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Attachment 3 - Audit Evaluation for EOR Tax Credit

Attachment 3
Audit Evaluation for EOR Tax Credit

Significant Expansion Issue. 

This issue is most prevalent for tax years in the early 1990’s although it can be an issue for later years.  IRC §43 generally restricts the credit to projects where first injection of the tertiary injectant into the reservoir occurred after December 31, 1990.  However, the regulations provide an exception for projects that are “significantly expanded” after that date.  Reg. §1.43-2(d) (2) states:

(2) Substantially unaffected reservoir volume.  A project is considered significantly expanded if the injection of liquids, gases, or other matter after December 31, 1990, is reasonably expected to result in more than an insignificant increase in the amount of crude oil that ultimately will be recovered from reservoir volume that was substantially unaffected by the injection of liquids, gases, or other matter before January 1, 1991.

It is the expansion of the pre-1991 project that is treated as a qualified project, not the continuation of the original project.  Reg. §1.43-2(d) (1).  Thus, only those costs paid or incurred to implement the significant expansion project qualify for the EOR credit.  The costs to carry on the pre-1991 project do not qualify even if they were paid or incurred after 1990. 

The starting point for the review of this issue will be to determine if the project described in the Petroleum Engineer’s Certification meets the definition of a significant expansion project in the regulations.  Examiners should make sure the certification contains all the items required by Reg. §1.43-3, especially an adequate delineation of the reservoir volume affected by the pre-1991 project and the post-1990 expansion.  Without adequate delineations it is nearly impossible to determine whether an activity (such as injecting carbon dioxide (CO2) into certain wells) was done to carry on the pre-1991 project or to implement the post-1990 expansion project.  An adequate delineation means a visual three-dimension representation such as a structure map combined with an annotated well log section.  See TAM 103300-05 (cited as PLR 2005-35028) for an in-depth discussion of this topic. 

The practical application of the significant expansion exception is fairly straightforward where the pre-1991 project and the post-1990 expansion project constitute distinct layers or vertical portions of the same reservoir.  For example, a steam flood that began before 1991 in the upper portion of a reservoir with significant vertical thickness would not preclude the significant expansion of the steam flood into the lower portion of the reservoir.  This would be accomplished by identifiable physical activities such as the installation of new injection wells or the completion of existing injectors into the lower portion of the reservoir.  Likewise, an aerial expansion of a tertiary flood to unflooded patterns on the periphery of a reservoir is fairly straightforward to review.  As long as the effect of the pre-1991 flooding is limited to certain patterns, the implementation of flooding in peripheral patterns can constitute a significant expansion.  Approval from an oil and gas agency is often required before these types of expansions can be undertaken, and operators typically must submit a substantial amount of information to gain approval.  This information is usually available for review by the public.

Some taxpayers have taken the position that various “infill projects” can also qualify as significant expansions even when first injection of the tertiary injectant into the project area occurred well before January 1, 1991.  Typically these are CO2 floods that involve the same overall reservoir volume, but the flood has been modified after 1990 to varying degrees.  The modifications may include such things as:

  • switching injectors and producers
  • altering the water-alternating-gas ratios
  • changing the daily injection rates or
  • deciding to eventually inject a cumulative volume of CO2 in excess of that described in the original project plan.

Taxpayers have generally argued that these modifications are affecting reservoir volume that was significantly unaffected by the pre-1991 injection of the tertiary injectant.  For many years the position of the Petroleum Industry Technical Advisors and LMSB has been that these kinds of arguments are contrary to the clear holdings of two specific regulations. 

  • Absent a ruling from the IRS, a project that commenced before 1991 can not be qualified for the credit unless the tertiary recovery method has been terminated for more than 36 months before being implemented again.  See 1.43-2(d) (3) and Example 2 of Reg. §1.43-2(d)(5).
  • The more intensive application of the same tertiary recovery method to the same reservoir volume does not constitute a significant expansion project.  This is true even if the more intensive use is expected to result in an increase in ultimate recovery of crude oil.  See Example 5 of Reg. §1.43-2(d)(5).

