**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 $26.56 per barrel. Below $26.56 per barrel, these contracts effectively result in realized prices that are on average $6.44 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 | | | | | | | | | | | | | | | | | | | | | |
| Total 2008 | | $ | 0 | | | $ | (8 | ) | | $ | (17 | ) | | $ | (25 | ) | | $ | (33 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| 2009 | | | | | | | | | | | | | | | | | | | | | |
| 1st Quarter | | $ | 104 | | | $ | 88 | | | $ | 72 | | | $ | 55 | | | | 39 | |
| 2nd Quarter | | $ | 105 | | | $ | 89 | | | $ | 72 | | | $ | 56 | | | $ | 40 | |
| 3rd Quarter | | $ | 106 | | | $ | 90 | | | $ | 73 | | | $ | 57 | | | $ | 40 | |
| 4th Quarter | | $ | 140 | | | $ | 129 | | | $ | 118 | | | $ | 107 | | | $ | 90 | |
| Total 2009 | | $ | 455 | | | $ | 396 | | | $ | 335 | | | $ | 275 | | | $ | 209 | |
| | | | | | | | | | | | | | | | | | | | | | |
| 2010 | | | | | | | | | | | | | | | | | | | | | |
| Total 2010 | | $ | 241 | | | $ | 205 | | | $ | 168 | | | $ | 132 | | | $ | 95 | |
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 Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains, onshore Texas and the Gulf of Mexico. The Company has international operations in Malaysia and China.
**This publication contains forward-looking information. All information other than historical facts included in this publication, such as information regarding estimated or anticipated fourth quarter 2008 results, estimated full-year 2008 and 2009 production, drilling and development plans, estimated 2009 capital expenditures, cash flow and production growth, the timing of activities, the timing of initial production and future rates of production from wells, fields and regions, expected cost reductions and the expected ultimate recovery of reserves from wells, 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 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.
