Released: September 28, 2010 Next Release: Discontinued

Excel Spreadsheet Model - 1994-2009 XLS (1,178 KB) Overview Oil and gas well equipment and operating costs, including coal bed methane costs, stopped their upward trend from the 1990s and fell sharply in 2009.  The extremely high oil and gas prices during the first half of 2008 followed by an unprecedented drop to very low prices by the end of the year had a major impact on equipment demand. Operating costs tumbled also because fuel costs were reduced and well servicing rates fell in most areas.  The exceptions were in California where electric rates continued to increase, causing a one (1) percent increase in annual operating costs for leases producing from 12,000 feet.  Operating cost for coal bed methane wells in the Appalachian and Powder River areas increased because electric rates continued to climb.  Due to the timing of the data collection, the cost reported here could be higher than the actual annual average for 2008.  However, some production costs (labor and equipment) are not as volatile as drilling, pipe, and other well completion costs, so the effect of the oil and gas prices on collected data may be lessened.  Annual average electric rates and natural gas prices are used, which also helps to dampen cost variances.  Gas lease equipment costs increased 8 percent in 2008 and decreased 4 percent in 2009.  Gas lease operating costs increased 6 percent in 2008 followed by a 5 percent decrease in 2009.  The increase in gas equipment costs was from the increases in the cost of steel items such as safety valves, chokes, separators, and dehydrators.   Oil lease equipment costs were up 17 percent in 2008 and dropped 11 percent in 2009.  If tubing costs are excluded, costs increased 11 percent and decreased 3 percent, respectively.  The oil lease operating costs rose 6 percent for 2008 and fell 12 percent for 2009.  Oil production equipment costs were affected by steel prices which raised the cost for tubulars by 30-40 percent in 2008 and then dropped by as much or more in 2009.  Offshore operating costs decreased by 4 percent in 2009 following the 7 percent increase in 2008.  Workover costs increased 20 percent in 2008 and decreased more than 26 percent in 2009.  Coal bed methane operating costs increased 7 percent in 2008, followed by decrease of 1 percent in 2009.  Coal bed methane equipment costs were up 16 percent in 2008 but declined 10 percent in 2009.  If tubing costs are excluded, equipment costs increased 13 percent for 2008 and declined 6 percent in 2009.  Coal bed methane data is summarized in Tables 23-25 of the accompanying Excel workbook.  More detailed data can be seen in Tables N through Q in the workbook.  Oil and gas operating and equipping cost changes are graphically shown in Figures 1, 2, and 3, and described in the Summary section below and in Summary Tables 1-22 in the workbook.  More detailed data can be found in Tables A through M of the accompanying Excel workbook.  Background This report, with the accompanying Excel workbook, presents indexes and estimated costs for domestic oil and natural gas equipment and production operations for 2006 through 2009.  Indexes only are provided for previous years.  Coal bed methane indexes, added in 2002, are also available.  The costs of all equipment and services do not always represent an annual average because of the timing of the data collection and industry cycles. Although mid-year costs are requested, they are not always available.  Care should also be used when comparing costs in rapidly decreasing or increasing demand markets (extreme oil and gas price volatility) because the reported costs may be higher or lower than the actual annual average.  Differences between the reported costs and actual annual average costs are likely to be dampened somewhat because some components, such as equipment and labor costs, are not as volatile as drilling rig costs, for example, because there are alternatives such as used equipment or scavenging equipment from marginal wells.  Annual electric rates and natural gas prices are used, which also helps to dampen cost volatility.  Summary Figures 1 and 2 show real (1976 dollar) oil and gas prices, and real equipment costs and operating costs indexed to the base year of 1976 for natural gas and oil in the contiguous lower 48 states excluding the Federal offshore Gulf of Mexico.  Figure 3 shows separately the real operating cost indexed to 1976 and the real gas price for the offshore Gulf of Mexico platforms.  (Real 1976 dollars were calculated using GDP Implicit Price Deflators from Global Insight.)  Figure 1 shows that the real costs of both natural gas equipment and operations have changed less over time than has the real price of natural gas.  Real gas equipment costs are 12 percent higher and operating costs are 37 percent higher than for the base year of 1976.  The gas price in real 1976 dollars dropped below the record of $2.67 per thousand cubic feet (Mcf) set in 2005 and now rests at $1.20 per Mcf (a 107 percent increase since 1976).  In nominal dollars, natural gas prices averaged $6.42 per Mcf in 2006, $6.39 per Mcf in 2007, $8.07 per Mcf for 2008, and only $3.71 per Mcf for 2009.  By comparison, the average gas price in nominal dollars in 1976 was $0.58 per Mcf.  Similarly, Figure 2 depicts oil prices in real 1976 dollars, and real equipment and operating costs for oil production indexed to 1976.  First purchaser oil prices averaged $59.60 for 2006, $66.52 for 2007, $94.02 for 2008, and $51.50 for 2009 in current dollars.  In real dollars, the 77 percent increase in oil operating costs from 1976 to 2008 and the 22 percent increase in equipping cost (in real 1976 dollars) are dwarfed by the 274 percent increase in the oil price from 1976 to 2008.  The differences are only slightly less dramatic after the 46 percent drop in oil prices in 2009.  The 1976 to 2009 change in the real dollar price of oil was 103 percent compared to an equipping cost change of 7 percent (in real 1976 dollars), and an operating cost change of 54 percent.  Figure 3 shows the real oil and gas operating cost indexed to 1976 for Federal offshore Gulf of Mexico platforms.  Gas prices for Louisiana in real 1976 dollars were used to represent offshore gas prices.  The real gas price changes from 1976 were 391 percent higher in 2008 but fell 54 percent and were only 126 percent higher in 2009.  The increase in the real operating cost index that began in 1976 and peaked in 2008 at 219 was primarily caused by a huge increase in the cost for transportation (helicopters and boats) and offshore rigs.  The real operating cost index for 2009 went down 5 percent as a result of decreases in costs for transportation and offshore rigs and was only 109 percent higher from 1976 to 2009.  Results Oil Leases Tables 1 and 2 contain the 2009 equipment costs and operating costs for a 10-well oil lease for the six regions and the additional costs for secondary recovery in West Texas. Costs for the Federal offshore Gulf of Mexico wells are not included in Tables 1 and 2.

