William J. Thomson, II and Randall B. Reed, of Dray, Thomson & Dykeman, P.C., for the Petitioner Chevron U.S.A., Inc. (Chevron).

Robert Swiech and Nicole Crighton, of Oreck, Bradley, Crighton, Adams & Chase, for Petitioner BP America Production Company (BP).

Karl D. Anderson and Martin L. Hardscog, of the Wyoming Attorney General’s Office, for the Department of Revenue (Department).

In the late spring of 2002, BP, RME, and Chevron (the “Petitioners” or “taxypayers”) filed annual reports related to their 2001 gas production processed through the Whitney Canyon gas processing plant. The Department prepared Notices of Valuation for that production, and all three taxpayers filed timely appeals of the Notices of Valuation received pursuant to Wyo. Stat. Ann. §39-14-209(b). The Board may hear objections to the Department’s determination of the fair market value of natural gas production, and accordingly has jurisdiction to consider these appeals. The Board heard the case on March 8-11 and 15, 2004.

This case renews Petitioners’ dispute with the Department of Revenue regarding the Department’s use of the statutory comparable value method. The Department used that method to determine the fair market value of natural gas processed at the Whitney Canyon gas processing plant during production year 2001. In litigation regarding the preceding production year, 2000, this Board affirmed the Department’s selection and application of the comparable value method. Union Pacific Resources Company et al, Docket No. 2000-147 et al., June 9, 2003, 2003 WL 21774603 (Wyo. St. Bd. Eq.)(hereafter Whitney Canyon 2000). In this proceeding, after presentation of more extensive evidence than for production year 2000, the Petitioners urge us to reconsider the findings and conclusions we reached in Whitney Canyon 2000. The Petitioners’ statutory and constitutional claims are similar to, and in some instances the same as, the claims they made for production year 2000.

The Petitioners reported taxable value for 2001 using a variant of the proportionate profits method, and contend the Department should have accepted the reported value. The method selected by the Department yielded a uniform deduction from gross sales value of 25% of the value of gas processed for each Petitioner. The method favored by the Petitioners yielded varying deductions, even for the same gas from the same well. For example, in the Amoco-Chevron-Gulf WI Unit, BP claimed a deduction of 55.1% of the value of gas processed by the Whitney Canyon plant; RME claimed a deduction of 67.52%; and Chevron claimed a deduction of 32.94%. Comparing the results of the different methods used by the Department and Petitioners, the combined difference in taxable value for the three taxpayers is $44,457,285.

We affirm the Department’s determination of value. The Petitioners failed to show either that the Department’s valuation was not in accordance with the constitutional and statutory requirements for valuing state-assessed property, or to show that the Department’s valuation was contrary to its rules, regulations, orders or instructions.

The Board’s procedures afford the parties several opportunities to document and refine the issues they would have us adjudicate. In this proceeding, these opportunities occurred at least in the original notice of appeal; in formal statements of contentions; in a prehearing listing of issues of fact and law submitted with an index of hearing exhibits; and in proposed findings of fact and conclusions of law submitted to the Board after the transcript of the hearing was prepared. One difficulty the Board encountered in this case was attributable to a large number of issues inconsistently stated over time.

As their final summary of issues prior to the hearing, the Petitioners stated these principal contentions for our consideration:

To establish comparable value, the Department relied upon contracts that do not meet the requirements of Wyo. Stat. Ann. §39-14-203(b)(vi)(B).

The proportionate profits method was authorized by law, determined fair market value, and has been confirmed on audit.

The Petitioners cannot use the statutory netback method of valuation because they own the Whitney Canyon plant, and therefore process their own production.

The comparable value method used by the Department does not accurately reflect the fair market value of Petitioner’s gas production stream, because:

B. The Department failed to follow standard appraisal techniques when it determined the fair market value of Petitioners’ production.

C. The comparable value processing contracts selected by the Department do not meet statutory requirements.

D. Concepts of judicial estoppel and res judicata prevent a decision in this matter different from one previously reached by the Wyoming Supreme Court.

Petitioners supported these principal points with numerous, more detailed propositions. Specifically, the contention that the Department’s comparable value method did not accurately reflect fair market value was supported by twenty-four propositions of fact and/or law. In a pleading filed simultaneously, Petitioners identified fifteen contested issues of fact and twenty-three contested issues of law. [Petitioners’ Joint Issues of Fact and Law and Exhibit Index].

Many issues were restated, and some new issues added, in Petitioners’ proposed findings of fact and conclusions of law. For example, the Petitioners originally contended that, “[t]he 25% in-kind charge is not intended to represent all costs plus a return on investment.” [Petitioners’ Joint Updated Summary of Contentions, item C.8]. This was amended to an argument that the Board find “[t]he 25 percent fee does not cover actual costs.” [Taxpayers’ Revised Proposed Findings of Fact and Conclusions of Law, pp. 18-19]. The modifications in pleadings left us in doubt about whether Petitioners maintained all of their theories after the close of evidence. In the detail of Petitioners’ contentions we read two collateral estoppel theories, although a simultaneous listing of issues of law referred to collateral estoppel and judicial estoppel. [Petitioners’ Contentions, items D.1. and D.2.; Petitioners’ Joint Issues of Law, item 18.] In their proposed findings and conclusions, Petitioners did not refer to either theory.

A. The Department’s objective in valuing minerals for taxation purposes is to determine the fair market value of the mineral.

B. The proportionate profits method, using the direct cost ratio the taxpayers have used (which excludes production taxes and royalties from direct production costs), does not render full value of the minerals.

C. The Department’s rejection of the proportionate profits method, and selection of the comparable value method for valuation, was reasonable, appropriate and consistent with Wyoming law.

D. The Board affirmed the Department’s use of the comparable value method for the 2000 production year for Whitney Canyon production.

E. Although Petitioners claim that use of a comparable is impossible, some of the Petitioners have in the past reported taxable value using comparable values for various gas productions.

F. The Department had sufficient information and documentation to apply the comparable value method using a 25% processing deduction as the comparable fee for the 2001 production year.

G. The use of the selected 25% comparable processing deduction yields an accurate reflection of the fair market value of Petitioners’ gas for the 2001 production year.

Whether the Department properly and correctly applied the Comparable Value method of valuation, as set forth in Wyo. Stat. §39-14-203(b)(vi)(B), to value the oil and gas produced by BP America Production Company, Chevron USA Inc. and RME Petroleum Corp. for Production Year 2001?

In its proposed findings and conclusions, the Department further described its contentions:

A. As to each of the plant owners, the other owners are “other parties” within the meaning of the statute.

B. The 25% fee processing established by the Construction and Operation agreement is a reasonable processing fee and the maximum fee ever charged by the plant for processing, regardless of quantity or quality of gas or terms and conditions.

C. The proportionate profits method does not produce a representative fair market value for the Petitioners’ products processed at the Whitney Canyon plant.

[Wyoming Department of Revenue’s Proposed Findings of Fact and Conclusions of Law, pp. 4-5].

After much study of the pleadings on file, we have grouped the subject matter of the parties’ contentions into seven issues of fact and four issues of law that embrace all of the contentions raised by the parties.

Did the Department have a reasoned basis for determining the value of Petitioners’ production?

Does a processing fee of 25% enable the Whitney Canyon plant owners to recover their actual processing costs?

Did the Petitioners demonstrate that the Department improperly applied the comparable value method by its selection of sources of comparable value?

Did the Petitioners demonstrate that the Department erred by not applying general appraisal principles when determining the value of Petitioners’ production using the comparable value method?

Did the Petitioners demonstrate that the values determined by the Department did not reach fair market value?

Did the Petitioners demonstrate that the Department violated prescribed procedures when determining the value of each Petitioner’s gas production?

Did the Petitioners demonstrate that there were taxpayers similarly situated to themselves who were allowed to report taxable value using the proportionate profits method?

Did the Department correctly apply the comparable value method to determine the value of each Petitioner’s production?

Did the Department violate prescribed requirements by the procedures it used to determine each Petitioner’s production?

Was the Department barred from use of the comparable value method by collateral estoppel or judicial estoppel?

1. The Whitney Canyon plant processes sour gas, i.e., natural gas with relatively high concentrations of hydrogen sulfide and carbon dioxide. [Bidwell Direct, Questions 12-19; see Wyo. Stat. Ann. §39-14-201(a)(xxv)]. In production year 2001, the Whitney Canyon plant processed natural gas for producers BP America, RME Petroleum, Chevron U.S.A., Forest Oil, Merit Energy, and Anschutz Corporation. [Miller Direct, Question 19].

2. In production year 2001, BP America Production Company, Anadarko Petroleum Company, ChevronTexaco, Inc., and Forest Oil Corporation were the owners of the Whitney Canyon plant. [Miller Direct, Question 101]. Forest is not a party to this appeal. [Board Record].

3. Some brief points about the identity of predecessors and affiliates of the parties are necessary to provide context for the testimony on which the Board will rely. BP acquired Amoco in 1999. ChevronTexaco acquired Gulf in 1985. Anadarko acquired its ownership from Union Pacific Resources Company in 2000. Forest Oil acquired the interest of Forcenergy Exploration in 2000, and Forcenergy acquired the interests of Apache in 1992. [Miller Direct, Question 113]. Anadarko established RME Petroleum, a holding company, to hold certain assets of Union Pacific Resources Company during a transition period. [Miller Direct, Question 114].

4. Each plant owner was a successor in interest under an agreement for the joint Construction, Ownership and Operation of the Whitney Canyon Gas Processing Plant, Uinta County, Wyoming (“the C&O Agreement”), dated March 3, 1980. [Miller Direct, Question 16; Exhibit 920]. No witness in our proceeding participated directly in the negotiations leading up to the execution of this Agreement. [E.g., Miller Direct, Question 4; Leo Direct, Question 6]. We find the contract itself to be the best expression of the intent of the parties.

5. According to the C&O Agreement, “[t]he Owners hereto recognize that this Agreement creates a partnership for tax purposes.” [Exhibit 920, Section 16.4 and Exh. G].

6. By executing the C&O Agreement, the parties to the C&O Agreement simultaneously executed a Gas Processing Agreement attached to the C&O Agreement as Exhibit F. Under the Gas Processing Agreement, each party to the C&O Agreement is identified both individually as a Producer, and collectively as the Owners of the Gas Processing Plant. [Exhibit 920, Section 23.1, Exh. F; see also Section 1(d) of Exhibit 920].

7. The Exhibit F Gas Processing Agreement obliges each Producer to pay, to the plant Owner[s], an in-kind processing fee of 25% of the plant production attributable to that Producer. [Exhibit 920, Exh. F, Section 12.1].

8. The Owners are responsible for all operating costs of the Gas Processing Plant. [Exhibit 920, Exh. F, Section 12.2].

9. The Gas Processing Agreement recites that the compensation percentage in the in-kind fee “can be readjusted to provide a discounted cash flow rate of return of 25% after Federal Income Taxes” if the anticipated capital investment of slightly less than $340 million is exceeded. [Exhibit 920, Exh. F, Section 12.3]. According to the plant operator, BP, the original intent of the 25% fee was to cover operating costs, depreciation, and return on investment. [Miller Direct, Questions 134-135; Transcript Vol. II, pp. 229-230]. Up to the time of the hearing in this matter in 2004, the 25% in-kind fee adopted in 1980 has never been altered. [Bolles Direct, p. 33].

10. The 25% in-kind fee paid for processing is distributed to the plant owners based upon each company’s interest in the Gas Plant. [Exhibit 920, Section 12.1]; infra, ¶90. The fee is extracted from each producer’s share of volumes coming into the plant and accounted for daily, and totaled on a monthly basis. The plant owners receive this monthly statement of volumes which they individually take in kind and separately dispose of. [Syring Direct, Question 16].

