Overview
Oil and gas well equipment and operating costs were higher in 2006. Gas equipment costs increased by about 10 percent while gas operating costs increased 13 percent. The 10 percent increase in gas equipment costs was partly caused by an increase in the cost of steel items such as safety valves, chokes, separators, and dehydrators. The 13 percent increase in gas operating costs was partly caused by an increase in the cost of chemicals and labor.

Oil equipment costs were up over 4 percent, while oil operating costs increased about 3 percent. The 3 percent increase in oil operating costs for 2006 is partly attributable to the large increase in the cost of well servicing rigs. Oil equipment costs were affected by an increase in the cost for steel. This increased the cost for tubulars and most surface equipment.

Offshore operating costs increased by 33 percent. The increase in the operating cost index for 2006 was primarily caused by an increase in the costs for transportation and offshore rigs.

These changes are graphically shown in Figures 1, 2, and 3, described in the Summary section.

Background
This report, with the accompanying Excel spreadsheet, presents estimated costs for domestic oil and natural gas field equipment and production operations for 1988 through 2006. Beginning with 2002 , coal bed natural gas costs were added. At the end of 2005, coal bed natural gas accounted for about 9 percent of U.S. dry gas production and 10 percent of the dry natural gas reserves. The importance of coal bed natural gas is expected to continue.

The costs of all equipment and services are those in effect during June of each year. The aggregate costs for typical leases by region, depth, and production rate were averaged. These averages provide a general measure of the change in costs from year to year for lease equipment and operations. The accompanying spreadsheets contain summary tables and detailed tables for equipment and services by region for the period 1988 through 2006.

Summary
Figures 1 and 2 indicate deflated oil and gas prices, equipment costs, and operating costs indexed to the base year of 1976 for natural gas and oil in the contiguous lower 48 states excluding offshore Gulf of Mexico. Figure 3 shows separately the deflated operating costs and gas price indexed to 1976 for the offshore Gulf of Mexico wells.

Figure 1 shows that the deflated prices of both natural gas equipment and operations have changed less over time than has the deflated price of natural gas. Deflated gas equipment costs and operating costs are slightly more than for the base year of 1976. The deflated gas price index dropped below the record of 460.6 set in 2005. Actual gas prices averaged $4.98 per MCF in 2003, $5.49 per MCF in 2004, $7.51 per MCF for 2005, and $6.42 per MCF for 2006. By comparison, the average gas price in 1976 was $0.58 per MCF.

Similarly, Figure 2 depicts deflated oil prices, and equipment and operating costs for oil production indexed to 1976.

First purchaser oil prices averaged $27.56 for 2003, $36.77 for 2004, $50.28 for 2005, and $60.78 for 2006. The high price for the year was in August when WTI oil prices were in the $75.00 per bbl range.

The 3 percent increase in oil operating costs for 2006 is partly attributable to the large increase in the cost of well servicing rigs.

Oil equipment costs were up by over 4 percent. This increase was primarily caused by an increase in the price of steel which increased the price for tubulars and most surface equipment.

Figure 3 shows the deflated oil and gas operating costs for offshore Gulf of Mexico wells. Gas prices for Louisiana were used to represent offshore indexed gas prices. The increase in the operating cost index that occurred in 1997 was primarily caused by a major increase in the cost for transport boats. The increase in the operating cost index for 2006 was primarily caused by an increase in costs for transportation and offshore rigs. Part of this increase may be due to major storms in 2005.

Methodology
The costs provided in this report are for representative lease operations with equipment and operating procedures designed by EIA staff engineers. Costs are estimated for representative 10-well oil leases producing by artificial lift; 1 flowing gas well per gas lease; or 10-well coal bed natural gas leases dewatering by artificial lift. While coal bed natural gas leases will typically have hundreds of wells, we have chosen to use a 10-well lease for the purpose of this study. The design criteria took into account the predominant methods of operation in each region. Individual items of equipment were priced by using price lists and by communicating with the manufacturers or suppliers of the item in each region. The leading supply, service, and contracting companies (active in one or more of the regions) were contacted every year (1976 through 2006) for local June prices for their component of equipment or operating function. The objective of this process is to acquire prices that are representative for each region. The annual operating costs measure the change in direct costs incident to the production of oil and gas and exclude changes in indirect costs such as depreciation and ad valorem and severance taxes.

Costs were determined for new equipment. Tubing costs are included for the oil wells but not for the gas wells. Care must be exercised when combining these equipment costs with drilling costs to obtain total lease development and equipment costs because most drilling and completion cost estimates also include tubing costs. Drilling and completion costs are not included in this study.

Primary Oil Production
Leases for onshore oil wells consist of 10 wells producing by artificial lift into a centrally located tank battery. The depths of all wells on each of the leases are 2,000, 4,000, 8,000, or 12,000 feet.