A few taxpayers have taken the very aggressive stance that an EOR project is significantly expanded on January 1, 1991 by the mere fact that the continued operation of the project (i.e. with normal levels of injection) will recover more oil than compared to the oil recovery that would occur if the use of the tertiary were to cease on that date.  A project that is claimed as qualifying for the EOR credit based on such a premise should be rejected.  All the costs that were claimed as qualified by the taxpayer should be disallowed by the examiner.  The examiner should also obtain the identity of all the working interest owners in the project and contact the Petroleum Industry Technical Advisors with such information.

These types of arguments were also addressed in great length in TAM 103300-05 (cited as PLR 2005-35028) and rejected.  The TAM states that in order to affect reservoir volume unaffected by previous EOR efforts, at least new wells or new perforations in wells would be required. 

An examiner may encounter a project that the taxpayer treats as a significant expansion and which consists of the drilling of new wells and / or the opening of new perforations in existing wells, both of which relate to a reservoir that had first injection before 1991.  The examiner must use professional judgment to determine if the purpose of such activity was to facilitate the interaction of tertiary injectant with oil that occupies reservoir volume that had not been swept by the pre-1991 injection project and would not be swept through the conclusion of that project.  See TAM 200227002 (23 Jul 2001) for a discussion of this topic. 

If the examiner concludes that a legitimate significant expansion project exists, the final step will be to ensure that the costs claimed as qualified are only those which are attributable to the significant expansion project.  Costs that are attributable to the continuation of the pre-1991 project are not qualified.  Ascertaining the spud date of the injection wells used in the expansion project is a useful audit tool.

Qualified Costs.  Even when the project described in the Petroleum Engineer’s certification appears to be qualified, the correctness of the costs claimed by the taxpayer can not be assured.  The certification is usually written before many of the costs to implement the project are incurred.  While the certification might state how many producing or injection wells will be drilled, it may not identify them or how much they will cost to drill and equip.  It is incumbent upon the taxpayer to determine whether the cost of any particular well, piece of tangible equipment, or tertiary injectant was incurred for the primary purpose of implementing one or more enhanced oil recovery projects, at least one of which is a qualified enhanced oil recovery project.  See Reg. §1.43-4(c)(1).  The examiner will want to verify the project costs to the activities described in the project certification.

Qualified EOR projects are often interspersed with other non-qualifying projects from both an operational and book and records standpoint.  Experience has shown that tax departments that do not consult with their operations department often claim costs that are not qualified.  Examiners may want to verify that the identity of qualified wells, equipment, and injection volumes was done by a technically qualified person. 

Examples of issues identified include the following:

  • Injection volumes (and costs) were overstated because some of the injection wells were completed in multiple reservoirs, one of which was not part of a qualified EOR project. 
  • The qualified cost of tangible equipment and wells was overstated because these assets were installed to implement both a qualified EOR project and a non-qualified project EOR project on the same property. 
  • When EOR projects are implemented at the commencement of production to improve the overall project economics in addition to increasing the ultimate recovery of oil, certain costs may not meet the primary purpose test under Reg §1.43-4(c).  Contact the Petroleum TA if you encounter this situation.

Tertiary Injectant Costs Issue.

Included as a category of qualified costs under section 43(c)(1) are “qualified tertiary injectant expenses (as defined in §193(b))” which are paid or incurred in connection with a qualified EOR project and for which a deduction is allowable for the taxable year.  This specific definition of qualified tertiary injectant expenses was retroactively amended and broadened by Congress in Section 317(a)(1)-(2) of the Community Renewal Tax Relief Act of 2000, Pub. L. 106-554, 114 Stat. 2673A-5872000.  To date Reg §1.43(b)(1) has not been modified to reflect this change in the law. 