11. The C&O Agreement required that all processing for third parties was to be under agreements similar to those of the C&O Agreement parties, but without any right to take plant products in kind. [Exhibit 920, Section 23.1].

12. In 2001, the plant processed gas for Merit Energy pursuant to a Gas Processing Agreement dated March 1, 1994, between Texaco Exploration and Production Company and the owners of the processing plant (“the Merit Agreement”). [Exhibit 928]. The Merit Agreement provides for a 25% in-kind processing fee for gas, but the plant owners take 100% of Merit’s sulfur. [Exhibit 928, Section 12.1(c)].

13. In 2001, the plant processed Chevron gas that was produced from interests held by Chevron before it acquired the C&O Agreement interest of Gulf Oil Corporation in 1985. The Plant processed that gas pursuant to a Gas Processing Agreement dated April 1, 1995, between Chevron U. S. A, Inc., and the plant owners. [Exhibit 963; Miller Direct, Questions 155, 156]. This 1995 Chevron Agreement (sometimes called the Chevron/Chevron Agreement to distinguish it from interests acquired through Gulf in 1985) provides for a maximum 25% in-kind processing fee. [Exhibit 963, Section 12.1, Attachment 1]. Chevron paid the 25% fee on all gas processed under this Agreement in 2001. [Miller Direct, Question 168]. Chevron used the same fee in its reporting to the Department. [Chevron Confidential Exhibit 204].

14. In 2001, the plant processed gas for the Anschutz Corporation that was produced from locations outside the Whitney Canyon field, and delivered to the Gas Processing Plant through the Wahsatch Gathering System. The plant processed the Wahsatch Gathering System gas pursuant to a Gas Processing Agreement completed June 22, 1994, originally between Union Pacific Resources Company (UPRC) and the plant owners. [Exhibit 924]. Anschutz acquired the Wahsatch Gathering System properties from UPRC in September 1999. [Transcript Vol. II, pp. 193, 208]. One witness placed the sale in late 2000. [Miller Direct, Question 36].

15. The Wahsatch Gathering System Processing Agreement provided an up-front fee benefit to offset the risks associated with its development, in the form of a threshold limit that was reached in May 1999. [Miller Direct, Questions 42, 45]. The Agreement thereafter included a fee schedule with a sliding scale to encourage development. [Miller Direct, Question 42]. Early in 2001, the processing fee was at 16.69%, but the processing fee rose throughout the year to the maximum of 25% as volumes declined. [Miller Direct, Question 44]. In their Proposed Findings of Fact, Taxpayers ask us to find that the fee for 2001 was 25%. [Taxpayers’ Revised Proposed Findings of Fact, ¶63]. We accept that request in the absence of other detail about the fee actually charged, and for the sake of simplifying our analysis of whether the plant owners’ processing fee covers the costs they incurred to operate the plant. Infra, ¶¶92-96.

16. In 2001, the Whitney Canyon plant performed a turnaround, or shutdown of the facility for maintenance, de-bottlenecking, and capital projects. [Bidwell Direct, Question 49]. For two weeks, Whitney Canyon sent Chevron’s Carter Creek gas processing plant about 30 million standard cubic feet a day for processing. [Transcript Vol. I, p. 65]. That gas was processed pursuant a letter agreement of March 17, 1993, by which the plant operator of the Whitney Canyon Gas Processing Plant agreed with the plant operator of the Carter Creek Gas Processing Plant to provide mutual back-up gas processing services. [Exhibit 927].

17. The Whitney Canyon plant commingled the gas of all producers during processing, although the Wahsatch Gathering System gas joined the plant process stream at a different point than Whitney Canyon field gas. [Bidwell Direct, Questions 19, 39]. The products of commingled gas were sold from the tailgate of the plant. [Bidwell Direct, Question 19].

18. In 2001, the Whitney Canyon plant processed 145 to 150 million standard cubic feet a day of gas from the Whitney Canyon field, and from 23.7 to 30.7 million standard cubic feet a day of gas from the Wahsatch Gathering System. [Transcript Vol II, pp. 192, 207-208; Exhibit 931, p. 2; Bidwell Direct, Questions 11, 36, 56 (10 to 15 million standard cubic feet a day for Wahsatch); we find Miller to be more credible than his co-employee Bidwell on this point, based on his knowledge of the plant’s business affairs – see Bidwell at Transcript Vol. I, p. 98]. The initial design capacity of the plant was 250 million standard cubic feet a day, but with the current hydrogen sulfide composition of produced gas, the plant could handle only 210 to 215 million standard cubic feet a day of gas. [Bidwell Direct, Question 26]. The aggregate daily volume of all producers was therefore less than the plant’s daily capacity, and the plant had substantial excess capacity in 2001. [Transcript Vol. I, pp. 88, 99-101].

19. On August 31, 1999, the Administrator of the Department’s Mineral Tax Division issued a Memorandum to all Wyoming oil and gas producers. The Administrator notified these producers that the Department elected the Comparable Value Method of valuation for production years 2000, 2001, and 2002, where oil and gas production, like that of Petitioners, was not sold at or prior to the statutory point of valuation. [Exhibit 900]. By this Memorandum, the Department satisfied its obligation to notify taxpayers of the selected method as required by Wyo. Stat. Ann. §39-14-203(b)(vi). The Memorandum recited the statutory definition of the Comparable Value Method:

Comparable Value – The fair cash market value is the arms-length sales price less processing and transportation fees charged to other parties for minerals of like quantity, taking into consideration the quality, terms and conditions under which the minerals are being processed or transported.

20. The Memorandum obliged the taxpayer to notify the Department if the “taxpayer has made a determination that a representative Comparable Value does not exist for a specific mineral property....” [Exhibit 900].

21. Within the next thirty days, all three Petitioners either denied the existence of comparable values, or that the comparable value method accurately reflected fair cash market value. Each requested use of the proportionate profits method. [Exhibits 901, 902, 903].

22. On November 16, 1999, the Administrator sent each Petitioner a letter broadly seeking specific documentation “to verify your claim of the non-existence of a comparable value and /or your believe [sic] that comparable value does not represent fair market value.” [Exhibits 904, 905, 906, 907].

23. During November and December, 1999, the Petitioners identified only the C&O Agreement, the Wahsatch Gathering System Agreement, and an agreement for short-term processing during Whitney Canyon turnarounds. [Exhibits 908, 909].

24. By letters dated February 4, 2000, the Department informed each taxpayer that it had reviewed the agreements provided, and reiterated the requirement that the taxpayer determine taxable value using the Comparable Value Method. [Exhibits 910, 911, 912].

25. In response to letters from Chevron and BP, the Department identified the Gas Processing Agreement that was Exhibit F to the C&O Agreement and identified the Wahsatch Gathering System Agreement as sources of comparable value. [Exhibits 913, 914, 915, 916]. In late March of 2000, the Administrator stated that:

The fact that the processing fee in Yellow Creek [Wahsatch] can never exceed twenty-five percent (25%) is certainly comparable to the Whitney Canyon C&O agreement and, in fact, is the exact processing fee that is being reported by one of the Whitney Canyon Plant owners for severance and ad valorem tax purposes. Hence, the DOR will not allow a processing fee of more than 25% for Whitney Canyon production....

[Exhibits 115, 116]. We find that the Department unequivocally communicated its position nearly a year before annual reports for production year 2000 were due from the taxpayers, Wyo. Stat. Ann. §39-14-207(a)(i), and some two years before reports for production year 2001 were due. Any lingering doubt about the Department’s view was dispelled during the litigation concerning production year 2000. Whitney Canyon 2000.

26. The Petitioners claim that they could not report using the comparable value method because, in the absence of formal rulemaking, the Department’s policy direction was unclear. [E.g., Syring Direct, Questions 27-38, 72; Chambers Direct, Questions 80-82]. They suggest they have been at liberty to interpret the comparable value method according to an understanding of their own, without regard to whether that understanding is consistent with the policies of the Department. [E.g., Corrected Ostroff Direct, p. 4]. Chevron goes further, and asserts that the Department was obliged to “demonstrate to Chevron that [the Department’s] interpretation [of the comparable value statute] was incorrect.” [Chambers Rebuttal, Question 2]. We find that by the spring of 2002, when Petitioners filed their annual reports for production year 2001 [Grenvik Direct, pp. 2-3], the Department’s policy was clear. Chevron and BP acknowledge that they had no trouble understanding what reporting the Department anticipated, and were opposed to the Department’s position. [Transcript Vol. II, pp. 358-359, Vol. III, pp. 475-476]. None of the claims that the Department’s position was unclear are credible.

27. BP asserted that further Departmental guidance was necessary so the taxpayers could adjust the 25% processing fee. [E.g., Syring Direct, Question 38]. This position assumes that adjustments were appropriate. Such testimony is not credible. Petitioners were simply unwilling to accept the Department’s direction with regard to the comparable value method. Any interest in modifying the 25% processing fee was merely an expression of disagreement with Department policy.

28. The Department never adopted rules to further define the comparable value method. [Bolles Direct, p. 51]. The Department believed the statute was clear. [Bolles Direct, pp. 22-25, 51]. The Department also believed that it would be difficult to identify uniform criteria for all situations, so that any rules could only provide general guidelines that would not be much more definitive than the statute. [Bolles Direct, pp. 25, 51]. We accept the Department’s testimony as reasonable. The Petitioners never availed themselves of their right to petition the Department to promulgate rules that would further define the comparable value method. [Bolles Direct, p. 50].

29. When the Petitioners filed their annual reports for production year 2001, they disregarded the Department’s repeated directive to use the comparable value method. [Corrected Ostroff Direct, p. 4; Syring Direct, Question 100; Chambers Direct, Question 28; Grenvik Direct, p. 4]. Instead, the Petitioners generally reported using their own variation of the proportionate profits method; they did not treat production taxes and royalties as direct costs of production, contrary to a series of rulings by this Board dating from 2001. Appeal of Amoco Production Company, June 29, 2001, 2001 WL 770800 (Wyo. St. Bd. Eq.); on reconsideration, September 24, 2001, 2001 WL 1150220, reversed on other grounds, Amoco Production Company v. Department of Revenue et al, 2004 WY 89, 94 P.3d 430 (2004). [Bolles Direct, p. 53]; infra, ¶276. The Petitioners’ variation of the proportionate profits method reduced the taxable value of Petitioners’ production. [Bolles Direct, p. 53].

30. Chevron reported part of its 2001 production using the netback method. [Transcript Vol. III, pp. 457-459]. Chevron did not consider gas produced under the 1995 Chevron Agreement to be producer-processor gas, that is, gas for which Chevron was both a producer and a processor. [Transcript Vol. III, p. 457]. In its reporting, Chevron reported a processing deduction of 25%, without requiring guidance from the Department. [Confidential Chevron Exhibit 204; Transcript Vol. III, pp. 486-487]. For four Mineral Groups, Chevron reported a single taxable value which was the sum of the results of two different valuation methods. [Confidential Chevron Exhibit 204, p. 2].

31. Chevron did not advise the Department that it had reported some production using the netback method. [Transcript Vol. III, p. 486]. Instead, Chevron asserted that the Department should have inferred netback reporting because Chevron had reported production from the same interests on a netback basis since before 1990. [Transcript Vol. III, p. 487].

32. Generally speaking, a taxpayer’s annual ad valorem reports do not disclose what valuation method the taxpayer actually uses to calculate its processing deduction. [Transcript Vol. IV, p. 837]. The Department learned of Petitioners’ unauthorized selection of valuation method when it compared the amount of reported processing deductions with reported gross sales value. The processing deductions did not equal 25% for any Mineral Group. [Grenvik Direct, p. 4; see Confidential Exhibits 504, 506, 508]. Since the correct processing deduction using the comparable value method for Whitney Canyon production was 25%, the Department concluded that none of the three taxpayers reported using the comparable value method. [Grenvik Direct, p. 4].