Costs were determined for new equipment capable of handling 200 barrels of liquid per day per well for onshore primary operations. Tubing costs are included. Care must be exercised when combining these equipment costs with drilling costs to obtain total lease development and equipment costs because most drilling and completion cost estimates also include tubing costs. Drilling and completion costs for the primary production wells are not included in this study. The artificial lift method selected was dependent on the type of lift found to be dominant for each depth in each region. The two types of prime movers considered were electric motors and natural gas engines. Annual operating costs were estimated for daily production rates of 100 barrels of liquid per day per well for each depth in each region of operation with 10 percent water content.

Secondary Oil Production
Costs for secondary oil production in West Texas were calculated for wells producing from depths of 2,000, 4,000, and 8,000 feet. Each lease was assumed to have 10 producing wells, 11 injection wells and 1 water supply well. Costs for water storage tanks, injection plant, filtering systems, injection lines and drilling water supply wells and water injection wells are included. Equipment was designed to handle 350 barrels of liquid per day per producing well. Gas engines used in primary operations were replaced by electric motors for secondary oil production. Some equipment for primary oil production was replaced with larger equipment to accommodate the increased liquid volumes assumed for secondary oil production. Operational costs for secondary oil production are indicated for the increased liquid lift of 250 barrels of liquid per day per producing well (90 barrels of oil per day) and for the water injection system.

Offshore Gas and Primary Oil Production
Operating costs for the offshore Gulf of Mexico were estimated for 12- and 18-well fixed structure platforms. Maximum crude oil production was assumed to total 11,000 barrels of oil per day from each platform. Maximum associated gas production was assumed to be 40 million cubic feet of gas per day per platform. Note that the balance between gas and oil is more heavily weighted toward gas in offshore operations than in onshore leases. Operating costs were derived for platforms assumed to be 50, 100, and 125 miles from shore corresponding to water depths of 100, 300, and 600 feet, respectively. Meals, platform maintenance, helicopter and boat transportation of personnel and supplies, communication costs, insurance costs for platform and production equipment, and administrative expenses are included in normal production expenses. Crude oil and natural gas transportation costs to shore were excluded, as were water disposal costs.

Gas Production
Leases for gas wells were assumed to consist of one well producing into an onsite separator with two storage tanks (a lease condensate sales tank and a water storage tank). Line heaters, dehydration units, and methanol injectors were included where needed. It was assumed that any compression or gas treatment would be furnished by the first purchaser or transporter. The cost data presented were based on the installation of new equipment and included items needed from the wellhead to the outlet on the meter run for the gas stream and through the tank for liquid streams. Tubing costs were not included, nor were costs of equipment for disposal of produced water above nominal amounts of water entrained in the gas stream. Gas production rates of 50, 250, 500, 1,000, 5,000 and 10,000 MCF/D and well depths of 2,000, 4,000, 8,000, 12,000 and 16,000 feet were the assumed volume and depth divisions for the cost determinations. These volumes were selected because of different processing requirements for each of these flow rates. Production records were used to determine the average production rate for each depth in each region. The equipment and operating costs for each of these average production rates were then calculated. For a broader view of each flow rate in each region at each depth, the equipment and operating costs of the next higher and/or lower rates are shown. Costs were calculated for equipping gas wells at producing rates of 50 MCF/D even though a new well coming onstream at this rate may not be economic. This low rate was selected to identify costs of production from stripper gas wells. Flow rates above 10,000 MCF/D usually require custom design of equipment and are not priced in this report.

The depths of 2,000, 4,000, 8,000, and 12,000 feet were chosen to be compatible with data provided for oil production. An additional depth of 16,000 feet was added for gas equipment and operations because there is significant gas production from this depth in some regions studied.

Coal Bed Natural Gas Production
Leases for coal bed natural gas were assumed to consist of 10 wells dewatering by the predominant artificial lift method employed in that area. The production depths and rates were chosen as representative for that area. The areas studied are Appalachia, Black Warrior Basin (Alabama), Powder River Basin (Wyoming), and San Juan Basin (New Mexico). Additional areas may be added in future reports. The following table lists the average production depth, per well production rates, and dewatering method used in the study.

		Dewatering Method	Per Well
AREA	Depth		Gas MCF/D	Water BWPD
Appalachia	2,000'	sucker rod	60	3
Black Warrior	2,000'	sucker rod	100	20
Powder River	1,000'	submersible	100	50
San Juan	3,000'	sucker rod	500	100

Revisions
Data used in this work are revised for at least one year. Late arrival of data necessitates using estimates in some cases, and in other cases, small items have been combined to reduce reporting burdens on data suppliers. The cost data comes from leading supply, service, and contracting companies in a region. If one of these companies should not be able to respond a replacement company is identified. The replacement company prices may vary slightly from the original company's prices. In order to collate the necessary data, the costs to drill the water disposal wells, water supply wells and secondary recovery water injection wells are estimated since the source for the drilling costs (the Joint Association Survey on Drilling Costs) is two years behind. In general, since 1976, data gathering has become more challenging, in part due to the restructuring of the industry, and in part due to normal changes in product lists. Changes in equipment and operating practices are adopted where they become common usage in an area. In this manner, improvements in productivity and technology are recognized, although gradually.

