Tier II Issue: Enhanced Oil Recovery Credit Directive #2
LMSB Control No. LMSB-04-0409-014
Impacted IRM: 4.51.2
May 14, 2009
MEMORANDUM FOR INDUSTRY DIRECTORS, LMSB
DIRECTOR, FIELD SPECIALISTS, LMSB
DIRECTOR, INTERNATIONAL COMPLIANCE, STRATEGY AND POLICY
DIRECTOR, PRE-FILING AND TECHNICAL GUIDANCE, LMSB
DIRECTORS, FIELD OPERATIONS, NATURAL RESOURCES AND CONSTRUCTION
FROM: Keith M. Jones /s/ Keith M. Jones
Director, Natural Resources and Construction
SUBJECT: Industry Directors’ Directive #2 on Enhanced Oil Recovery Credit
On May 2, 2007, the Industry Director for Natural Resources and Construction issued an Industry Director’s Directive to provide field direction on Tier II Issue – Enhanced Oil Recovery (EOR) Credit (IDD #1). This directive (IDD #2) supplements IDD #1 by providing additional direction to the field in order to effectively utilize resources in the examination of a taxpayer who is claiming the EOR Credit.
IDD #2 is a result of LMSB’s experience examining the EOR Credit since the issuance of IDD #1. The additional guidance is provided in the form of Questions and Answers. See Attachment, Questions and Answers Regarding the Enhanced Oil Recovery Tax Credit.
Questions regarding either IDD or the EOR credit should be addressed to one of the Petroleum Technical Advisors.
This Directive is not an official pronouncement of law and cannot be used, cited, or relied upon as such.
cc: Commissioner, LMSB
Deputy Commissioner, Operations
Deputy Commissioner, International
Division Counsel, LSMB
Director, Performance, Quality and Audit Assistance
Questions and Answers Regarding the Enhanced Oil Recovery Tax Credit
Question: What is the qualified tertiary injectant expense for “self produced” fuel that is used by the taxpayer to create or facilitate the use of a tertiary injectant?
Scenario 1: In many enhanced oil recovery (EOR) projects natural gas is produced in association with crude oil. Operators routinely use this natural gas within the confines of the project as a source of fuel to create steam (for injection as a tertiary injectant) or to power equipment such as injection pumps and recycling compressors. The cost of fuel for such activities is a qualified tertiary injectant expense within the meaning of IRC §43(c)(1)(C). See Rev. Rul. 2003-82, 2003-2 C.B. 125. What is the qualified cost of the fuel in this scenario?
Answer: The qualified cost of the self produced natural gas described in Scenario 1 is its day-to-day cost of production and any other costs which directly relate to its production and use within the project (e.g., royalties or severance taxes). The cost of production attributable to this natural gas would be a subset of the day-to-day cost to operate the entire EOR project and must be determined by a reasonable method. Royalties and severance taxes are not routinely due on produced hydrocarbons that are consumed within a lease or unit as part of production operations. Verification of whether such payments were made should not be difficult.
Examiners should be aware that some taxpayers have used a hypothetical market price/value of natural gas (i.e., $ per MCF) to help determine the “qualified cost” of the volume of self produced gas that is produced and consumed within the EOR project. This has resulted in excessive amounts claimed as qualified tertiary injectant expense. Evidence of this improper practice could be found by looking for equal (and offsetting) amounts of imputed expense and revenue on the lease operating statements for the project. It may be more practical to directly ask the taxpayer to explain how it determined the cost of any self produced gas that was used as fuel in an EOR operation.
Scenario 2: The facts are similar to Scenario 1 except that the taxpayer’s natural gas is produced from wells drilled on other properties which it owns and which are outside the bounds of the EOR project. Assume that none of the wells or equipment qualified for the EOR tax credit when they were installed. In this scenario the taxpayer does pay royalties and severance taxes when it removes the natural gas from these other properties. The taxpayer also pays a transportation fee to the owner of a pipeline that is used to deliver the gas to the EOR project. What is the qualified cost of the fuel in this scenario?