33. The Department responded to the Petitioners’ annual reports by preparing a Notice of Valuation for each taxpayer. [Exhibits 500, 501, 502]. A Notice of Valuation states the Department’s determination of the value of production from each Mineral Group, but does not restate confidential information from a taxpayer’s annual reports. [Exhibits 500, 501, 502].

34. The Department adjusted the processing deduction for all Whitney Canyon Mineral Groups by applying a 25% processing deduction against the reported Gross Sales Value of Plant Products, and recalculating Taxable Value using the 25% processing deduction. [Bolles Direct, p. 51; Grenvik Direct, p. 4]. The Taxable Value of each Notice of Valuation reflected this adjustment for all natural gas that the Whitney Canyon plant processed for the Petitioners. [Exhibits 500, 501, 502].

35. Forest Oil, the fourth owner of the Whitney Canyon plant, reported a processing fee of approximately 18% for production year 2001. [Bolles Direct, p. 48]. The Department assumes that Forest Oil reported under the comparable value method. [Bolles Direct, p. 49]. The record does not disclose how Forest Oil calculated its processing fee.

36. No taxpayer has appealed the Department’s mathematical calculations of the comparable value processing allowance or the taxable value that results from those calculations.

Did the Department have a reasoned basis for determining the value of Petitioners’ production?

37. The Department concluded that the words “of like quantity,” as they appear in the statutory definition of the comparable value method, were clear and were satisfied by the Department’s application of the comparable value method. [Bolles Direct, pp. 22-23]. In principal part, the Department observed that all contracts (except the Mutual Back-up Agreement) charged the same maximum 25% processing fee. [Bolles Direct, pp. 22-23].

The Wahsatch Gathering System Processing Agreement and the 1995 Chevron Agreement require a maximum processing fee of 25%, with a reduced fee for lower volumes. [Exhibits 924, 963]. Further, the contracts that are Exhibit F to the C&O Agreement and the Merit Agreement attributed no significance to quantity of gas that was processed. [Exhibits 920, 928].

38. The Department concluded that the word “quality,” as it appears in the statutory definition of the comparable value method, was satisfied by the Department’s application of the comparable value method. Specifically, the Department concluded that:

a. The contracts did not expressly address gas quality as a factor affecting the processing fee;

c. The quality was comparable because all gas was processed without requiring changes to the plant’s processing functions;

d. All of the gas produced of any producer was commingled and became a unified product.

39. The Department concluded that the words “terms and conditions,” as they appear in the statutory definition of the comparable value method, were satisfied by the Department’s application of the comparable value method to all processing contracts that charged producers a maximum processing fee of 25%. Further, the Department concluded that:

a. The terms and conditions were identical or almost identical in Exhibit F to the C&O Agreement, the Merit Agreement, the Wahsatch Agreement, and the 1995 Chevron Agreement;

b. Regardless of the differences in terms and conditions, the processing fee never exceeded 25%.

40. The Department concluded that the statutory definition of the comparable value method did not require a processing fee charged to other parties to be arms-length, and that the words “arms-length” only modified the words “sales price.” The Department further concluded that each of the contracts included a processing fee derived from an arms-length agreement. [Bolles Direct, pp. 21-22, 27-29, 38-39, 41-43, 47-48].

41. The Department concluded that Exhibit F to the C&O Agreement, under which Petitioners paid the plant owners a processing fee of 25% of the gas product, was a comparable value which the Department could use to determine the processing deduction for valuing a producer’s production. Specifically, the Department concluded that:

a. The Petitioners negotiated the C&O Agreement in an arms-length manner because the Petitioners acted in their own interest, were not controlled by each other, and were currently competitors. [Exhibit 920; Bolles Direct, pp. 27-29; Bolles Rebuttal, pp. 1-2].

b. The 25% processing fee paid by BP, Chevron, RME, and Forest Oil individually to the plant owners jointly was, for each individual company, a fee charged by the plant owners to an other party within the meaning of the statutory definition of comparable value. [Bolles Direct, p. 26].

c. The 25% processing fee that the plant owners received was intended to cover plant operating costs and depreciation, and to provide a return on investment to the plant owners. [Exhibit 920, pp. WC 89, WC 124-125; Miller Direct, Questions 135-136].

d. Prior to 1988, Amoco (BP’s predecessor) affirmatively asserted that the 25% processing fee was the actual fee paid to process Whitney Canyon field gas, and that the Department should accept the fee for the purpose of determining a processing deduction. [Exhibits 524, 525; Bolles Direct, pp. 32-36; Transcript Vol. IV, pp. 803-810].

f. The 25% processing fee that the plant owners charged to process each Petitioner’s gas was also imposed on all other producers under the C&O Agreement, and no producer paid a fee greater than 25% during production year 2001. [Exhibit 920; Bolles Direct, pp. 21-49; Transcript Vol. IV, pp. 818-819].

g. On a per mcf basis, the Petitioners never paid more than a 25% processing fee regardless of quantity differences or any other circumstances. [Bolles Direct, pp. 37, 43].

h. All gas that the plant processed was of similar chemical quality and was commingled at the inlet of the plant. The C&O Agreement did not require a different processing fee to account for any differences in quality of gas. [Exhibit 920; Bolles Direct, pp. 31-32, 37; Bidwell Direct, Question 19].

i. The Exhibit F contractual terms and conditions were the same for all producers, and the processing fee never exceeded 25%. [Exhibit 920; Bolles Direct, pp. 24-37].

j. Petitioners were contractually able to modify the processing fee, but over two decades have not done so. [Exhibits 524, 525, 920; Bolles Direct, pp. 33-37; Transcript Vol. I, pp. 170-171].

42. The Department concluded the Wahsatch Gathering System Processing Agreement, under which Anschutz Corporation paid the plant owners a processing fee of 25% of the gas product during production year 2001, was a comparable value which the Department could use to determine the processing deduction for valuing a producer’s production. Specifically, the Department concluded that:

a. The plant owners and Union Pacific Resources Company, as a third priority producer, negotiated the C&O Agreement in an arms-length manner with Amoco and resolved outstanding areas of difficulty. Specifically, UPRC as producer was motivated to pay the lowest possible processing fee, and the plant owners without interest in the Yellow Creek gas (a majority) were motivated and would receive benefit from receiving the highest possible processing fee. UPRC assigned its interest in the Wahsatch Gathering System Agreement to Anschutz before production year 2001. Anschutz was not a Whitney Canyon plant owner. [Exhibit 924; Transcript Vol. II, pp. 212-214; Miller Direct, Questions 36, 42-43, 49; Bolles Direct, pp. 37-41].

b. Chevron is a plant owner with no interest in the Yellow Creek gas, and benefits from receiving the highest possible processing fee from the producer of Yellow Creek gas. [Transcript Vol. II, pp. 212-214].

c. Amoco competitively negotiated with UPRC for the rights to process Yellow Creek gas at the Whitney Canyon plant. Amoco benefitted as a plant owner because it received a share of processing fees, and as a producer because the Yellow Creek gas extended the economic life of the Whitney Canyon plant. [Exhibit 924; Transcript Vol. II, pp. 212-214; Miller Direct, Questions 36, 42-43, 49].

d. The Wahsatch Gathering System Agreement provides for processing fees based on the volume of gas processed discounted to as low as 14.17% for the first 40 billion cubic feet of gas, with a maximum of 25%. [Exhibit 924].

e. The quantities of gas produced by the Petitioners and Anschutz in production year 2001 were similar, and to the extent that quantities varied, the Wahsatch Gathering System Agreement attributed no difference to the disparities insofar as the maximum processing fee was 25%. The Wahsatch Gathering System contained no quantity limitation other than the capacity of the Whitney Canyon plant. On a per mcf basis, Anschutz paid no more than a 25% fee. The Department selected this maximum contractual fee as the comparable. [Exhibit 924; Bolles Direct, pp. 38-42].

f. The quality of Wahsatch Gathering System gas was similar to other gas processed at the Whitney Canyon plant, because the gas was commingled at the inlet, no additional processing expense was required, and the processing agreement did not require fee adjustments based on quality of gas. [Bolles Direct, p. 40; Exhibit 924].

g. The terms and conditions of the Wahsatch Gathering System Processing Agreement were similar to the terms and conditions of other contracts pursuant to which the Whitney Canyon plant processed gas. No fee adjustments were required for such terms and conditions. [Exhibit 924; Bolles Direct, p. 42].

43. The Department concluded that the Merit Agreement, under which Merit paid the plant owners a processing fee of 25% of the gas product and 100% of the sulfur product, was a comparable value which the Department could use to determine the processing deduction for valuing a producer’s production. Specifically, the Department concluded that:

a. The plant owners negotiated the Merit Processing Agreement in an arms-length manner with Merit’s predecessor in interest. Merit’s predecessor was not affiliated with any of the plant owners, and the parties to the processing agreement were in a position to protect or further their competing economic interests. [Exhibits 928; Bolles Direct, pp. 42-44; Transcript Vol. II, p. 220].

b. The 25% processing fee paid by Merit to the plant owners jointly was a fee charged by the plant owners to an other party within the meaning of the statutory definition of comparable value.

d. There is a significant disparity between the processing allowance available to Merit based on the Merit Agreement, and the processing allowance claimed by BP for production from the Champlin 505B1 well. [Transcript Vol. II, pp. 216, 224-226].

e. The quality of Merit gas was similar to other gas processed at the Whitney Canyon plant. Because the gas was commingled at the inlet, no additional processing expense was required, and the processing agreement did not require fee adjustments based on quality of gas. [Bolles Direct, pp. 42-44; Exhibits 928, 954].

f. The terms and conditions of the Merit Agreement were similar to the terms and conditions of other contracts pursuant to which the Whitney Canyon plant processed gas. No fee adjustments were required for such terms and conditions. [Bolles Direct, pp. 42-44; Exhibit 928].

44. The Department concluded that the 1995 Chevron Agreement (or Chevron/Chevron Agreement), under which Chevron paid the plant owners a processing fee of 25% of the gas product, was a comparable value which the Department could use to determine the processing deduction for valuing a producer’s production. Specifically, the Department concluded that:

a. The Petitioners and Chevron, originally as a third priority producer, negotiated the 1995 Chevron Agreement in an arms-length manner. When the agreement was originally negotiated, Chevron did not own an interest in the plant, and the plant owners were motivated to receive, and would benefit by receiving, the highest possible processing fee from Chevron. The original agreement was also negotiated during a period when relations between Chevron and the plant operator, Amoco, were strained, and there was intense competition between Chevron and Amoco. In the 1995 negotiation, Chevron gained freedom to process Chevron/Chevron gas at its Carter Creek facility, and a reduction in its processing fee from 35% to 25%. Amoco gained processing simplicity. [Exhibit 928; Bolles Direct, pp. 47-49; Transcript Vol. II, pp. 222-224, 227-228, 231-234, 263-265].

b. The 25% processing fee paid by Chevron to the plant owners jointly was a fee charged by the plant owners to an other party within the meaning of the statutory definition of comparable value.

c. The quantities of gas produced by Chevron under the 1995 Chevron Agreement were similar to the quantities produced by the other Petitioners, and to the extent that quantities varied, the 1995 Chevron Agreement attributed no difference to the disparities insofar as the maximum processing fee was 25%. The 1995 Chevron Agreement contained no quantity limitation other than the capacity of the Whitney Canyon plant. On a per mcf basis, Chevron paid no more than a 25% fee. [Exhibit 963, p. 0249; Bolles Direct, pp. 47-49].

d. The quality of gas produced by Chevron under the 1995 Chevron Agreement was similar to other gas processed at the Whitney Canyon plant, because the gas was commingled at the inlet, no additional processing expense was required, and the processing agreement did not require fee adjustments based on quality of gas. [Bolles Direct, pp. 47-49; Exhibits 963, 954; Transcript Vol. II, p. 236].

f. The terms and conditions of the 1995 Chevron Agreement were similar to the terms and conditions of other contracts pursuant to which the Whitney Canyon plant processed gas. No fee adjustments were required for such terms and conditions. [Bolles Direct, pp. 44-49; Exhibit 963].

g. Chevron characterized its production under the 1995 Chevron Agreement as not being producer processed gas, and reported production under the 1995 Chevron Agreement using the netback method with a 25% processing fee deduction. Chevron paid the plant owners the 25% processing fee on all production under the 1995 Chevron Agreement. [Exhibit 963; Transcript Vol. II, pp. 233-236, 263-265].