Revenue Ruling 2003-82 holds that the definition of the term “qualified tertiary injectant expenses” (as defined in §193(b)) includes expenditures related to the use of a tertiary injectant as well as expenditures related to the acquisition (whether produced or acquired by purchase) of the tertiary injectant.  Specifically included in the former are costs to inject, recover, and reinject the purchased and produced tertiary injectants.  The ruling also holds that “qualified tertiary injectant expenses” do not include costs a taxpayer would have paid or incurred in the development or operation of a mineral property if an EOR project had not been implemented with respect to the property.  Costs that are related to the use of a tertiary injectant and that also are related to other activities (for example, primary or secondary recovery) must be reasonably allocated among the tertiary injectant and the other activities to determine the amount of tertiary injectant expenses paid or incurred by the taxpayer for the taxable year.

Taxpayers’ Claims for Additional Credit.  Following the issuance of Revenue Ruling 2003-82, many taxpayers filed claims for additional EOR tax credit.  To prepare such claims they often extract broad categories of costs from their historical accounting records and apply allocation formulas to such costs.  Reviewing these claims can be challenging, time–consuming, and require specialized knowledge of oil production operations.  If such claimed amounts are material then a SRS referral should be made to obtain the services of an IRS Petroleum Engineer.

The books and records for production operations (sometimes called “lease operating statements”) will normally have a category of costs for the acquisition by purchase of tertiary injectants.  However, such records usually will not specify the cost to self produce or use tertiary injectants.  For instance, a producer may have accounting records that indicate the cost of purchased electricity that was consumed in the overall operation of an oil field undergoing an EOR process, which may include many activities unrelated to tertiary injectants.  However, it is unlikely that the accounting records will have captured the cost of electricity used to operate the specific equipment that handled tertiary injectants.  Examiners will want to make note of the cost – on a $/MCF or $/Bbl basis - to acquire injectants via purchase.

Analyze Each Claim in Terms of “Activities” and “Costs.”  For an effective and efficient examination, analyze this issue from two different aspects – “activities” and “costs.”  Revenue Ruling 2003-82 clearly states that the cost to inject a tertiary injectant will qualify as a tertiary injectant expense and generate the tax credit.  Without knowing how the injection process works, it is impossible to determine or estimate the injection cost.  The importance and interrelationship of these two aspects can be shown by an example.

  An investigation of the facts indicates that the following activities were undertaken to
  accomplish injection of CO2 during the taxable period:

  • An electrically powered gas compressor was run nearly continuously to compress and deliver to injection wells CO2 purchased from a third party supplier. 
  • Electricity to power the compressor and for other unrelated leasehold operations was purchased from an unrelated supplier.  There was no record of how much electricity was actually consumed by the compressor.
  • As part of their general duties, pumpers (i.e. field maintenance personnel) made periodic visits to the compressor to check on its operation and to adjust same
  • The pumpers replaced items consumed in operation of the compressor such as lubricating oil and small parts.  These items came from a spare parts warehouse on the premises that served several facets of the overall operation
  • The compressor was shut down once for major maintenance that was performed by outside vendors
  • A field foreman supervised the work of the pumpers and outside vendors

  An investigation of the facts showed that the taxpayer recorded expenditures that
  relate to the above activities or to the compressor in general:

  • They purchased electricity for use in overall field operations
  • They paid wages to the pumpers and to the field foreman
  • They paid benefits and taxes on behalf of the pumpers and field foreman
  • They paid a supply company to keep their spare parts warehouse stocked
  • They paid the outside vendor for the major maintenance

Only by having a good understanding of the activities performed to inject the tertiary injectant and the purpose behind the associated expenditures, can the examiner determine a reasonable allocation method to arrive at what cost was paid or incurred for the injection operation.  In this example if electricity is a major cost, then a reasonable allocation may require a knowledgeable individual to estimate how much electricity was consumed in operating the compressor for the taxable period, and to compare this to the total amount purchased.  Allocating the cost of labor and benefits to the operation of the compressor could be quite challenging.  It may require an interview of someone who is knowledgeable about all the duties of these personnel.  If, for instance, the personnel cost pales in comparison to the electricity cost, then it’s probably not worth the time to achieve a rigorously correct allocation method of the personnel cost. 