Answer: The qualified cost of the self produced natural gas described in Scenario 2 includes a reasonable portion of the day-to-day cost of production of the other properties, the related royalties and severance taxes, and the related transportation fee. Examiners can also allow a reasonable amount to reflect the depletion of the taxpayer’s gas reserves and depreciation of specific equipment if such allowance is warranted by all the facts and circumstances.
Examiners should be aware that it can be more difficult to uncover the improper use of hypothetical market price/value of natural gas when it is transported between leases since the offsetting imputed expense and revenue amounts would be recorded on separate lease operating statements. It may be more practical to directly ask the taxpayer to explain how it determined the cost of any self produced gas which was used as fuel in an EOR operation.
Question: Is the cost of water disposal equipment which is located "downstream" of the equipment used to complete the separation of water from the produced crude oil a qualified tangible property cost? Examples include discharge pumps, water lines, and disposal wells.
Answer: No. A review of the applicable regulation is useful in explaining this answer.
Regulation §1.43-4 states in part that for tangible property to qualify for the EOR tax credit it must be (1) used for the “primary purpose” of implementing an EOR project and (2) be an integral part of a qualified enhanced oil recovery project. The regulation also states that tangible property is an integral part of a qualified enhanced oil recovery project if the property is used directly in the project and is essential to the completeness of the project.
Several examples of assets used to implement EOR projects are provided in Reg. §1.43-4(b)(4). The stated premise of the examples is that each asset is used for the primary purpose of implementing an EOR project. However, the examples explain and show that some assets qualify for the EOR tax credit and others do not:
- From Example 1: “* * * [Taxpayer] acquires an operating mineral interest in a property and undertakes a cyclic steam enhanced oil recovery project with respect to the property. * * * [T]he equipment to remove the gas and water from the oil after it is produced * * * [is] used directly in the project and * * * [is] essential to the completeness of the project. Therefore, this equipment is an integral part of the project and the costs of the equipment are qualified enhanced oil recovery costs.”
- From Example 1: “* * * [A]lthough the building that * * * [taxpayer] constructs as an office and the cars and trucks * * * [taxpayer] purchases to provide transportation for monitoring the wellsites are used directly in the project, they are not essential to the completeness of the project. Therefore, the building and the cars and trucks are not an integral part of the project and their costs are not qualified enhanced oil recovery costs.”
- From Example 3: “Oil storage tanks. * * * [Taxpayer] acquires storage tanks that * * * [it] will use solely to store the crude oil that is produced from the enhanced oil recovery project. The storage tanks are not used directly in the project and are not essential to the completeness of the project. Therefore, the storage tanks are not an integral part of the enhanced oil recovery project and the costs of the storage tanks are not qualified enhanced oil recovery costs.”
- From Example 5: “Gas processing plant. * * * A gas processing plant where * * * [taxpayer] will process gas produced in the project is located on * * * [taxpayer’s] property. The gas processing plant is not used directly in the project and is not essential to the completeness of the project. Therefore, the gas processing plant is not an integral part of the enhanced oil recovery project.”
- From Example 6: “Gas processing equipment. The facts are the same as in Example 5 except that * * * [taxpayer] uses a portion of the gas processing plant to separate and recycle the tertiary injectant. The gas processing equipment used to separate and recycle the tertiary injectant is used directly in the project and is essential to the completeness of the project. Therefore, the gas processing equipment used to separate and recycle the tertiary injectant is an integral part of the enhanced oil recovery project and the costs of this equipment are qualified enhanced oil recovery costs.”
Disposal of produced water is a day-to-day activity that occurs in almost every oilfield at some point in its life. Other activities that occur day-to-day include:
- Transportation of oil from the property where it had been produced from an underground reservoir and then made saleable by the removal of water and natural gas (and any other contaminants that would prevent it from being saleable). Equipment such as oil storage tanks, sales meters, and oil pumps are commonly located at the outlet of the equipment that separates the oil and removes contaminants.
- Processing of natural gas after it has been separated from oil and water. Depending on the requirements of gas purchasers in the vicinity of the property, an operator may employ processing equipment such as a dehydrator, sulfur reduction unit, low temperature separator (for NGL recovery) and compressor to bring the gas to “pipeline specification.”