45. The Department concluded that the Whitney Canyon/Carter Creek Mutual Back-up Agreement, under which either the Whitney Canyon plant or the Carter Creek plant could, upon 24 hours notice, send gas to the other plant for processing for a processing fee of no more than 22% of the gas product, was a comparable value which the Department could use to determine the processing deduction for valuing a producer’s production. Specifically, the Department concluded that:

b. The maximum 22% processing fee charged to each producer under the Mutual Back-up Processing Agreement was a fee charged to an other party within the meaning of the statutory definition of comparable value. Gas processed at the Carter Creek plant could be sent to the Whitney Canyon facility. [Bolles Direct, p. 45].

c. The quantities of gas produced and processed under the Mutual Back-up Processing Agreement were of like quantity, and to the extent that quantities varied, the Mutual Back-up Processing Agreement attributed no difference to the disparities insofar as the maximum processing fee was 22%. The Mutual Back-up Processing Agreement contained no quantity limitation other than the available capacity of the back-up processing plant, and no specific expiration date once continued after August 31, 1995. On a per mcf basis, producers paid no more than a 22% fee to the plant providing back-up service. [Exhibit 927; Bolles Direct, pp. 45-47].

d. The quality of gas produced under the Mutual Back-up Processing Agreement was similar to other gas processed at the Whitney Canyon plant. Gas processed through either plant was similar due to similarities in gas produced from the Whitney Canyon and Carter Creek fields. Gas processed at either plant was commingled at the plant inlet. Neither plant was obliged to modify its processing function to process the other’s gas. The processing agreement did not require fee adjustments based on quality of gas. [Bolles Direct, pp. 45-47; Exhibit 927; Transcript Vol. II, pp. 333-334].

e. The terms and conditions of the Mutual Back-up Processing Agreement were similar to the terms and conditions of other contracts pursuant to which the Whitney Canyon plant processed gas. No fee adjustments were required for such terms and conditions. [Bolles Direct, p. 46; Exhibit 927].

46. Although the Department was generally committed to the application of the comparable value method, its witnesses commented on the Department’s position with regard to whether other methods were available. The Department took the position that the taxpayers in this case are producer-processors, so they could not use the statutory netback method to report Whitney Canyon production. [Transcript Vol. IV, p. 836; see Bolles Direct, p. 6]. No data existed to apply the comparable sales method, because all sales of gas were from the tailgate of the plant. [Bolles Direct, p. 5; Bidwell Direct, Question 19].

47. The Department disfavors the proportionate profits method because in years like 2001 it returns the least amount of taxable value of the four methods. [Grenvik Direct, p. 23]. In the Department’s view, the ratio of production and processing costs only has a true bearing on the value of processed gas within a very limited range of inputs to the formula. As revenues rise, the proportionate profits method incorrectly attributes value of the gas to the processing function. [Transcript Vol. I, pp. 900-901]. The proportionate profits methodology thus tends to yield an excessive deduction, and can allow a processing deduction that may be two to four times greater than actual processing costs. [Bolles Direct, p. 8].

48. The Department also disfavors the proportionate profits method for administrative reasons. In the Department’s experience, the taxpayers in this case classify costs differently among themselves even within the same plant, and some taxpayers have aggressively pursued tax reduction by classification practices. [Bolles Direct, p. 7].

49. The Board finds that the Department had a reasoned basis for applying the comparable value method to each Petitioners’ production. However, it remains for us to consider whether all of the details of the Department’s conclusions are sound in light of the contrary views of the Petitioners, and our consideration of aspects of the record to which neither party specifically directed our attention.

50. We find the taxpayers presented no credible evidence that the Department selected the comparable value method solely and exclusively because it generates the highest taxable value. [Chambers Direct, Question 90; Bolles Rebuttal, p. 5].

Does a processing fee of 25% enable the Whitney Canyon plant owners to recover their actual processing costs?

51. The Petitioners believed that in 2001 the 25% processing fee was no longer a meaningful measure of the financial burdens borne by a plant owner. [Transcript Vol. III, pp. 451-452]. A BP witness testified that plant profitability has not been a concern since at least 1991. [Transcript Vol. II, p. 229]. Instead, BP now focuses on covering incremental costs and maximizing revenue in general. [Transcript Vol. II, p. 229]. However, this testimony contradicts the language of the C&O Agreement, supra, ¶9, and we decline to give general statements more weight than recitals in an agreement that has withstood the test of time.

52. For production year 2001, the Petitioners testified in terms that are more concrete. RME and Chevron representatives testified that the comparable value processing fee allowed by the Department did not allow a plant owner to recover its direct processing costs in 2001. According to RME, “[t]he processing fee allowed by the Department fails to allow RME to recover its direct processing costs by $1,363,574.” [Corrected Ostroff Direct, p. 13]. Chevron testified that the 25% fell millions of dollars short of recovering Chevron’s operating expenses, depreciation, and return on investment. [Chambers Direct, Questions 24-26]. BP asserted that there “is a possibility that the 25% fee would not cover all BP’s actual plant expenses given a low price environment.” [Syring Direct, Question 96].

53. If we find that the taxpayers are correct, they ask us to conclude that the Department’s chosen valuation method must at least remove actual processing costs incurred by the taxpayer in order to reach fair market value. [Taxpayers’ Proposed Findings of Fact and Conclusions of Law, ¶¶247-248]. In other words, they ask us to disallow the Department’s comparable value determination.

54. Information about plant revenues and costs came from producers paying taxes, because only producers are required to report production, processing costs, and taxable value to the Department. Infra, ¶70. The owners of a processing plant have no similar reporting obligation. So, any comparison of 2001 plant revenues and costs rests principally on the information reported by the Petitioners as producers, and supplemented by information generated specifically for the hearing of this matter.

55. The Department and the Petitioners agreed on an approach that we should employ when we compare plant revenues with plant costs. [E.g., Miller Direct, Question 135; Corrected Ostroff Direct, p. 13; Rev. Confidential Exhibit RME-6; Grenvik Direct, pp. 6-20]. The parties generally agreed that plant costs were comprised of three separate components: (1) current operating costs; (2) return of investment, in the form of depreciation for the current year; and (3) annual return on investment, expressed as percentage of capital currently invested.

56. From the Petitioners’ reporting, we found that cost components were difficult to track and accept with confidence. The processing deductions reported by the taxpayers illustrate this difficulty because the deductions diverged radically. BP’s deductions were around 55%, Chevron’s were around 36%, and RME’s ranged as high as 67.52%. Infra, ¶87. Further, the three taxpayers took these different processing deductions even for gas produced from single wells in which they shared the same gas production. Infra, ¶88. The taxpayers’ constitutional claims obliged the Board to pursue, as best it could, the source of these large differences.

57. Our comparison of plant revenues and plant costs was complicated by numerous late revisions to the evidence.

58. To carry its burden of going forward, RME relied on evidence that it had revised on the eve of the hearing. [Corrected Testimony of Ostroff, with revised Confidential Exhibits RME-1 through RME-6]. This evidence included the gross elements of RME’s proportionate profits calculation, and calculations of taxable value over a period of years using alternative valuation methods. We find that RME produced credible evidence, at least in the sense of demonstrating the basis for its belief that its plant costs exceeded plant revenues. At the same time, RME did not carry its burden of persuasion. RME only accounted for plant revenues derived from its own production, rather than all revenues. As important, RME claimed costs dramatically and inexplicably higher than the costs of BP and Chevron. [Grenvik Direct, p. 18].

59. Most of Chevron’s late-revised evidence was introduced in its rebuttal case. [Transcript Vol. V, pp. 1008-1022; Confidential Exhibit 204]. In its initial case, Chevron’s evidence was principally in the form of claims unsupported by data. [E.g., Chamber Direct, Questions 24-26]. This underlying data was significant because Chevron reported its production using two different methods. Supra, ¶¶30-31. Chevron remedied some of these shortcomings in its rebuttal case, when it presented evidence of some details of its proportionate profits and netback reporting. Chevron did not carry its burden of persuasion either through its case-in-chief or in rebuttal.

60. All three Petitioners relied on the testimony of expert Joseph Wilkinson, who concluded that the 25% processing allowance provided a 6% internal rate of return for the Whitney Canyon plant in 2001. [Wilkinson Direct, Question 15]. We found several of Wilkinson’s premises flawed. Infra, ¶238. However, aspects of Wilkinson’s approach were persuasive and helpful. Wilkinson made an effort to consider plant economics by combining costs and revenues of all owners. [Rev. Exhibit 972, attached Exh. F]. Wilkinson also explained that, for comparison purposes, it was reasonable to evaluate the economics of the plant using straight line depreciation based on a common initial investment. [Transcript Vol. II, pp. 722, 751-752, 783-785]. We find that Wilkinson’s testimony was credible evidence, at least in the sense of demonstrating the basis for the Petitioners’ belief that their plant costs exceeded plant revenues. This evidence therefore carried Petitioner’s burden of going forward. Wilkinson’s testimony did not carry Petitioners’ burden of persuasion.

61. The Department’s case had two strengths. First, the Department summarized the data the taxpayers had originally reported. [Grenvik Direct, pp. 6-7, 11-12, 16-17; Exhibits 504, 506, 508]. These summaries of the reported data enabled us to evaluate the testimony of all witnesses against a reliable foundation. The summaries also enabled us to straighten out discrepancies that arose from identification of the gas production that was subject to appeal. Infra, ¶¶84, 86.

62. Second, the Department compared plant revenue and plant cost data in a consistent format for each taxpayer. [Grenvik Direct, pp. 7-10, 12-15, 17-20]. The Department’s format tied to data from the taxpayers’ annual reports, and tied to data from the taxpayers’ proportionate profits computations. The Department’s format provided a consistent basis for comparing the revenue of each taxpayer with the three types of costs. Supra, ¶55. The Department’s witness clearly explained the source of the data used for the Department’s comparisons. [Grenvik Direct, pp. 7-10, 12-15, 17-20]. Since the format was consistent, and the format could be tied to data sources, the Department’s format provided us a platform that could be consistently adjusted as we pursued our findings.

63. The Department’s comparisons of plant revenue and plant cost data include an implied rate of return on investment for the three taxpayers. We agree that the implied rate of return is a useful focal point. Infra, ¶¶149-150. An implied rate of return shows the degree to which operating costs and depreciation were covered by the Department’s 2001 processing allowance, which the Department used as a surrogate for plant revenue. We find that the Department’s implied rate of return calculation for each taxpayer (ROI on Assessed Processing) is not confidential. The Department concluded that BP’s implied return on investment for production year 2001 was 11.89%. [Confidential Exhibit 505]. The Department concluded, with reservations, that RME’s implied rate of return was a negative 20.98%. [Confidential Exhibit 509; Grenvik Direct, p. 18]. The Department concluded that Chevron’s implied rate of return was 19.03%. [Confidential Exhibit 532].