Activities:  Examiners should gain a thorough understanding of all the important physical activities that were conducted in the operation of the qualified EOR project(s).  Since EOR projects often exist within larger oil and gas production operations, this understanding must extend to what activities benefited both the qualified EOR project and other oil and gas recovery projects within the larger operations.  From the totality of all the activities conducted in the operation of the qualified EOR project, the examiner will have to determine which ones had a reasonable nexus to the acquisition, production or use of the tertiary injectant. 

In making this determination a good place to start is the operator’s Petroleum Engineer’s certification submitted for the project.  As mentioned earlier, other sources of information include industry articles, filings with regulatory commissions, and the taxpayer’s website.  A process or flow diagram of the surface operations of the field where the EOR lies should be requested.  An interview with a knowledgeable technical representative of the taxpayer or operator may be necessary.

Examples of Qualifying and Non-Qualify Activities:  LMSB has determined that certain activities are either qualifying or non-qualifying for purposes of the tax credit

  Qualifying Activities include:

  • The operation of source wells, pumps, compressors, meters, lines, etc. to transport tertiary injectant from point of acquisition to the EOR project and eventual injection into the reservoir
  • The operation of equipment used to produce, recover, recycle and reinject tertiary injectant into the reservoir
  • The repair of equipment used to produce, recover, recycle and reinject tertiary injectant into the reservoir
  • Performing workovers on injection wells

  Non-Qualifying Activities include:

  • Workovers on wells that do not produce any fluids used for injection or to fuel equipment used to handle tertiary injectants
  • Workovers on wells that do produce fluids used for injection or to fuel equipment used to handle tertiary injectants, when the sole purpose of such workover is to improve the efficiency of recovering saleable hydrocarbons
  • Disposing of tertiary injectant (as opposed to recovery for reinjection)
  • Conducting environmental studies
  • The operation of any wells or equipment that is located outside of the bounds of the project unless it is specifically described in the petroleum engineer’s certification

Costs:  Examiners should now focus on which costs (or portion of costs) should be viewed as having been paid or incurred in order to conduct the activities of acquiring, producing or using tertiary injectants in a qualified EOR project.  The allocation of costs follows the nature of the underlying expenditures.  It is not uncommon for a taxpayer to combine a wide variety of expenditures into a pool of costs and then allocate the total to tertiary injectant expenses based on relative volumes of fluids injected or number of injection wells operated.  Only if the taxpayer can explain the nexus between an expenditure and the acquisition or use of a tertiary injectant should the expenditure be subject to any pooling or allocation. 

Examples of Qualifying and Non-Qualify Costs:  LMSB has determined that certain costs are either qualifying or non-qualifying for purposes of the EOR tax credit.

  Qualifying Costs include:

  • Wages and fringe benefits of field personnel, to the extent they are engaged in qualifying activities (i.e. the operation of equipment to produce or acquire or use tertiary injectant).  Assumes such costs are of the nature that non-operators would reimburse the operator.
  • Payments to third parties for consumables such as raw materials, fuel, and utilities used for qualifying activities
  • Expenditures to third parties to perform qualifying activities
  • Overhead / administrative costs to the extent they support qualifying activities and are of the magnitude that non-operators would reimburse the operator

  Non-Qualifying Costs include:

  • Royalties and severance taxes paid on value of hydrocarbon sales
  • Ad valorem taxes based on appraised value of mineral
  • Ad valorem taxes based on appraised value of equipment
  • Amounts paid for non-qualifying activities
  • Overhead above field level that would not be reimbursed by non-operators

Allocation or Apportionment of Activities:  When a facility is operated in order to recover substances that are saleable (or used other than in the tertiary recovery process) and also tertiary injectant, the activities undertaken to operate the facility must be assigned or allocated on a reasonable basis to the substances produced by the facility.  An allocation based on the relative value or relative volume of the useable substances produced by the facility may be reasonable at times.  An example of an oil skimmer will demonstrate why allocation based on relative volume may not always be reasonable.