Examples 3 and 5 of the regulation state that the oil storage tanks and gas processing equipment are not used directly in the project and are not essential to the completeness of the project; therefore, they are not integral parts of the project. This conclusion is reached in spite of the stated premise that they were used for the primary purpose of implementing an enhanced oil recovery project. Thus, the regulations make clear that for an asset to be used directly in the project and be essential to its completeness, it must be needed to capture (i.e., isolate) saleable crude oil within the bounds of the project. Once the saleable crude oil has been captured, the equipment that handles it and the other produced byproducts after that point are not used directly in the project and are not essential to its completeness.
Stated another way, the regulations make clear that assets that are “downstream” of the oil separation process do not qualify for the EOR credit (unless they are used in recycling of the injectant, as explained in Example 6). The equipment used to dispose of produced water is analogous to the oil storage tanks and gas processing equipment discussed in Examples 3 and 5 of the regulation. Therefore, water disposal equipment is (1) not used directly in the project, (2) not essential to its completeness, and (3) therefore not an integral part of the project.
Question: Is the cost to dispose of produced water a qualified tertiary injectant expense that generates the EOR tax credit? Examples include the operation of water discharge pumps and fees paid to third-party owners of disposal ponds. Assume that some or all of the produced water had been previously injected as part of a tertiary recovery process such as a steam drive or CO2 water-alternating-gas flood, but the operator has chosen not to recycle it. Also assume that the water was produced via normal oil production wells that serve a qualified EOR project.
Answer: No. The rules related to tertiary injectant costs qualifying for the EOR credit are different than those related to qualifying equipment. IRC §43(c)(1)(C) provides that the credit is allowable for any qualified tertiary injectant expenses as defined in §193(b). Section 193(b)(1) provides in general that the term “qualified tertiary injectant expenses” includes any cost paid or incurred for any tertiary injectant which is used as a part of a tertiary recovery method. The IRS issued Revenue Ruling 2003-82 to provide guidance as to what expenditures are included in the term “qualified tertiary injectant expenses” under §193(b).
Some of the relevant facts considered in that ruling are:
- “In some cases, X [the taxpayer] purchased liquids and gases to inject into the reservoirs in connection with the EOR projects. In other cases, X produced tertiary injectants (for example, X burned natural gas to fuel boilers that produced steam for use as an injectant) rather than purchasing them.”
- “X paid or incurred costs either to acquire or produce the liquids and gases used as tertiary injectants in X's EOR projects. In addition to the costs of acquiring or producing the tertiary injectants, X also incurred costs to inject, recover, and reinject the purchased and produced tertiary injectants.”
The ruling found that the legislative history underlying §193 indicates that tertiary injectant expenses include costs related to the use of a tertiary injectant; for example, "costs related to injecting a substance with a transitory effect on production" and “costs of producing and reinjecting gas or hydrocarbon liquids utilized in a recycling process." See S. Rep. No. 394, 96th Cong., 1st Sess. 97 (1979), 1980-3 C.B. 131, 215. The legislative history further states that the purpose of §193 is "to encourage the use of expensive tertiary enhanced oil recovery processes." Id. 1980-3 C.B. 131, 216. Neither §193 nor its legislative history, however, indicates that the term "qualified tertiary injectant expenses" was intended to include costs a taxpayer would have paid or incurred in the development or operation of a mineral property if an enhanced oil recovery project had not been implemented with respect to the property; for example, costs paid or incurred to plug and abandon wells.
Some taxpayers have asserted that the phrase “use of a tertiary injectant” as used in the ruling encompasses any new or increased operating expense that may result from the project’s implementation. An example of this would be the disposal cost of excess produced water resulting from a WAG water-alternating-gas or steam injection project. While such costs may be significantly impacted by the tertiary injection project, they are not the type of cost held in the ruling to reflect the “use of” the tertiary injectant. The ruling factually considers only the costs to acquire, produce, inject, recover, or reinject the tertiary injectant, and its holding that costs related to the “use of” the tertiary injectant is limited to those specific types of costs. Costs that pertain to operating expenses that do not involve the handling of a tertiary injectant would not qualify even though such costs may be impacted by the EOR project. They may be operating costs, but they are not tertiary injectant expenses.