Results

Oil Leases
Tables 1 and 2 contain the 2006 equipment costs and operating costs for a 10-well oil lease for the six regions, the Lower 48 states and the additional costs for secondary recovery in West Texas. Costs for the offshore Gulf of Mexico wells are not included in the aggregated totals used for tables 1 and 2.

Table 1. Equipment Costs for 10-well Oil Lease in 2006 (Current US Dollars)

	Producing Depth, feet
Region	2,000	4,000	8,000	12,000
California	1,731,400	2,073,600	2,686,900	3,243,100
Mid-Continent	918,700	1,465,300	2,423,400	2,924,500
South Louisiana	1,116,600	1,545,100	2,013,300	3,288,300
South Texas	1,029,200	1,461,800	1,867,900	3,220,300
West Texas	938,700	1,438,800	2,348,700	2,950,200
Rocky Mountains	1,044,800	1,500,100	2,330,700	2,950,900
Lower 48 states excluding offshore	1,148,600	1,580,800	2,278,500	3,096,200
Additional cost for Secondary Recovery in West Texas	4,397,700	8,799,000	17,937,400	NA

Table 2. Annual Operating Costs for 10-well Oil Lease in 2006 (Current US Dollars)

	Producing Depth, feet
Region	2,000	4,000	8,000	12,000
California	225,200	301,1000	507,600	758,400
Mid-Continent	204,500	243,800	430,200	529,000
South Louisiana	244,100	350,900	419,700	626,900
South Texas	259,900	332,700	416,300	649,300
West Texas	186,400	223,5000	326,200	497,100
Rocky Mountains	232,500	259,400	351,900	454,600
Lower 48 states excluding offshore	225,400	285,200	408,700	585,900
Additional cost for Secondary Recovery in West Texas	434,900	593,700	827,900	NA

Gas Leases
Tables 3 and 4 contain equipping and operating costs for onshore gas wells displayed by depth, region, and per well producing rate. Since the rate-depth combinations are chosen for each region to reflect the majority of the wells in that region, the tables contain blanks, which represent rate-depth combinations which were not found in significant numbers in the base year of 1976. The averages for the Lower 48 states show that the equipping costs generally increase with depth at each of the producing rates.

Table 3. Equipment Costs for 1-well Gas Lease in 2006 (Current US Dollars)

	Producing Depth, feet
Region	2,000	4,000	8,000	12,000	16,000
Producing 50 MCF/D
Mid-Continent	31,200	31,200
North Louisiana	30,700
South Louisiana	30,700	30,700
Rocky Mountains	33,300	33,300
South Texas	30,300	30,300
West Texas	27,100	27,100	39,800
Lower 48 states excluding offshore	30,600	30,500	39,800
Producing 250 MCF/D
Mid-Continent	33,500	44,200	70,500	91,200
North Louisiana	30,700	44,500	69,500
South Louisiana	30,700	44,300	70,300
Rocky Mountains	33,400	67,600	77,600	95,900
South Texas	30,300	44,000	70,000
West Texas	27,100	40,500	65,500	85,700
Lower 48 states excluding offshore	31,000	47,500	70,600	90,900
	Producing Depth, feet
Region	2,000	4,000	8,000	12,000	16,000
Producing 500 MCF/D
Mid-Continent		41,800	68,900	88,800	97,700
North Louisiana		43,400	68,100	88,000
South Louisiana			68,100	88,000	88,000
Rocky Mountains		74,100	75,300	93,500
South Texas			67,800	87,700
West Texas			63,800	83,700	95,300
Lower 48 states excluding offshore		53,100	68,700	88,300	93,700
Producing 1 MMCF/D
Mid-Continent				97,700	97,700
North Louisiana				96,900	96,900
South Louisiana			96,900	96,900	96,900
Rocky Mountains				93,500
South Texas			96,600	96,600
West Texas				95,400	95,300
Lower 48 states excluding offshore			96,800	96,200	96,700
Producing 5 MMCF/D
Mid-Continent					115,300
North Louisiana					114,400
South Louisiana				114,400	114,400
South Texas				114,200
West Texas					112,500
Lower 48 states excluding offshore				114,300	114,200
Producing 10 MMCF/D
North Louisiana					144,700

Table 4. Annual Operating Costs for 1-well Gas Lease in 2006 (Current US Dollars)