This example deals with a miscible water-alternating-gas (MWAG) project which is a qualified EOR project.  Because the injection of the water is necessary to move the miscible gas and mobilized oil through the reservoir, it is clearly related to the use of the miscible gas.  Therefore, the reasonable cost to acquire, inject, recover and recycle water can be a qualified tertiary injectant cost.  In this case, a processing vessel in the recovery / recycling phase yields fluid composed of 97% water and 3% oil which is suitable for injection without further processing.   The value of the oil, however, is such that the operator installs an oil skimmer to recover the entrained oil for sale.  Regardless of the relative volumes of oil and water, none of the costs to operate the skimmer are qualified in this case because the stream was already suitable for injection.  Once a stream of liquid or gas is chemically suited for injection, no further processing of such stream is an activity related to handling a tertiary injectant.  Of course the subsequent pumping or compression of such stream to actually inject it into the reservoir is qualified activity, and the cost of doing so is related to the use of a tertiary injectant. 

If in the above example the fluid was not suitable for injection as a tertiary injectant, it will be a question of fact if any particular allocation method is reasonable.  To that end it will be important to ask why the operation is being conducted and what benefits it brings.  In order to test the reasonableness of any taxpayer allocation it will be very important to know whether the operator could have obtained additional “fresh” injectants from outside sources, what the price was during the time in question, and what additional processing (if any) was required so that it could be injected.  To demonstrate this concept, consider the following example:

Assume from the earlier example that the skimmer must be operated to obtain saleable oil, and as a side benefit it also produces water suitable for injection.  The latter reduces the amount of “make-up” water the operator must obtain from outside sources for injection.  Further assume that the sales price of oil is $20 per barrel, and the acquisition cost for water is $0.10 per barrel.  Thus, from the previous example the 3 barrels of oil could have been sold for $60 and the 97 barrels of water allowed the taxpayer to avoid spending $9.70 on make-up water.  An allocation based on relative volumes would assign 97% of the cost of the activity to water, with the remainder to the saleable oil.  Depending on the cost to operate the skimmer, this allocation method could yield a cost for the 97 barrels of water that exceeds the cost to obtain that amount of make-up water.  With these facts it is clear that an allocation based on volumes of recovery is not realistic.  This is because the operation was required to obtain both saleable oil and injectable water, but the benefit was approximately 86% in favor of recovering saleable oil ($60 out of $69.70).  Using this methodology as recommended by LMSB, only 14% of the cost of this activity qualifies as a tertiary injectant expense. 

If the oil in the example would not have been saleable due to the need for further processing, then an allocation based on relative value may be too difficult to perform for this particular piece of equipment.  An allocation based on relative volume may be the only expedient method.  When that method is used for major quantities of fluids that are recovered and / or recycled for reinjection, the examiner should make a final computation of the average cost per unit of same for the entire EOR project. 

If the average cost per unit is in excess of the cost to obtain fresh injectant it should be adjusted downward accordingly.  Another possible approach is to compare the average operating costs before and after the implementation of a tertiary injection project in order to get a feel for the reasonable percentage of overall operating expenses that relates to qualifying activities.  The Society of Petroleum Engineers (SPE) Monograph on CO2 flooding suggests that operating costs increase on the order of 10% upon initiation of a CO2 flood.  This 10 % increase excludes the cost of purchasing CO2 and handling produced gas.  (See Practical Aspects of CO2 Flooding, SPE Monograph Series, Vol. 22, page 63)

Continue to check with the Petroleum Industry Technical Advisors for updates on this issue.

Page Last Reviewed or Updated: 06-Nov-2014