Similar arguments could be made for the P&A costs of injection wells drilled specifically for the EOR project. The credit is available for their drilling costs and arguably for their operation as a conduit for injection, yet the ruling specifically cites costs related to their abandonment as the type of cost that would have been paid or incurred irrespective of the EOR project and as therefore ineligible for the credit. Though it may be argued that the P&A costs associated with these wells were directly “caused by” the use of a tertiary injectant, the concept of a “causal” relationship appears to have been rejected by the ruling in favor of an “in order to” standard. In other words, tertiary injectant expenses are incurred in order to acquire, produce, inject, recover, or reinject the injectant. Unless there is a reasonable nexus between the purpose for which a particular cost is incurred and one of these activities, no portion of the cost can be considered a tertiary injectant expense.
Disposal costs related to the cleanup and disposal of waste streams that will not be reinjected as a part of the tertiary injectant project are therefore not “qualified tertiary injectant expenses” for purposes of the EOR tax credit because they were not incurred in order to acquire, produce, inject, recover, or reinject a tertiary injectant.
Question: When cyclic steam wells that commenced steam injection before January 1, 1991, are continuously cycled after that date, does each cycle constitute a qualifying “significant expansion project?”
Answer: No. Cyclic steam injection is a qualified tertiary recovery method for purposes of the EOR tax credit. It is defined in Reg. §1.43-2(e)(2)(i)(B) as follows:
Cyclic steam injection – The alternating injection of steam and production of oil with condensed steam from the same well or wells
Cyclic steam operations became popular in the mid-1960s for recovery of heavy oil from oilfields in the vicinity of Bakersfield, California. From the onset it was common knowledge that a cyclic steam well would undergo multiple cycles during its lifetime in order to maximize recovery from the area which it was intended to drain. See generally Chapter 8 “Thermal Recovery Processes” from Enhanced Oil Recovery, SPE Textbook Series, Vol. 6, Green and Willhite Editors. No prudent operator would drill and equip a cyclic steam well and then cycle it only one time. Neither would a prudent operator of a cyclic steam well arbitrarily stop the cycling of the well simply because a certain date on the calendar passed.
Reg. §1.43-2(a) lists the requirements for an enhanced oil recovery project to be qualified. Subparagraph (3) requires that the first injection of fluids must occur after December 31, 1990. However, §1.43-2(d) provides for a small number of exceptions to subparagraph (3) in the case of a “significant expansion.” A project can be considered significantly expanded if the post-1990 injection of fluids will result in a more than insignificant increase in the amount of crude oil recovered from reservoir volume that was substantially unaffected by fluid injection before January 1, 1991. It is the expansion that qualifies for the EOR tax credit, not the continuation of the original pre-1991 project.
Example 1 of §1.43-2(d)(5) discusses a case in which a cyclic injection project began injecting steam in 1988. In 1992, cyclic steam injection begins in reservoir volumes substantially unaffected by the previous cyclic steam injection. The example concludes that the new injection project is treated as a separate project. This example refers to different wells in a different part of the reservoir. The reservoir volume substantially affected by a project is that portion of the reservoir that is reasonably expected to be affected during the life of the project. In the case of cyclic wells, the project includes all cycles until the wells reach their economic limit.
There would be no reason to establish the December 31, 1990, date if one takes the position that each injection cycle is a new project. The December 31, 1990, date applies to all types of EOR projects. There is no exception in the code or regulations that indicates that this date does not apply to cyclic steam injection.
The same point can be made with an example of a steam drive project which began injection in early 1989. Assume it consists of four injection wells and one production well and that the recovery from this project was projected to be 50,000 barrels oil (BO). By January 1, 1991, the project has recovered 20,000 BO. The project is expected to reach its economic limit in 1999. The projected ultimate recovery is still 50,000 BO. The mere continuation of production operations past the January 1, 1991, date does not create a new project or a significant expansion project. To conclude otherwise would render meaningless the significant expansion exception granted to projects that are terminated for a minimum of 36 months.