64. We do not accept the rates of return calculated by the Department due to shortcomings of the Petitioners’ data and proportionate profits calculations upon which the Department relied.

65. The Department was hampered by the late revisions of RME and Chevron, which forced the Department to make corresponding revisions to its comparisons. The Department’s comparisons erroneously included some revenue related to wells that RME and Chevron had not placed in issue with their notices of appeal. Infra, ¶¶84, 86.

66. The Department’s collection of cost data was generally handicapped by Wyoming’s statutory reporting system. The Department receives very limited processing cost information from reporting producers. [Bolles Direct, p.4]. The Department met this handicap by seeking additional information during the appeal process, and by accepting each taxpayer’s cost information at face value. [Grenvik Direct, pp. 7, 13, 18]. We find it necessary to move beyond the Department’s permissive approach, and reject some of the cost figures that the Department was prepared to accept. We do not and cannot conduct a proportionate profits method audit, which requires access to the plant operator’s books to assure that the individual taxpayers have consistently handled plant costs. We must work with the information available to us in the record.

67. For similar reasons, the Department’s approach to estimating plant revenue was too limited. The Department estimated plant revenue to be equal to the Department’s processing allowance, that is, equal to 25% of each taxpayer’s gross sales. Although this approach simplified the Department’s calculations, it failed to accurately account for plant revenues derived from sources other than the reporting taxpayer’s own production. Specifically, we agree with the Department that RME made no adjustment to its share of plant revenues or plant costs to account for such revenue. [Transcript Vol. V, p. 914]; infra, ¶¶105-111.

68. The Board found it necessary to perform its own analysis of the testimony and of confidential information in the record. In an effort to protect the confidential information, we have frequently been obliged to explain how we viewed or manipulated information in the record, rather than disclosing the results of our calculations.

69. We began as the Department did, by reviewing the taxpayers’ annual gross product reports for revenue information. Each taxpayer filed these reports with the Department of Revenue in the spring of 2002. [Grenvik Direct, pp. 2-3].

70. The single-page annual gross product report is known as Form 4201 MTD. Each report refers to a producing asset identified by a Mineral Group number. [Confidential Exhibit BP-1]. Each report states, as part of the taxpayer’s taxable value calculation for each Mineral Group: (a) a gross sales volume of natural gas; (b) an aggregated gross sales value of plant products; (c) the value of royalty, processing, and transportation deductions; (d) a taxable value, which is the difference between gross sales value and all deductions. [Confidential Exhibit BP-1]. Every Form 4201 MTD in our record was accompanied by a separate one-page attachment, Form 4231 MTD, which stated the volumes and values of the specific products that resulted from processing. [Confidential Exhibit BP-1]. The four products of the Whitney Canyon plant were residue gas, natural gas liquids, plant condensate, and sulfur. [Confidential Exhibit BP-1].

71. As previously noted, Chevron calculated its processing deductions using two different methods, depending on the origin of its interests in the production in question. [Confidential Exhibit 204, p. 2]. We accept the distinction Chevron made between its two sets of interests, one from Gulf, and the other independently. [Confidential Exhibit 204, p. 2]. Chevron reported its Gulf interests using the proportionate profits method, and reported its interests under the 1995 Chevron Agreement using the statutory netback method. [Transcript Vol. II, pp. 457-459; Confidential Exhibit 204, p. 2]. Chevron was the only Petitioner that reported using two different processing deductions.

72. The Petitioners’ revenue and cost information was not presented in a consistent format. [Confidential Exhibit BP-2; Rev. Confidential Exhibit RME-6; Confidential Exhibit 204].

73. BP provided revenue and cost information through its confidential proportionate profits calculation. [Confidential Exhibit BP-2]. The Department accepted unaudited direct processing costs from this calculation as the source of BP’s current plant operating costs and plant depreciation. [Grenvik Direct, p. 7; Confidential Exhibits 505, 527, 529; Exhibits 510, 511, 531, 533, 534, 535]. Specifically, the Department relied upon the statement of Total Processing Costs and Depreciation that appears in the Total Processing Costs portion of BP’s proportionate profits calculation. [Confidential Exhibit BP-2].

74. RME introduced two summaries of its proportionate profits calculation as confidential exhibits. [Confidential Exhibit RME-6; Rev. Confidential Exhibit RME-6]. RME’s first summary reflected its original proportionate profits calculation, and the second summary was a revised calculation for the same purpose. [Confidential Exhibit RME-6; Rev. Confidential Exhibit RME-6; Transcript Vol. III, pp. 501-502]. RME revised its calculation to amortize costs of a plant turnaround in 2001, after originally including the expenses of the 2001 turnaround all in one year. [Transcript Vol. III, pp. 557-558].

75. RME’s rationale for amortizing the turnaround costs was that the turnaround was an extraordinary expense. [Transcript Vol. III, p. 557; Confidential Transcript Vol. V, p. 1016]. The plant turnaround window was three years, with the next turnaround planned in May 2004. [Transcript Vol. I, pp. 85-86]. However, many of the costs incurred in the turnaround were to refurbish equipment intended to last through 2008, the expected life of the plant. [Transcript Vol. I, pp. 86-87, Vol. II, p. 256]. We find that three years was the minimum reasonable time to amortize the costs.

76. RME’s original proportionate profits summary tied to its annual gross products report, and associated all turnaround costs with production year 2001. [Confidential Exhibit RME-6; Confidential Exhibit 508, column entitled “Rptd Poc %”]. When RME corrected the costs that were originally reported, RME reduced reported total processing costs by nearly twenty-eight percent. [Confidential Exhibit RME-6; Rev. Confidential Exhibit RME-6]. RME’s revision reduced the processing deduction used for its annual reports by about seven percent. [Confidential Exhibit RME-6; Rev. Confidential Exhibit RME-6].

77. RME’s representative testified that no effort was made to amend its annual report, because RME was preserving its legal rights. [Transcript Vol. III, p. 559]. We find that the processing deductions originally reported by RME to the Department were materially in error. Supra, ¶¶74-76. RME agrees. [Transcript Vol. III, p. 558].

78. The Department initially used RME’s original unaudited statement of direct processing costs as its source of RME’s current plant operating costs and plant depreciation. [Confidential Exhibit 509; Exhibit 510, 511]. The Department later revised its exhibits to reflect RME’s amortization of turnaround costs. [Confidential Exhibits 527, 530; Exhibits 531, 533, 534, 535]. In both instances, the Department relied upon RME’s statements of Total Processing Costs and the Depreciation, which were entries in the Total Processing Costs portion of RME’s proportionate profits calculation. [Confidential Exhibit RME-6; Rev. Confidential Exhibit RME-6].

79. Chevron introduced an abbreviated summary of its proportionate profits calculation in its rebuttal case. [Confidential Exhibit 204]. This summary includes a statement of Total Processing Costs, or combined operating costs and depreciation. [Confidential Exhibit 204]. Chevron separately provided the Department a statement of the depreciation included in its Total Processing Costs. The Department accepted Chevron’s unaudited statement of these direct processing costs as the source of Chevron’s current plant operating costs and plant depreciation; however, when the Department prepared its hearing exhibits, it deducted depreciation twice. [Transcript Vol. V, p. 918]. The Department’s final exhibits corrected the double deduction for depreciation. [Confidential Exhibits 527, 528, 532; Exhibits 531, 533, 534, 535].

80. There are minor discrepancies between the values for total gas sales used by the Petitioners and by the Department. We sorted out these discrepancies by referring to the Mineral Groups that each Petitioner identified as the object of its appeal.

81. BP’s Notice of Appeal identified the following Mineral Groups: 1008, 1009, 1021, 1022, 1023, 1024, 1028, 1031, 1033, 1041, 1051, 1053, 1069, 1070, 14336, 14355, and 39921. [Board Record]. The Department prepared a summary of information from the annual reports submitted for each of these Mineral Groups, and provided a total Gross Sales Value for all BP Mineral Groups that the plant processed. [Grenvik Direct, p. 6; Confidential Exhibit 504]. The Department’s summary also showed the processing deduction allowed by the Department in its Notices of Valuation, and compared the deductions reported by BP for each Mineral Group. [Grenvik Direct, p. 6; Confidential Exhibit 504].

82. We checked the Department’s total of Gross Sales Value for the BP Mineral Groups subject to appeal against the detail of BP’s proportionate profits method calculation. [Confidential Exhibits 504, BP-2]. The Total Revenues that BP calculated from the Whitney Canyon Gas Processing Plant in its proportionate profits calculation are approximately $5.4 million less than the revenues in the Department’s total. [Confidential Exhibits 504, BP-2]. We find the Department’s total to be more reliable because we could check the Department’s total against the detail of BP’s annual reports [Confidential Exhibit BP-1], but had no similar means to check the Total Revenues stated in BP’s proportionate profits calculation.

83. RME’s Notice of Appeal identified the following Mineral Groups: 1008, 1009, 1021, 1022, 1023, 1024, 1028, 1031, 1041, 1051, 1069, 1070, 14355, and 39921. [Board Record]. The Department prepared a summary of pertinent information from RME’s Annual Gross Products reports for each Mineral Group, and provided a total Gross Sales Value for all RME Mineral Groups that the plant processed. [Grenvik Direct, p. 16; Confidential Exhibit 508]. The Department’s summary also showed the processing deduction allowed by the Department in its Notices of Valuation, and compared the deductions reported by RME for each Mineral Group. [Grenvik Direct, pp. 16-17; Confidential Exhibit 508].

84. The Department’s summary of RME Mineral Groups included Mineral Group 14366, which is associated with the Whitney Canyon field, but was not subject to the appeal. [Confidential Exhibit 508]. However, RME did not claim a processing allowance for Mineral Group 14366, and the DOR did not allow a processing allowance. [Confidential Exhibit 508]. As a result, the total Whitney Canyon processing allowance was not distorted by including a processing allowance for Mineral Group 14366. For our calculations, we have adjusted the Department’s total RME revenue to exclude Gross Sales Value for RME’s Mineral Group 14366. Infra, ¶153.

85. Chevron’s Notice of Appeal listed gas production from several producing areas, including gas processed at Whitney Canyon. [Board Record]. Chevron identified the Mineral Groups subject to appeal as including but not limited to “MTD’s 4730, 4731, 4732, 4734, 4736, 4737, 1008, 1009, 1022, 1024, 1031, 1033, 1051, 4761, 4762, 4766, 4767, 4768, 4771, 4772, 4774, 4781, 14156, 14336, and 39921". [Board Record]. Based on this blanket statement, the Department prepared a summary of pertinent information from the Annual Gross Products reports submitted for Mineral Groups identified with Whitney Canyon, including 1008, 1022, 1024, 1031, 1033, 4781, 14156, 14336, and 39921, together with a Gross Sales Value for all Chevron Mineral Groups that the plant processed. [Grenvik Direct, p. 11; Confidential Exhibit 506]. The Department’s summary also showed the processing deduction allowed by the Department, and compared the deductions reported by Chevron for each Mineral Group. [Grenvik Direct, pp. 11-12; Confidential Exhibit 506].

86. In its rebuttal case, Chevron showed that the Department’s summary included a well from which gas was processed at Carter Creek, not Whitney Canyon. [Confidential Transcript Vol. V, p. 1013]. Chevron identifies this well as ACG #6, with Mineral Group number 1024. [Confidential Transcript Vol. V, pp. 1013, 1017]. For our calculations, we have adjusted the Department’s total revenue to exclude Gross Sales Value for Chevron’s Mineral Group 1024. Infra, ¶155.