Table 1. Equipment Costs for 10-well Oil Lease in 2009 (Current US Dollars)

Table 2. Annual Operating Costs for 10-well Oil Lease in 2009 (Current US Dollars)

Gas Leases
Tables 3 and 4 contain equipping and operating costs for onshore gas wells displayed by depth, region, and per well producing rate.  The tables contain blanks because the rate-depth combinations are chosen for each region to reflect the majority of the wells in that region.  Not all rate-depth combinations are found in significant numbers.  The averages show that the equipping costs generally increase with depth at each of the producing rates.  Costs for the Federal offshore Gulf of Mexico platforms are not included in Tables 3 and 4. 

Table 3. Equipment Costs for 1 well Gas Lease in 2009 (Current US Dollars)

Table 4. Annual Operating Costs for 1 well Gas Lease in 2009 (Current US Dollars)

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 2009 (Current US Dollars)

Coal Bed Methane Leases At the end of 2009, coal bed methane remained at the 2008 level of about 9 percent of U.S. dry gas production. Coal bed methane reserves declined 5 percent in 2009 and are now at 8.5 percent of the total dry natural gas reserves. The importance of coal bed methane is expected to continue. Table 6 and 7 provide the 2009 lease equipment costs and operating costs for a 10-well coal bed methane lease. Water handling costs are a major factor in coal bed methane operating costs and partially account for the difference in operating costs.

Table 6. Equipment Costs for 10-well Coal Bed Methane lease in 2009 (Current US Dollars)

Table 7. Annual Operating Costs for 10-well Coal Bed Methane lease in 2009 (Current US Dollars)

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 methane leases dewatering by artificial lift.  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 items in each region.  The leading supply, service, and contracting companies (active in one or more of the regions) were contacted every year (1976 through 2009) 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 for producing wells, but are included for secondary recovery injection wells. 

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 are 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 on stream 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 Methane Production
The Environmental Protection Agency conducted a survey of coal bed methane producers in the U.S.A.  Their resulting comprehensive report <>Technical Support Document for the 2006 Effluent Guidelines Program Plan, December 2006 EPA-821R-06-018, provided information on coal bed methane production and lease maintenance procedures (specifically for water disposal).  This report was adopted as the guiding reference for the 2009 cost study and all previous estimates were revised to reflect this change. 

Leases for coal bed methane were assumed to consist of 10 wells dewatered 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).  The following table lists the average production depth, per well production rates, and dewatering method used in the study. 

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 when they become common usage in an area.  In this manner, improvements in productivity and technology are recognized, although gradually. 

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. 

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