Question: When cyclic steam wells that commenced steam injection before January 1, 1991, have a cessation of steam injection that exceeds 36 months, does such cessation constitute the termination of a project so that subsequent cyclic steam operations constitute a qualifying “significant expansion project?”
Answer: No, not necessarily. Reg. §1.43-2(d)(3) clearly states that a tertiary recovery method is not necessarily terminated merely because the injection of the tertiary injectant has ceased. The regulation also clearly states that a method terminates at the point in time when the method no longer results in more than an insignificant increase in the amount of crude oil that ultimately will be recovered. All the facts and circumstances determine when that occurs. As long as oil is being produced due to the previous injection of steam the ultimate recovery of oil continues to increase. That is a fact which dictates that the earliest date on which termination of a project can occur is 36 months after the cessation of thermal oil production. Another fact that is likely to be key is the date at which the reservoir temperature and pressure returned to levels that no longer had a meaningfully impact on the productivity of oil from the reservoir.
Reg. §1.43-3(a)(3)(ii) sets forth the specific items that must be contained in a petroleum engineer’s certification of a project that depends upon the 36-month termination rule.
Question: Does the de minimis exception contained in Reg. §1.43-4(a)(2) apply to situations where the same type of injectant is used in more than one EOR project but where the same physical injectant is not used in more than one project?.
Answer: No. Taxpayers routinely purchase injectants from third parties on a dollar per unit basis (e.g., $ per barrel of steam or $ per MCF of CO2) and in large enough quantity to supply multiple EOR projects. When any asset is obtained for the purpose of implementing more than one EOR project, an allocation of its cost must generally be made between the projects. This is especially true if one of the EOR projects is not qualified for the tax credit (e.g., because it commenced injection before January 1, 1991). This is clearly required by Reg. §1.43-4(a)(2). See also Example 7 of Reg. §1.43-4(b)(4), which deals with the allocation of the cost of a single steam generator which will serve two EOR projects.
Reg. §1.43-4(a)(2) provides an exception to the allocation rule when the use of the property for nonqualifying purposes is de minimis (e.g., not greater than 10 percent). When an injectant is purchased on a dollar per unit basis, the taxpayer knows the cost of each barrel of steam or MCF of CO2 and the quantity it has purchased. This information can be found on invoices. Taxpayers also know the quantity of injectant that has been injected into each well since this information is routinely reported to oil and gas regulatory agencies. Lastly, taxpayers know which injection wells serve which particular EOR projects that they operate. Therefore except in very rare instances where one injection well serves two or more projects, there is no cost of injectant that needs to be allocated between projects.
For injectants that the taxpayer produced itself, the unit cost is typically determined by taking the sum of appropriate costs such as fuel, labor, utilities, etc. and then dividing by the quantity of injectant produced. Examiners will have to review both the underlying costs and the taxpayer’s methodology to determine if the unit cost is reasonable. The unit cost is applied directly to each project as described in the paragraph above.
Question: Is the cost to work over (i.e., repair) a cyclic steam well analogous to the cost to repair an injection well, even if none of the gas or water produced from the well is used in a qualified activity such as recycling to make additional steam?. Assume the cost of the workover is an ordinary and necessary business expense that is deductible under IRC §162, but does not meet the definition of intangible drilling costs.
Answer: IDD #1 on the EOR Credit states that the cost to work over an injection well is a qualified tertiary injectant expense. However, the directive states that the cost to work over a well that does not contribute to recycling or handling of tertiary injectants is not a qualified tertiary injectant expense. Whether the cost of a workover described above – or a portion thereof – is a qualified tertiary injectant expense depends on all the facts and circumstances. Generally, if one of the reasons the workover is being performed is to correct or improve the injection of steam into the well, then some portion of the workover cost will qualify. The purpose(s) behind the workover should be evident by inspecting the Authorization for Expenditure (AFE). Discussions with the engineers and field personnel for the operator can be useful too. The portion that can be qualified as a tertiary injectant expense depends on such things as the relative importance of improving oil production versus improving steam injection.
This Directive is not an official pronouncement of law and cannot be used, cited, or relied upon as such.