	Producing Depth, feet
Region	2,000	4,000	8,000	12,000	16,000
Producing 50 MCF/D
Mid-Continent	15,600	18,500
North Louisiana	15,100
South Louisiana	15,100	18,100
Rocky Mountains	17,800	21,100
South Texas	16,600	19,200
West Texas	12,900	16,100	20,900
Lower 48 states excluding offshore	15,500	18,600	20,900
	Producing Depth, feet
Region	2,000	4,000	8,000	12,000	16,000
Producing 250 MCF/D
Mid-Continent	21,800	30,400	49,100	60,700
North Louisiana	19,000	27,700	48,700
South Louisiana	19,000	27,600	48,000
Rocky Mountains	21,700	36,700	51,900	64,100
South Texas	20,500	28,100	47,700
West Texas	16,800	24,600	42,300	52,600
Lower 48 states excluding offshore	19,800	29,200	48,000	59,100
Producing 500 MCF/D
Mid-Continent		27,100	36,500	44,400	48,600
North Louisiana		25,700	36,300	42,000
South Louisiana			37,200	43,300	47,900
Rocky Mountains		35,100	40,100	48,700
South Texas			34,900	43,700
West Texas			28,400	34,900	43,600
Lower 48 states excluding offshore		29,300	35,600	42,800	46,700
Producing 1 MMCF/D
Mid-Continent				59,100	63,400
North Louisiana				56,000	64,200
South Louisiana			48,500	58,000	63,600
Rocky Mountains				62,500
South Texas			56,200	52,300
West Texas				47,200	55,600
Lower 48 states excluding offshore			52,400	55,900	61,700
Producing 5 MMCF/D
Mid-Continent					63,900
North Louisiana					67,600
South Louisiana				51,300	66,500
South Texas				54,600
West Texas					61,100
Lower 48 states excluding offshore				53,000	64,800
Producing 10 MCF/D
North Louisiana					88,100

Offshore
Table 5 provides operating costs for offshore wells displayed by platform size and water depth.

Table 5. Annual Operating Costs for Gulf of Mexico wells in 2006 (Current US Dollars)

	Water Depth, feet
Platform Size	100-ft	300-ft	600-ft
12 Slot	9,337,100	9,624,300
18 Slot	11,179,300	11,523,900	12,148,800
GOM Average	10,258,200	10,574,100	12,148,800

Coal Bed Natural Gas Leases
Table 6 and 7 provide the 2006 lease equipment costs and operating costs for a 10-well Coal Bed Natural Gas lease.

Table 6. Equipment Costs for 10-well Coal Bed Natural Gas lease in 2006 (Current US Dollars)

	Producing Depth, feet
Area	1,000	2,000	3,000
Appalachia		926,300
Black Warrior		621,500
Powder River	501,500
San Juan			1,319,200

Table 7. Annual Operating Costs for 10-well Coal Bed Natural Gas lease in 2006 (Current US Dollars)

	Producing Depth, feet
Area	1,000	2,000	3,000
Appalachia		108,200
Black Warrior		127,800
Powder River	174,600
San Juan			187,700

Water handling costs are a major factor in coal bed natural gas operating costs and partially account for the difference in operating costs.

Items Tracked
Table 8 indicates the more significant cost items tracked from year to year, beginning in most cases with the year 1976. Freight and taxes are also a part of the equipment cost, as is the labor to install the equipment. Maintenance costs include replacement costs of some of the more common wear items.

Table 8. Items tracked for Oil, Gas, or Coal Bed Natural Gas Lease Equipment and Operating Costs
Automobile Costs	Oil transfer pumps
Communications costs - land	Oilfield chemicals
Communications costs - offshore	Oilfield maintenance - land
Electric lease power	Oilfield maintenance - marine
Electric motors and controllers	Packers
Electric labor - field	Perforating
Electric materials - field	Pipe coating
Fences	Plastic tanks
Field structures - small	Pumping engines- gas
Fishing tools	Pumping motors - electric
Miscellaneous fittings	Pumping unit bases
Gas compressors	Pumping units
Gas lift equipment	Slick line work - offshore
Gas sales meters	Speciality tubing
Gross national product deflator	Submersible pumps
Helicopter service	Submersible hydraulic pumps
Hot oil service	Sucker rods
Insulation	Tubular goods - lease
Insurance - offshore	Tublar goods - well
Labor statistics - oil field	Tugs and barges
Labor - clerical	Valves, pumps, misc. - land
Labor - supervisory	Water filter cases
Labor - technical	Water filters
Large engine for hydraulic pumping	Water injection pumps
Lease processing and storage equipment	Well costs - secondary recovery
Lubricants	Well servicing - land
Marine food services	Well servicing - offshore
Natural gas prices	Wellheads
Oil sales meters	Work boats