87. From review of the Department’s summary of the annual reports data of each taxpayer, we find that all three taxpayers reported varying percentages of processing costs between and among their own Mineral Groups. [Confidential Exhibits 504, 506, 508 (column entitled “Rptd Proc %”)]. While these exhibits are generally confidential, processing allowance percentages do not independently disclose confidential sales and volume information. The high and low percentage of processing allowance claimed against sales value were as follows:

	High	Low
BP	56.5059%	55.1000%
RME	67.52%	39.40%
Chevron	36.68%	22.34%

[Confidential Exhibits 504, 506, 508]. RME claimed a processing cost percentage over 61% for twelve of its fourteen Mineral Groups. [Confidential Exhibit 508]. We note that Chevron appealed Mineral Group 1033, for which Chevron reported a processing deduction of less than 25%; the Department revised that processing deduction upwards to 25% when it applied the comparable value method. [Confidential Exhibit 506].

88. The processing percentages claimed by the Petitioners vary widely for even a single Mineral Group. [Confidential Exhibits 504, 506, 508]. For example, in Mineral Group 1022, known as the Amoco-Chevron-Gulf WI Unit, BP’s reported processing percentage is 55.1%; RME’s reported processing percentage is 67.52%; and Chevron’s reported processing percentage is 32.94%. [Confidential Exhibits 504, 506, 508, BP-1, p. BP0007]. We find that the Petitioners shared interests in production for most Mineral Groups. For all but two Mineral Groups subject to this appeal, two or more of the Petitioners reported production from the same Mineral Group. [Confidential Exhibits 504, 506, 508].

89. The taxpayers generally argue that when we consider plant revenues, we should look no further than the 25% processing fee applied against each taxpayer’s gross revenue. [E.g., Syring Direct, Question 26; Transcript Vol. II, pp. 350-351]. Several witnesses testified that the 25% processing fee is just taking money “from one pocket and putting it in another pocket.” [Transcript Vol. I, p. 166; Syring Direct, Questions 17, 26; Wilkinson, Transcript Vol. IV, p. 720]. RME’s representative testified that for the plant owners, the payment of the processing fee is “a flow-through; it is inconsequential.” [Corrected Ostroff Direct, p.15]. However, we disagree, and find that total plant revenues for each taxpayer are materially affected by fees from third parties, and by the degree to which the taxpayer is over-producing or under-producing when compared to its ownership share.

90. The ownership interests in the Whitney Canyon plant in 2001 were as follows:

BP	62.9546%
RME	19.0112%
Chevron (Gulf)	15.0272%
Forest	3.0136%

91. The Whitney Canyon plant processed gas in 2001 for the following producers, in the following proportions of all gas processed:

BP	47.92%
RME	14.88%
Chevron (Gulf)	12.34%
Forest	3.42%
Chevron (1995)	5.13%
Merit	0.16%
Wahsatch (Anschutz)	16.15%

[Miller Direct, Question 19; Transcript Vol. II, p. 225]. We accepted Chevron’s distinction between its ownership and production interests acquired through Gulf, and its independently acquired interests. Supra, ¶¶3, 13, 30. For the findings to follow, we note that we have not been provided corresponding revenues for each producer – only these percentages of all gas processed.

92. We compared the percentages of all processed gas taken from each producer and paid to the plant owners. We did so by multiplying each producer’s percent of all gas by the 25% processing allowance, which is the processing fee. We then subtracted the fee from the original percentage of all gas, and show the remaining percentages of volume due to each producer after subtracting the in-kind processing fee of 25%:

Producer	Start %	Fee Paid Owners	Remaining volume
BP	47.92%	11.98%	35.94%
RME	14.88%	3.72%	9.255%
Chevron (Gulf)	12.34%	3.085%	11.16%
Forest	3.42%	0.855%	2.565%
Chevron (1995)	5.13%	1.2825%	3.8475%
Merit	0.16%	0.04%	0.12%
Wahsatch (Anschutz)	16.15%	4.0375%	12.1125%
Totals	100.00%	25.00%	75.00%

93. We determined the processing fee gas each plant owner received by multiplying its respective plant ownership interest (¶90) times the 25% that represents the portion of all processed gas that was the owners’ fee:

Producer	Ownership share
BP	15.7364%
RME	4.7528%
Chevron (Gulf)	3.7568%
Forest	0.7534%
Total	24.9994% of all gas

94. After processing, each plant owner’s total share of all processed gas equaled its producer percentage of gas remaining after processing (Remaining Volume, ¶92), plus its ownership percentage of the processed gas (Ownership Share, ¶93). Supra, ¶¶92-93. For example, BP’s total share of all gas equaled its percentage of gas remaining after processing, 35.94% (Remaining Volume, ¶92), plus its share of the processing fee gas, 15.7364% (Ownership Share, ¶93), or a total of 51.6764% of all gas. In contrast, since Merit is not an owner, Merit’s total share of all processed gas equals only its share of gas remaining after payment of the processing fee, or 0.12% (Remaining Volume, ¶92) of the total.

95. For the seven producing sources of gas, the final portion of all gas processed, after the redistribution of processing fees to plant owners interests is taken into account, was as follows:

Producer	Total Gas Produced	Total Gas Received After Fees Paid
BP	47.92%	51.6764%
RME	14.88%	15.9128%
Chevron (Gulf)	12.34%	13.0118%
Forest	3.42%	3.3184%
Chevron (1995)	5.13%	3.8475%
Merit	0.16%	0.12%
Wahsatch (Anschutz)	16.15%	12.1125%
Total	100%	99.9994%

96. A taxpayer who was a plant owner in production year 2001 received more plant revenue than just the 25% fee that it paid for processing its own production. For example, the 25% processing fee paid by BP on its production equals 11.98% (25% of 47.92% = 11.98%), supra ¶92. BP’s share of the 25% processing fee charged to all producers is 15.7364% (47.92% of 25% = 15.7364%), supra ¶¶91, 93. The difference is 3.7564% of all 2001 gas processed through the Whitney Canyon plant. We find that these differences are not a trivial pass-through, and must not be ignored. If we ignored the redistribution of gas for processing fees, we would understate each plant owner’s revenue by the following percentages of all gas produced:

Plant owner	Produced	Total with fees	Difference
BP	47.92%	51.6764%	3.7564%
RME	14.88%	15.9128%	1.0328%
Chevron (Gulf)	12.34%	13.0118%	0.6718%

97. In finding that the plant owners’ fee results in more than a simple return of gas equal to the amount of each owner’s processing allowance, we also determined the degree to which the Department’s use of a processing allowance falls short of being an adequate surrogate for plant revenues. We considered what adjustments should be made to estimates of plant revenue to account for this difference. We find that the necessary adjustment differs for each taxpayer.

98. For the purposes of comparing plant revenues with plant costs, one can account for our calculated difference from the Department’s 25% processing allowance in two ways: (1) an appropriate upward adjustment in revenue; or (2) an appropriate credit against costs. For each taxpayer, we examined revenues and costs using features of the format of the Department’s Confidential Exhibits 505, 509, and 532, all entitled “Comp II Statistics.” (Comp II refers to the fact that this case is the second case involving application of the comparable value method to gas production processed at the Whitney Canyon plant.)

99. The Department applied 25% against BP’s total revenues to reach its processing allowance, which is the surrogate for plant revenues. [Exhibit 505]. The Department made no upward adjustment as we did to BP’s total revenues to account for BP’s ownership share of all natural gas processed by the plant, leaving a shortfall in estimated plant revenue of 3.7564% of all gas. Supra, ¶96. We know there was no adjustment to BP’s total revenues, because when we compared total Gross Sales Value in the Department’s summary of BP’s annual reports with the Gross Revenue in Department’s Comp II Statistics for BP, we found that the two numbers were the same. [Confidential Exhibits 504, 505].

100. In contrast, we find that the Department made a implicit credit against BP’s costs to partially account for the 3.7564% difference, because it used BP’s total processing costs from BP’s proportionate profits calculation. BP accounted for receipt of its ownership share of Wahsatch Gathering System gas through a credit against its share of plant processing costs. BP recorded this credit in the detail of its proportionate profits calculation as an entry entitled, “Related to Processing - (WGS)”. [Confidential Exhibit BP-2, p. BP0043].

101. A credit for Wahsatch gas did not fully account for BP’s ownership share of the processing fee gas. The understatement of BP’s share of plant revenues can be expressed in terms of a percentage of all gas processed at the Whitney Canyon plant. BP implicitly claims that its total gas revenue would equal the fee it paid on its own production, or 11.98% of all gas, plus BP’s share of the Wahsatch processing fee in the amount 2.5414% of all gas (62.9546% plant ownership share (¶90) times the 4.0375% fee paid to all plant owners by the Wahsatch producer (¶92)). Supra, ¶¶90, 92. The sum of these two percentages is 14.5214% of all gas. When we compare BP’s actual ownership share of all gas, 15.7364%, with the percentage that results using BP’s theory, 14.5214%, we see that the difference is 1.2150% of all gas processed at Whitney Canyon. [By computation from supra, ¶¶90, 92, 93].

102. Although the percentage is modest, the difference is enough to materially affect BP’s plant-related revenue and with it, BP’s proportionate profits calculation. BP has adjusted its total direct costs by a credit of only 2.5414% of all gas, representing its ownership share of the Wahsatch gas. Supra, ¶100. The credit should have been for 3.7564% of all gas (2.5414% plus 1.2150%), or nearly half again more.

103. As an alternative to adjusting by an additional credit against processing costs, BP’s correct ownership share of plant revenue can be estimated by adjusting the processing fee share for BP upward by 8.37% (i.e. (15.7364% (actual) minus 14.5215% (Department calculation)) divided by 14.5215%).

104. The Department made no upward adjustment to RME’s total revenues to account for RME’s ownership share of all natural gas (production and fees). The Department used only its processing allowance as a surrogate for plant revenues. [Exhibit 509]. We know there was no adjustment to RME’s total revenues, because when we compared total Gross Sales value in the Department’s summary of RME’s annual reports with the Gross Revenue in Department’s Comp II statistics for RME (adjusted to eliminate Mineral Group 14336), we found that the two numbers were the same. [Confidential Exhibit 508, adjusted to eliminate Mineral Group 14336 as described supra, ¶84; Rev. Confidential Exhibit RME-4, line 24 under column for 2001; Rev. Confidential Exhibit RME-6, item F, “Gross Sales Revenue”]. We eliminated Mineral Group 14336 from the Department’s summary because RME did not appeal Mineral Group 14336. Supra, ¶84. If eliminating Mineral Group 14336 distorts the overall statement of Whitney Canyon plant revenues, that distortion will understate revenues, and favor the taxpayer’s position.

105. RME’s representative stated that RME had adjusted its revenue for Wahsatch gas: “[t]hat revenue would include what was our revenue, including the fees that came off of it, like Wahsatch.” [Transcript Vol. III, p. 575]. We find that this testimony is not supported by any documents, and is not credible.

106. The possibility remains that RME made a credit against processing costs, as BP did. Unlike BP, no such credit appears in RME’s proportionate profits calculation. [Rev. Confidential Exhibit RME-6; item B, “Total Direct Processing (Plant) Costs”]. However, RME’s calculation is not as detailed as BP’s. [Compare Confidential Exhibit BP-2].

107. We confirmed that RME made no such credit by comparing RME’s claimed Total Direct Processing (Plant) Costs with the source of those costs, the plant owners’ monthly joint interest billings. [Exhibit 975]. The joint interest billings are not confidential. Each monthly statement included from four to six separate invoices, entitled “basic gross ownership,” “gas collection system,” “sulfur loading terminal,” “sulfur haul road,” and “seismic program.” [Exhibit 975].

108. RME’s representative testified that he calculated RME’s Direct Processing Costs using the amounts billed to RME as a plant owner by BP as plant operator. [Transcript Vol. V, pp. 584-585]. RME did not include capital costs from these billings. [Transcript Vol. V, p. 585; see Transcript Vol. II, pp. 244-245]. Generally, RME captured operating expense, subtracted operating overhead, and multiplied by its plant ownership percentage to reach the amount of its Direct Processing Costs. [Transcript Vol. V, pp. 585, 588]. The operating overhead in the joint billings can be identified by its line reference, L00001. [Transcript Vol. V, p. 587].

109. We replicated RME’s calculation of its Direct Processing Costs. For all invoices but those entitled “basic gross ownership,” we totaled the category of “non-AFE” expenditures, and subtracted L00001 overhead. For “basic gross ownership” invoices, we totaled Operating Expense category 1000095307 and again subtracted L00001 overhead. We made one additional adjustment, which was to subtract about $1.1 million of property taxes found principally in the sulfur haul road invoices. RME made a separate entry for ad valorem taxes in its proportionate profits calculation [Rev. Confidential Exhibit RME-6]; and, we would otherwise not anticipate any production taxes associated with processing to be included in RME’s reported costs. Supra, ¶29. When we multiplied the total costs by RME’s plant ownership percentage of 19.0112% (¶90), the end result was about $3.7 million, which was close enough to RME’s processing costs to give us confidence in RME’s representations in the source of its Direct Processing Costs.

110. The same examination of the joint interest billings demonstrated that RME made no attempt to subtract Wahsatch gas revenue from its stated processing costs, since there is no explicit deduction from the joint interest billings for Wahsatch gas revenue. [Exhibit 975]. Unlike BP, RME took no credit against processing in its proportionate profits calculation. RME therefore did not account for its ownership share of any gas but its own. This failure carried over into Revised Confidential Exhibit RME-4.

111. We find that RME adjusted neither plant revenues nor plant costs to account for the difference between the Department’s comparable value processing allowance and RME’s actual ownership share. This is a difference equal to 1.0328% of all gas processed at the plant. Supra, ¶96. Stated another way, RME has proceeded as if its processing fee volume of 3.72% were the measure of its ownership share of plant processing fee revenue, when the RME ownership share of plant was actually 4.7528% (¶93).

112. RME’s correct ownership share of plant revenue can be estimated by adjusting the processing fee share for RME upward by 27.76% (i.e. (4.7528% minus 3.72%) divided by 3.72%). [Confidential Exhibit 509, adjusted to eliminate Mineral Group 14336].

113. The Department applied 25% against Chevron’s total revenues to reach its processing allowance, which is the Department’s surrogate for plant revenues. [Exhibit 532]. For the purposes of comparing Chevron’s share of plant costs with its ownership share of revenues, we find that neither Chevron nor the Department has made an upward adjustment to Chevron’s total revenues to account for the difference between the Department’s processing allowance and Chevron’s ownership share of all natural gas (production and fees). We based our finding on a comparison of the total Gross Sales value in the Department’s summary of Chevron’s Annual Gross Products reports with the revenue as described in confidential testimony. [Confidential Exhibit 506, adjusted to eliminate Mineral Group 1024 as described supra, ¶86; with segregation of Chevron(Gulf) and Chevron(1995) interests as described in Confidential Transcript Vol. V, pp. 1010-1013]. We eliminated Mineral Group 1024 from the Department’s summary because no Chevron production from Mineral Group 1024 was processed at Whitney Canyon. Supra, ¶86. If eliminating Mineral Group 1024 distorts the overall statement of Whitney Canyon plant revenues, that distortion will understate revenues, and favor the taxpayer’s position.

114. Chevron’s representative stated that Chevron subtracted an amount “that was reflective of the revenue [Chevron] received from Anschutz [Wahsatch] gas” from Chevron’s total plant processing costs, and that the adjusted plant costs were used in the principal exhibits of Chevron and the Department. [Confidential Transcript Vol. V, pp. 1020-1021; Confidential Exhibits 527, 204; the same cost figures were also used in Confidential Exhibit 532]. However, unlike BP, and like RME, Chevron provided no documentation to support this testimony. Chevron’s disclosure of its proportionate profits calculation was in a form that does not permit us to tell whether any specific entry was made to adjust for Wahsatch gas. [Compare Confidential Exhibit BP-2, p. BP0043, and Rev. Confidential Exhibit RME-6, with Confidential Exhibit 204].

115. Like RME, Chevron derived its processing costs from the joint interest billings to the plant owners. [Transcript Vol. III, pp. 465-468]. The joint interest billings were compiled by Chevron’s North American Financial Services Center, and Chevron’s tax representative used a recap of the costs to prepare Chevron’s annual report. [Transcript Vol. III, pp. 465-468]. Chevron did not introduce any documentation of the recap information, and did not call anyone other than its tax representative to testify.

116. We find that the joint interest billings provide support for Chevron’s tax representative, but show that Chevron did not deduct overhead. [Exhibit 975]. We did the same calculations that we have already described with respect to RME, but applied Chevron’s plant ownership percentage of 15.0272%. Supra, ¶¶90, 109-110. When we subtracted overhead, as we did with RME, the result is slightly less than $2.94 million. This amount is less than the processing cost Chevron used in its reports. [Confidential Exhibit 204]. This amount therefore could not have been the starting point for a deduction against processing cost, because any such deduction would yield a result lower than $2.94 million.

117. Chevron’s claim that it credited Wahsatch gas against its costs was supported when we included the overhead costs that RME had excluded. [Exhibit 975]. If we do not subtract overhead, Chevron’s share of plant costs is approximately $3.38 million. If we do not subtract the $1.1 million of property taxes that appeared in the sulfur haul road invoices, Chevron’s share of plant costs is $3.54 million. Both of these amounts exceed the processing cost used by Chevron in its reports. [Confidential Exhibit 204]. Using these amounts, we referred back to the dollar amount of the Wahsatch credit taken by BP in its proportionate profits calculation. [Confidential Exhibit BP-2]. We multiplied BP’s credit by the proportion of Chevron ownership interest to BP ownership interest to get a rough approximation of what a credit could be. We find that the result is consistent with testimony that Chevron made a deduction against processing cost for Wahsatch gas, although it is more plausible if we use the higher calculation of Chevron’s share of plant costs, or $3.54 million, which includes both overhead and property taxes.

118. There was another possible adjustment that we have taken into account. The Department commented that Chevron made an adjustment to account for the correct point of valuation, which we discuss infra, ¶¶125-127. [Transcript Vol. V, p. 898]. We were unable to satisfy ourselves that this was so, from the evidence of either Chevron or the Department.

119. As with BP, we find that a deduction for Wahsatch gas alone falls short of representing Chevron’s ownership share of the processing fee gas, although slightly. Supra, ¶¶101-103. Chevron (Gulf) paid a processing fee on its production equal to 3.085% of all gas processed at the Whitney Canyon plant. Supra, ¶92. The Chevron (Gulf) ownership share of the Wahsatch gas was 0.6067% (15.0272% of 4.0375%) of all processed gas. Supra, ¶¶90, 92. The total of these two amounts (0.6067% and 3.085%) is 3.6917% of all gas processed at the plant. Chevron (Gulf)’s correct ownership volume is 3.7568% of all processed gas. Supra, ¶93. The resulting understatement of volume is 0.0651% of all processed gas.

120. As an alternative to adjusting by additional credit against processing costs, Chevron’s correct ownership share of plant revenue can be estimated by adjusting the processing fee share for Chevron (Gulf) upward by 1.76% (i.e. (3.7568% minus 3.6917%) divided by 3.6917%). [Confidential Exhibit 532, adjusted to exclude Mineral Group 1024].

121. The taxpayers claim that modifying the 25% processing fee “would have no bottom line impact.” [Transcript Vol. III, p. 433; Syring Direct, Question 26; Ostroff Corrected Direct, p. 15]. From our review and analysis, that claim is not credible. Using the percentages of plant ownership and plant production in production year 2001, an increase in the 25% processing fee has the effect of increasing the total percentage volume of gas going to BP and RME. A fee increase likewise increases the total percentage of gas going to Chevron with respect to its Gulf interests, but modestly decreases the total percentage of gas going to Chevron, because its interests under the 1995 Chevron Agreement are adversely affected. The effect on Wahsatch and Merit, who have no ownership interest, is a direct decrease in total percentage of gas. In view of these divergent effects on producers, testimony that belittles the difficulty of modifying the processing fee is not credible.

122. The testimony of Joseph Wilkinson implied that a modification of the 25% processing fee could have an unfavorable effect on a company’s market value. A primary driver for the market value of exploration and production companies like the Petitioners is the value of gas reserves. [Transcript Vol. IV, p. 725]. To the extent that processing costs are deducted from reserves to determine a value for the reserves, an increase in processing costs decreases the value of reserves and tends to decrease the market value of the company. [Transcript Vol. IV, pp. 725-726]. If the processing fee were 100%, the reserves would be worth nothing. [Transcript Vol. IV, p. 726]. A producer has an incentive to resist an increase in the processing fee, although for companies as large as Petitioners, we cannot determine whether Whitney Canyon production would be noticeable.

123. Broadly speaking, each taxpayer’s proportionate profits cost data is subject to at least two distortions when used as a surrogate for plant operating costs; one distortion may understate actual costs, and the other may overstate actual costs. These distortions are of concern because the Department’s comparison of plant revenues and plant costs for each Petitioner, the Comp II Statistics, rest on the proportionate profits cost data of each taxpayer. Supra, ¶¶62-64, 66. As we have said, we modeled some features of our calculations on the Comp II Statistics.

124. The proportionate profits data may understate actual costs if the taxpayers did not report all costs. We know that the proportionate profits calculation is supposed to reflect only direct costs, as opposed to all costs. Wyo. Stat. Ann. §39-14-203(b)(vi)(D)(I). We found no evidence of such understatement. As we have seen from examination of the joint interest billings, RME costs included everything listed in the joint interest billings, except overhead. Supra, ¶109. As best we could determine, Chevron followed suit, but included overhead as well. Supra, ¶116. Chevron’s tax representative criticized the Department’s cost calculations because the Department “appeared to” omit Chevron’s indirect costs. [Chambers Rebuttal, Question 11]. If Chevron excluded some indirect costs from its annual reports to the Department, those exclusions were such a modest portion of the joint interest billings that we could not readily identify them. RME’s cost calculations did not provide any independent insight about the amounts of indirect costs. [Rev. Confidential Exhibit RME-4].

125. The proportionate profits cost data may overstate actual costs to the extent that the taxpayers included expenses that should not be considered processing costs. Wyo. Stat. Ann. §39-14-203(ii), (iv). Petitioners have included the Whitney Canyon field gathering system in their processing costs. By statute, gathering system expenses are typically production costs, but the Petitioners took the position that the Whitney Canyon facility extends all the way to meters located at the wellheads in the field. [Bidwell Direct, Questions 5-6; Transcript Vol. I, pp. 56-57, Vol. II, pp. 210-211; Exhibit 954, page 1]. After separation at the inlet facility, the gas enters an inlet compressor. [Transcript Vol. I, pp. 56-57]. We find that BP’s witnesses described a gathering system, and that Petitioners’ accounting of Whitney Canyon processing costs should have begun at the inlet to the compressor, not at the wellhead.

126. The Wyoming Supreme Court has rejected the claim that Whitney Canyon processing costs include gathering system costs all the way to the wellhead. Amoco Production Company v. Dept. of Revenue, 2004 WY 84, ¶¶28-37, 94 P.3d 430 (2004). At the hearing in this case, BP (on behalf of all Petitioners) repeated the same position that gave rise to the Wyoming Supreme Court’s decision, by describing the wellhead meters as custody transfer meters. [Bidwell Direct, Question 6]. Despite the name given to these meters by the plant operator, the purpose of these meters is “to measure the output of each well for allocation purposes.” [Bidwell Direct, Question 6]. Under the Wyoming Supreme Court’s decision, we must reject BP’s position.

127. Gathering system expenses are identified under the rubric of “Gas Collection System” in one of the set of monthly invoices that comprise the joint interest billings that RME and Chevron used. [Transcript Vol. II, pp. 242-243]. Of course, we cannot know how closely the Gas Collection System expense of the joint interest billings correlates to statutory gathering system expenses without an audit, and we are not in a position to do an audit. If we assumed that gathering system expense was equal to the Gas Collection System invoices, we could estimate the magnitude of overstated plant costs for tax purposes. When we totaled the joint interest billings in the manner we have previously described, supra, ¶109, but excluded overhead, we found that Gas Collection System invoices were approximately 26% of all the current operating costs reflected in the joint interest billings, exclusive of overhead. Whatever the magnitude of the overstated operating costs, we assume that there would be a parallel overstatement of depreciation associated with the gathering system.

128. We find that BP similarly treated gathering expenses as processing costs. This follows logically from BP’s position that the plant processing costs extend to the wellheads in the Whitney Canyon field. We can also confirm that BP did so from its evidence. A BP witness testified that 40% of plant operating cost was incurred as electricity for compression, and that compression was provided to the Whitney Canyon field as well as to the plant inlet. [Transcript Vol. I, pp. 91-92]. We checked this testimony against the proportionate profits calculation the Department used as the source of BP’s cost information. [Confidential Exhibit BP-2, p. 0043]. BP recorded no production costs at all for “Fuel, Water & Power.” All “Fuel, Water & Power” costs in BP’s proportionate profits calculation were listed as processing costs. At the same time, the Gas Collection System joint interest billing invoices include an entry for utilities, so we know that BP routinely accounted for utility charges related to the gathering system. [E.g., Exhibit 975, p. WC 0673, line A00003]. The utility charges were simply not included as production costs in BP’s proportionate profits calculation.

129. We are faced with a mismatch between costs that are allowable under the proportionate profits method, and costs that plant owners actually incurred under the rubric of Gas Collection System, as reflected in the joint interest billings. Supra ¶¶125-128. For the purposes of this case, our estimate of plant costs will include all Gathering System Expense reflected in the joint interest billings, even though doing so would be contrary to statute if we were applying the proportionate profits method. We believe this is the only practical approach in view of the fact that the Petitioners have all misapplied the proportionate profits method in the same way. It also assures that any errors in our estimate will favor the Petitioners.

130. We find that the Petitioners did not include information in their annual reports that would have enabled the Department to break out gathering system costs. It follows that the Department would not have been in a position to reduce the 25% processing fee to account for plant expense, related to the processing fee, that the statute did not allow as processing.

131. In compiling its cost statistics for each taxpayer, the Department accepted each taxpayer’s depreciation figure. [Confidential Exhibits 505, 509, 532; Transcript Vol. V, pp. 993, 995].

132. The Board compared the depreciation claimed by the three Petitioners. RME’s depreciation was disproportionately large. RME’s plant ownership share was 26.5% larger than that of Chevron, but RME claimed depreciation 229% larger than Chevron’s depreciation – a dollar amount well more than three times greater. [Confidential Exhibits 509, 532]. RME’s plant ownership share is 30% that of BP, but RME’s depreciation was 62% that of BP. [Confidential Exhibits 505, 509].

133. RME did not provide compelling testimony to support its processing depreciation. RME’s representative explained that its depreciation “comes out of our financial records.” [Confidential Transcript Vol. III, p. 582]. Processing depreciation is calculated on a units-of-production method, based on the reserve estimates of its engineers. [Confidential Transcript Vol. III, pp. 582-583]. RME’s representative could not explain why the reserve estimates of different companies produced such disparate results. [Confidential Transcript Vol. III, p. 584]. RME produced neither RME engineers with their documented reserve estimates, nor RME financial records to support the depreciation. RME introduced an exhibit that purports to show plant capital accounts [Rev. Confidential Exhibit RME-5], but no one explained how this exhibit might bear on RME’s disproportionate claim for depreciation. [E.g., Corrected Ostroff Direct, pp. 10-11].

134. RME’s own historical information shows an unexplained change from the period 1989-1995, when a relatively constant depreciation figure suggests that RME used straight line depreciation. [Rev. Confidential Exhibit RME-4, line 12]. RME’s 2001 depreciation is 74% higher than its 1995 depreciation. [Rev. Confidential Exhibit RME-4, line 12]. In the period since 1995, RME’s claimed depreciation has been as much as two and one-half times as high as 1995. [Rev. Confidential Exhibit RME-4, line 12].

135. We do not find RME’s 2001 depreciation to be a credible surrogate for its share of the depreciation component of Whitney Canyon plant costs. Aside from the factors we have already mentioned, supra, ¶¶132-134, we are influenced by the fact that the Whitney Canyon plant will operate through 2008; that RME demonstrated a tendency to overstate depreciation by its treatment of turnaround costs; and that RME was not scrupulous in correcting an acknowledged reporting error. Supra, ¶¶75-77. Our finding does not conflict with the Department’s policies for accepting reported depreciation subject to audit, because we intend to determine whether plant revenues exceed plant costs in production year 2001, not to determine taxable value.

136. As an adjusted figure for processing depreciation, we used the same amount that RME used for production years 1992 through 1995. As we have already found, BP’s depreciation was higher than Chevron’s, relative to ownership share. Supra, ¶132. We calculated RME’s depreciation as a proportionate share of BP’s reported processing depreciation ((RME ownership share divided by BP ownership share) times BP processing depreciation from Confidential Exhibit 505). The result of the RME/BP calculation was less than the depreciation actually used for production years 1992 through 1995; we elected to use the higher figure. [Confidential Exhibit RME-4]. The actual 1995 depreciation is more favorable to RME individually, and the Petitioners together, than expressing RME’s depreciation as a proportion of one of the other two Petitioners.

137. Based on our findings, we adjusted the Department’s Comp II Statistics for each taxpayer to make our own comparison of Whitney Canyon plant revenues and plant costs. Before we describe our results, we must first address what a netback approach to value is, since many witnesses used the word freely, but not with the same meaning. In order to provide context for the evidence of the parties and for our calculations, we summarize some of the definitions of the netback method, as they appear in Wyoming law and in the testimony of the witnesses.

138. The Wyoming Supreme Court has quoted this Board as describing the netback method in this way: “a cost approach to value which relies on the following formula: Sales value - (minus) value added by processing and transportation after the point at which mining is completed = Fair market value of the mineral at the mine mouth.” Amoco Production Company v. State Board of Equalization, 12 P.3d 668, 673, n. 2 (Wyo. 2000); see also Department of Revenue v. Amoco Production Company, 7 P.3d 35, 39 (Wyo. 2000); Amax Coal Company v. State Board of Equalization, 819 P.2d 825,827 n. 4 (Wyo. 1991). Since that decision, we have had occasion to consider both the history of the netback method since 1988, and practical limitations on its application. Whitney Canyon 2000, ¶¶151-159; In the Matter of Sublette County, Docket No. 2000-142 et. al., 2004 WL 1174651 (Wyo. St. Bd. of Eq. 2004), ¶¶41-47, 49, 67, 86, 112-119, 272 (netback method a version of comparison approach in pre-1990 regulations). The Legislature enacted the current statutory definition in 1990. 1990 Wyo. Sess. Laws, Chapter 54. Since then, the statute has defined the netback method as follows: “Netback – The fair market value is the sales price minus expenses incurred by the producer for transporting produced minerals to the point of sale and third party processing fees....” Wyo. Stat. Ann. §39-14-203(b)(vi)(C).

139. Petitioners’ witness Lisa Adair argued for a netback that begins with a market center. [Transcript Vol. IV, p. 669]. She defined a market center as “a point in the value chain where we have price discovery and transparency, where there are a lot of deals being done, in other words, a lot of liquidity in the spot market or the term gas market.” [Transcript Vol. IV, p. 669]. She said that the Henry Hub or Opal would qualify as market centers. [Transcript Vol. IV, p. 669]. We find that her concept of market center is inconsistent with the valuation methods available to the Department under the statute. [Bolles Direct, pp. 5-7].

140. According to the Wyoming Department of Audit, indirect costs should not be included in a netback calculation of taxable value. [Transcript Vol. V, p. 881]. We do not concern ourselves with this point because our interest in this context lies in a comparison of plant revenues and plant costs. As important, we had no ready means to separate direct from indirect costs.

141. The witnesses often used netback in a very generic sense. When doing so, they use netback as a shorthand for comparing plant revenues and plant costs. For example, RME’s witness testified that, “[f]rom a conceptual standpoint, a netback method is often the preferred method for arriving at taxable value because it removes only actual processing and transportation costs.” [Corrected Ostroff Direct, p. 6].

142. The focus of every netback analysis made by any witness in this case was ultimately on return on invested capital, also known as return on investment. [Corrected Ostroff Direct, pp. 9-10; Confidential Rev. Exhibit RME-4; Chambers Direct, Questions 23-26; Grenvik Direct, pp. 7-8, 12-13, 17-18, 23; Exhibits 505, 507, 509, 532]. Return on investment has a particular function in this case. It is a measure that goes beyond the comparison of plant revenues and plant costs, to determine whether any excess of revenues over costs occurred to a degree that can usefully be characterized in the context of the Department’s use of the comparable value method.

143. By simply evaluating return on investment, we are not making a finding that any particular return on investment was contemplated by the 25% processing fee. [Bolles Direct, p. 26].

144. The parties presented evidence of return on invested capital in two different ways. Both ways required information about each plant owner’s un-depreciated asset balance. [Exhibits 505, 509, 532].

145. In the context of this case, the un-depreciated asset balance means taxpayer-specific capital investment in the Whitney Canyon plant that has been reduced annually to eliminate return of investment through depreciation. Stated another way, the un-depreciated asset balance is the amount of capital investment that each Petitioner has not yet recovered through its accounting for depreciation.

146. At the time of the turnaround in 2001, the Whitney Canyon plant was already “at 20 years in the 20-year design life of the plant.” [Transcript Vol. I, p. 86]. Wilkinson’s calculations more precisely show that production year 2001 was the eighteenth year of plant operations. [Rev. Exhibit 972, attached Exh. F]. The Petitioners have recovered the majority of the original capital investment in the Whitney Canyon plant, now in operation for more than twenty years, by depreciation. The un-depreciated asset balance for each Petitioner was provided to the Department in discovery, or otherwise disclosed in a Petitioner’s exhibits. [Grenvik Direct, pp. 7-8, 13, 18].

147. The first way the parties testified to return on investment was to simply assume a percentage rate of return. The assumed rate was then applied against invested capital to generate total costs to make a comparison. RME used this approach. RME assumed a rate of 12.52% for its original analysis [Confidential Exhibit RME 4], then assumed a rate of 10% for its revised analysis. [E.g., Confidential Rev. Exhibit RME-4]. The results were used to support a number of comparisons and arguments. In contrast, the Department assumed a rate of return of 8.81% to generate the netback portion of an analysis that compared the results of different valuation methods. [Grenvik Direct, pp. 9-10, 21-22; Exhibit 535].

148. For this case, we find that there is an easier way to gauge the consequences of the different valuation methods than attempting to resolve sharp disputes over assumptions about rate of return. [E.g., Taxpayers’ Revised Proposed Findings of Fact and Conclusions of Law, ¶¶282-285]. (In this regard, we note that no party offered evidence of the capital structure of any Petitioner, or of the Petitioners’ industry.) When the Department summarized the annual reports of the three taxpayers, its summary included a difference in taxable value between what the taxpayer reported and the Department allowed for each Mineral Group. [Confidential Exhibits 504, 506, 508; