Natomas North America, Inc. v. Commissioner

90 T.C. No. 45, 90 T.C. 710, 1988 U.S. Tax Ct. LEXIS 44, 100 Oil & Gas Rep. 207

• Court: United States Tax Court
• Decided: April 18, 1988
• Docket: Docket Nos. 35928-85, 6712-86
• Status: Published

Opinion

GOFFE, Judge:

The Commissioner determined deficiencies in petitioners’ windfall profit tax as follows:

Docket No. TYE Dec. 31— Taxable quarter ended Deficiency

35928-85 1980 --- $51,103.07

1981 - - - ¹272,248.96

6712-86 1981 --- 113,814.13

9/30/81 48,266.61

12/31/81 61,755.78

3/31/82 56,635.11

6/30/82 53,505.46

9/30/82 51,307.75

12/31/82 72,602.61

The issues for our decision are: (1) Whether the miscible flue-gas injection project in the East Binger Unit was significantly expanded within the meaning of section 4993(d)(4)² so that a portion of the production from the property qualifies as incremental tertiary oil under section 4993, and (2) if so, when was the project beginning date within the meaning of section 4993(d)(2).³

FINDINGS OF FACT

Some of the facts have been stipulated and are so found. The stipulation of facts and exhibits are incorporated by this reference.

Petitioner Natomas North America, Inc., is a corporation organized under the laws of California. Petitioner’s principal office was located in Dallas, Texas, at the time it filed its petition in this case. For each of the taxable periods in issue, petitioner filed all required windfall profit tax returns with the Internal Revenue Service Center in Austin, Texas.

Petitioner Samedan Oil Corp., is a corporation organized under the laws of Delaware. Petitioner’s principal office was located in Ardmore, Oklahoma, at the time it filed its petition in this case. For each of the taxable periods in issue, petitioner filed returns with the Internal Revenue Service Center in Austin, Texas.

During the taxable periods in issue, petitioners owned working interests in certain properties located within the East Binger Field (field). The field is located in the Anadarko Basin of south-central Oklahoma and covers more than 13,000 acres. The reservoir is at a depth of 10,000 feet in the Pennsylvanian Hogshooter Sand.

By early 1976, the operators of wells in the field were seriously engaged in an effort to form a unit.⁴ By February 1, 1977, a consensus was reached to inject flue gas, and a unitization formula was approved by a majority of the operators. The field was unitized, effective August 1, 1977, and Phillips Petroleum Co. was elected operator. The operator derived its authority from the operating committee, which was comprised of representatives of the working interest owners in the unit. The operating committee formed a technical committee, which was charged with making recommendations to the operating committee with respect to technical matters.

The technical committee concluded that overall sweep efficiency in the field utilizing miscible flue-gas injection would be about 48 percent, resulting in the recovery of 44 percent of the oil in place. The term “miscible” means the point when two fluids become completely soluble in one another; they are able to dissolve in all proportions and remain a single-phase fluid. Miscible flue gas injection works by injecting flue gas into the reservoir at a sufficient pressure to achieve miscibility. This has the effect of sweeping the reservoir of oil and thereby significantly increasing the ultimate recovery of oil. Miscible flue gas injection is one of the methods described in subparagraphs (1) through (9) of section 212.78(c) of the June 1979 energy regulations. 43 Fed. Reg. 33689 (Aug. 1, 1978).

A contract was entered into with Production Operators, Inc., of Houston, Texas, to produce flue gas for injection. Flue gas is generated by taking hot exhaust gas from natural-gas-fueled compressor engines. The first flue gas was injected on September 10, 1977, into three injection wells. In April 1978, there were 17 injection wells, which were converted production wells. The injection pattern was an inverted nine-spot pattern with the injection well in the center of a nine-well array. The well density was 160 acres per well. The miscible flue gas injection project was designed to affect the entire reservoir.

Performance of the miscible flue-gas injection project was substantially below that expected, due primarily to operational problems and reservoir characteristics significantly different from those initially premised. Average reservoir permeability was determined to be approximately one-half of that initially premised, which substantially reduced injectivity. The reservoir was also found to have an oriented fracture system which resulted in early flue gas breakthrough. This caused poor sweep efficiency and associated poor recovery. Some of the production wells in the reservoir did not respond to the project. The working interest owners were seriously considering discontinuing the project and disbanding the unit due to the poor performance of the project.

In May 1978, the property owners in the unit commissioned Intercomp Resource Development & Engineering, Inc. (Intercomp), to prepare a compositional simulation study to ascertain why the miscible flue-gas injection project had failed to perform as projected and to evaluate the alternatives available.

On May 23, 1979, the technical committee met to discuss the results of the Intercomp study, review the various cases forecasted, and make recommendations for the operating committee to consider regarding future operations. The technical committee recommended that case IV analyzed by the Intercomp study be approved and implemented. Under this case, seven additional wells would be converted to injection wells to form three line drive patterns, and 14 additional wells would be drilled. The realignment of the injection pattern was designed to improve the distribution of flue gas throughout the reservoir. It was the consensus of the technical committee that the field was developed on spacing too wide to adequately drain the reservoir and that 80-acre spacing rather than 160-acre spacing would be desirable. The technical committee recommended that two wells be considered for drilling during 1979 to verify the conclusions of the Intercomp study.

In October 1979, the working interest owners were asked to approve the initial phases of case IV, and they approved the drilling of two wells. On July 23, 1980, the operator filed a self-certification with the Internal Revenue Service that satisfied the requirements of section 4993(c)(2)(D). Beginning in August 1980, a portion of the oil removed from the unit was treated as incremental tertiary oil under section 4993. The performance of the two wells, which were completed in September 1980, confirmed the conclusions reached in the Intercomp study. These wells encountered near virgin reservoir pressure and produced inert free hydrocarbon gas. Production from these wells relieved reservoir pressure in the area where they were drilled. This allowed flue gas to begin moving into that area of the reservoir. As a result, the injection wells were able to inject more gas into the reservoir. The subsequent production history of the wells verified this conclusion. Based upon the performance of the two wells, it was recommended that an immediate program to expand 80-acre development should be undertaken by drilling 10 additional wells and that a minimum of six production wells should be converted to injection.

In October 1980, the working interest owners approved the drilling of two additional wells. In March 1981, the working interest owners approved the drilling of 10 wells, and in May 1981, they approved the conversion of six production wells to gas injection. The production wells were converted to injection wells in August 1981. In January 1982, the working interest owners approved the drilling of two wells, and in August 1982, they approved the drilling of seven wells. The unit consisted of many small, independent operators and, due to the size of their cash-flow, many of them were limited in the amount of expenditures they could incur in any single year. They preferred to implement case IV in stages in order to maintain their cash-flow.

The implementation of case IV from 1980 through 1983 resulted in the drilling of 23 wells. All the wells were completed in such a manner that they could be utilized either as production or injection wells, at a cost of approximately $185,000 per well. This drilling program increased sweep efficiency in areas of the reservoir previously unaffected by the initial miscible flue-gas injection project. Twenty-two of the 23 wells encountered areas of the reservoir which did not contain flue gas. These wells increased the ultimate amount of oil to be recovered from the unit. These wells also increased the amount of flue gas being injected into the reservoir as the gas-oil ratio was sustained with the increased production, i.e., reservoir pressure was maintained. At the end of 1983, the total well count was 27 injection wells and 74 production wells.

In the statutory notices of deficiency, the Commissioner determined that petitioners were not entitled to treat a portion of the oil removed from the unit as incremental tertiary oil under section 4993. The Commissioner determined that the initial miscible flue-gas injection project was not significantly expanded within the meaning of section 4993(d)(4).

OPINION

The Crude Oil Windfall Profit Tax Act of 1980, Pub. L. 96-223, 94 Stat. 229, imposes a temporary excise, or severance, tax on certain crude oil produced in the United States. See sec. 4986; Shell Oil Co. v. Commissioner, 89 T.C.

371 (1987). The tax is computed under section 4987 as a percentage of the windfall profit defined by section 4988(a). Page v. Commissioner, 86 T.C. 1, 3 (1986). The percentage and the windfall profit depend upon the tier classification of the oil. Secs. 4987, 4988, 4989. Taxable crude oil is generally classified into one of three tiers.⁵ Sec. 4991. Incremental tertiary oil is classified as tier 3 oil and is defined as the incremental volume of oil produced after the project beginning date and during the period in which a qualified tertiary recovery project is in effect on the property. Secs. 4991(e)(1), 4993(a). A qualified tertiary recovery project is defined in section 4993(c)(1)(B)⁶ as any project for enhancing recovery of crude oil which meets the following requirements:

(A) the project involves the application (in accordance with sound engineering principles) of 1 or more tertiary recovery methods[⁷] which can reasonably be expected to result in more than an insignificant increase in the amount of crude oil which will ultimately be recovered,

(B) the date on which the injection of liquids, gases, or other matter begins is after May 1979,

(C) the portion of the property to be affected by the project is adequately delineated,

(D) the operator submits[⁸] (at such time and in such manner as the Secretary may by regulations prescribe) to the Secretary—

(i) a certification from a petroleum engineer that the project meets the requirements of subparagraph (A), (B), and (C), or

(ii) a certification that a jurisdictional agency (within the meaning of subsection (d)(5)) has approved the project as meeting the requirements of subparagraph (A), (B), and (C), and that such approval is still in effect, and

(E) the operator submits (at such time and in such manner as the Secretary may by regulations prescribe) to the Secretary a certification from a petroleum engineer that the project continues to meet the requirements of subparagraphs (A), (B), and (C).[⁹]

[Sec. 4993(c)(2).]

The parties disagree only over whether the requirement contained in section 4993(c)(2)(B) has been satisfied. Petitioners contend that the implementation of case IV was a significant expansion within the meaning of section 4993(d)(4)¹⁰ of the miscible flue-gas injection project and, therefore, it is a separate project. Petitioners conclude that because case IV is a separate project and was implemented after May 1979, the requirement contained in section 4993(c)(2)(B) has been satisfied. Respondent, on the other hand, contends that the injection of flue gas began before May 1979 because the implementation of case IV was not a significant expansion of the miscible flue gas injection project. Respondent contends that the tertiary activities implemented during the taxable years in issue were within the range of the original project. Respondent argues that actions taken pursuant to case IV were corrective measures and that case IV constituted an improvement of the project but not a significant expansion.

What constitutes a “significant expansion” is not defined in the statute. Significant expansion is not defined in the temporary regulations nor have final regulations been promulgated on this subject. Sec. 150.4993-1, Temporary Excise Tax Regs., 45 Fed. Reg. 23389 (Apr. 4, 1980).¹¹ The legislative history reveals that significant expansions include:

any which could qualify as expansions under the June energy regulations.[¹²] Pre-June 1979 projects which were curtailed significantly before 1980, and which were expanded to the average pre-curtailment level after that date, would qualify under this provision. A project would be considered to have been curtailed significantly, for example, if the average post-curtailment concentration of injected gases was reduced by 35 percent or more from the average pre-curtailment concentration of injected gases. For purposes of making this determination, the entire pre-curtailment project area would be compared with the same area after the curtailment. The conferees also clarified that expansions of otherwise qualifying projects could include a significantly more intensive use of a tertiary recovery method, or a significant expansion of tertiary activities, within a project area. [H. Rept. 96-817 (Conf.)(1980), 1980-3 C.B. 245, 260.]

The legislative history describes several situations which will qualify as significant expansions. Unfortunately, however, little guidance is provided. We conclude, therefore, that it is appropriate to examine all of the facts and circumstances in determining whether there was a significant expansion.

Respondent contends that the tertiary activities implemented during the taxable years in issue were within the range of the original miscible flue-gas injection project because as originally conceived, the project was designed to affect the entire reservoir. Although the original project was designed to affect the entire reservoir, it is evident that it did not. Some of the production wells in the reservoir did not respond to the original project. Twenty-two of the 23 wells drilled pursuant to case IV encountered areas of the reservoir which did not contain flue gas. These wells increased sweep efficiency in areas of the reservoir previously unaffected by the project. We think that additional activities which affect areas of the reservoir which were not affected by the initial project may constitute a significant expansion, notwithstanding the fact that the initial project was designed to affect the entire reservoir. It is more appropriate to examine the actual results of the initial project. We, therefore, reject respondent’s argument.

Respondent next contends that the tertiary activities implemented during the taxable years in issue were within the range of the original miscible flue-gas injection project because they were not designed to change the injection rate. Respondent argues that, although the realignment of the injection wells was designed to improve the distribution of the flue gas throughout the reservoir, it was not designed to change the injection rate. However, the realignment and its effect on the injection rate must be considered in conjunction with the entire course of events.

Performance of the initial miscible flue-gas injection project was substantially below that expected, due primarily to operational problems and reservoir characteristics significantly different than those initially premised. The working interest owners were seriously considering discontinuing the project and disbanding the unit, due to the poor performance of the initial project. In May 1978, the property owners in the unit commissioned Intercomp to prepare a compositional simulation study to ascertain why the project had failed to perform as projected and to evaluate the alternatives available. In May 1979, the technical committee recommended that case IV of the Intercomp study be approved and implemented. In October 1979, the working interest owners were asked to approve the initial phases of case IV, and they approved the drilling of two wells. Production from these wells, which were completed in September 1980, relieved reservoir pressure in the area where they were drilled and allowed flue gas to begin moving into that area of the reservoir. Consequently, the injection wells were able to inject more flue gas into the reservoir. Case IV was implemented in stages and completed in 1983. We disagree with respondent’s characterization that the tertiary activities were a “gradual response” and that we should examine each year separately. The unit consisted of many small, independent operators, and due to the size of their cash-flow, many of them were limited in the amount of expenditures they could incur in any single year. They preferred to implement case IV in stages in order to maintain their cash-flow.

Pursuant to the implementation of case IV, there were 27 injection wells, 10 more than the original miscible flue-gas injection project and an overall increase of 58 percent. The injection pattern was changed from an inverted nine-spot pattern to three line drive patterns. This realignment of the injection pattern was designed to improve the distribution of flue gas throughout the reservoir. In addition to this realignment, 23 wells were drilled and were completed in such a manner that they could be utilized either as production or injection wells, at a cost of approximately $185,000 per well. This drilling program increased sweep efficiency in areas of the reservoir previously unaffected by the initial project. Twenty-two of the 23 wells encountered areas of the reservoir which did not contain flue gas. These wells increased the ultimate amount of oil to be recovered from the unit. These wells also increased the amount of flue gas being injected into the reservoir as the gas-oil ratio was sustained with the increased production, i.e., reservoir pressure was maintained.

Based upon an examination of all the facts and circumstances, we conclude that the implementation of case IV was a significant expansion within the meaning of section 4993(d)(4). Consequently, we must decide the project beginning date.

The project beginning date is defined in section 4993(d)(2)¹³ as the later of:

(A) the date on which the injection of liquids, gases, or other matter begins, or

(B) the date on which—

* * * * * * *

(ii) in the case of a project described in subsection (c)(1)(B), a petroleum engineer certifies, or a jurisdictional agency approves, the project as meeting the requirements of subparagraphs (A), (B), and (C) of subsection (c)(2).i¹⁴)

Petitioners initially contend that because injection is already taking place when a significant expansion occurs, the project beginning date for such an expansion is the later of the date the expansion commences or the date of certification. Petitioners argue that the implementation of case IV began with the spudding of the first well on April 24, 1980. Petitioners then conclude that because the certification was filed on July 23, 1980, this is the project beginning date. The statute, however, compels a different analysis.

The statute provides that a significant expansion shall be treated as a separate project. Sec. 4993(d)(4). Therefore, to determine the project beginning date of a significant expansion, we must compare the date on which injection begins pursuant to the significant expansion with the date the significant expansion is certified. The later of these will be the project beginning date for the significant expansion. We disagree with petitioners that this interpretation, is not justified under the language of the statute.

The parties agree that the operator filed a self-certification with the Internal Revenue Service on July 23, 1980. The parties disagree, however, as to when injection pursuant to the implementation of case IV began. Petitioners contend that injection began when the first wells were completed in September 1980. Respondent contends that injection did not begin until the six production wells were converted to injection wells in August 1981. Respondent argues that prior to that time, there was no increase in tertiary activities and, therefore, no possibility of any incremental production response. The evidence, however, establishes otherwise.

Production from the two wells completed in September 1980 relieved reservoir pressure in the area where they were drilled. This allowed flue gas to begin moving into that area of the reservoir. As a result, injection wells were able to inject more gas into the reservoir. Therefore, we conclude that injection began in September 1980 when the first wells drilled pursuant to case IV were completed. Because this is later than the date the self-certification was filed, this is the project beginning date.

In sum, we conclude that the implementation of case IV was a significant expansion within the meaning of section 4493(d)(4) of the initial miscible flue-gas injection project and that the project beginning date within the meaning of section 4493(d)(2) was September 1980.

To reflect the foregoing,

Decision will be entered under Rule 155 in docket No. 35928-85.

An appropriate order will be issued in docket No. 6712-86.

1 Petitioner Natomas North America, Inc., filed a motion for leave to amend petition which the Court granted. Respondent had no objection to our granting of this motion. In its amendment to petition, petitioner states that the notice of deficiency set forth numerous other adjustments which have been agreed to. However, no refund of windfall profit tax has been made for the taxable year 1981 based upon the agreed adjustments. Petitioner states that if it prevails in this case it will be entitled to a refund of windfall profit tax in the amount of $248,807.08 for the taxable year 1981.

2 Unless otherwise indicated, all section references are to the Internal Revenue Code of 1954 as amended and in effect for the relevant taxable periods.

3 The case of Samedan Oil Corp. was consolidated for purposes of trial, briefing, and opinion with respect to these issues only.

4 A term used to denominate the joint operation of ail or some portion of a producing reservoir. Unitization is important where there is separate ownership of portions of the rights in a common producing pool in order that it may be made economically feasible to engage in cycling, pressure maintenance, or secondary recovery operations, and to explore for minerals at considerable depth. 8 H. Williams & C. Myers, Oil and Gas Law 938 (1984).

5 Taxable crude oil is defined as all domestic crude oil other than exempt oil. Sec. 4991(a). Exempt oil includes crude oil from a qualified governmental interest or a charitable interest, exempt Indian oil, exempt Alaskan oil, and exempt front-end oil. Sec. 4991(b). Sec. 4991(b) was amended by secs. 601(b)(1) and 603(a) of the Economic Recovery Tax Act of 1981, Pub. L. 97-34, 95 Stat. 336, 338, to provide that with respect to oil removed after Dec. 31, 1981, exempt oil includes exempt royalty oil and with respect to oil removed after Dec. 31, 1982, exempt oil includes exempt stripper well oil. These exemptions are defined in sec. 4994.

6 A qualified tertiary recovery project is also defined in sec. 4993(c)(1)(A) as a qualified tertiary enhanced recovery project with respect to which a certification as such has been approved and is in effect under the June 1979 energy regulations. Sec. 212.78 of the June 1979 energy regulations provided that incremental production from a property resulting from the implementation or expansion of a qualified tertiary enhanced recovery project was exempt from price controls. A qualified tertiary enhanced recovery project was a project for the enhanced recovery of crude oil to the extent it involved the application of one or more of several specified chemical, fluid, or gaseous techniques, and was certified by the Department of Energy as being uneconomical at the otherwise applicable ceiling rates. 43 Fed. Reg. 33689 (Aug. 1, 1978). On Jan. 28, 1981, President Reagan, by Executive Order 12287, exempted all crude oil and refined petroleum products from the price and allocation regulations adopted pursuant to the Emergency Petroleum Allocation Act of 1973, Pub. L. 93-159, 87 Stat. 627, as amended. 46 Fed. Reg. 9909 (Jan. 30, 1981). The Secretary of Energy was directed to take action promptly to revoke the price and allocation regulations made unnecessary by the Executive Order. Consequently, the provisions of this regulation were revoked. 46 Fed. Reg. 20508 (Apr. 3, 1981).

7 Tertiary recovery method is defined in sec. 4993(d)(1) as any method which is described in subpars. (1) through (9) of sec. 212.78(c) of the June 1979 energy regulations or any other method to provide tertiary enhanced recovery which is approved by the Secretary. The parties have stipulated that miscible flue gas injection is one of the methods described in subpars. (1) through (9) of sec. 212.78(c) of the June 1979 energy regulations. 43 Fed. Reg. 33689 (Aug. 1, 1978).

8 The parties have stipulated that the operator filed a self-certification with the Internal Revenue Service that satisfied the requirements of sec. 4993(c)(2)(D).

9 This requirement for continuing certification is not applicable since such certification is not required to be filed until 60 days after final regulations on this subject are published. Sec. 51.4993-l(e)(6), Proposed Excise Tax Regs., 49 Fed. Reg. 35521 (Sept. 10, 1984).

10 Sec. 4993(d)(4) provides:

(4) Significant expansion treated as separate project — A significant expansion of any project shall be treated as a separate project.

11 Sec. 51.4993-l(f), Proposed Excise Tax Regs., 49 Fed. Reg. 35521 (Sept. 10, 1984), defines significant expansion as'follows:

(f) Significant expansion of tertiary projects — (1) In general A significant expansion of a tertiary project shall be treated as a separate project (i.e., a new project in the case of a project that was significantly curtailed before June 1, 1979). To qualify as a qualified tertiary recovery project, the expansion must satisfy the requirements of paragraph (c)(2) of this section independently of the original project.

(2) Methods of significantly expanding a project. A project is significantly expanded by undertaking tertiary activities to recover crude oil from an area not substantially affected by the project’s previous tertiary activities, or in the case of a project that was begun before June 1, 1979 and significantly curtailed before January 1, 1980, by increasing the level of tertiary activities to at least the highest level of tertiary activities prior to the curtailment period. For purposes of this paragraph, the determination of what was the highest level of tertiary activities or whether a project has been significantly curtailed shall be made on a case-by-case basis and in light of all the facts and circumstances.

Example. In 1982 X Corporation initiated an enhanced recovery project to be conducted in three phases on a 20,000-acre property. The tertiary activities conducted on the property during that year were expected to affect only 2,000 acres. During phase II of the project which is expected to begin in 1984, X Corporation plans to drill additional injection wells and to inject injectants to increase recovery of crude oil from only one-half of the remaining 18,000 acres. During phase III, which is expected to begin in 1986, X Corporation plans to drill additional injection wells and to inject injectants to recover oil from only the remaining 9,000 acres. Since the portions of the property affected during phases II and III were not affected by the initial tertiary activities on the property, phases II and III will be treated as substantial expansions of an existing project in 1984 and 1986, respectively, and each will be treated as a separate project beginning in those years.

Proposed regulations are not entitled to judicial deference. North Ridge Country Club v. Commissioner, 89 T.C. 563 (1987), on appeal (9th Cir., Jan. 29, 1988); Scott v. Commissioner, 84 T.C. 683, 690 (1985). Proposed regulations “carry no more weight than a position advanced on brief by the respondent.” F.W. Woolworth Co. v. Commissioner, 54 T.C. 1233, 1265-1266 (1970). The parties have not argued that sec. 51.4993-1(f), Proposed Excise Tax Regs., is applicable.

12 See note 6 supra.

13 Sec. 150.4993-l(c), Temporary Excise Tax Regs., 45 Fed. Reg. 23389 (Apr. 4, 1980), defines project beginning date as follows:

The “project beginning date” is the later of—

(1) The date on which the injection of liquids, gases, or other matter begins, or

(2) The date on which—

(i) The project is certified as a qualified tertiary enhanced recovery project under the June 1979 energy regulations, or

(ii) All of the requirements of sec. 150.4993-2 are met with respect to the submission of a petroleum engineer’s certification, or all of the requirements of sec. 150.4993-3 are met with respect to the submission of a certification of jurisdictional agency approval. * * *

14 This is the same certification filed pursuant to sec. 4993(c)(2)(D).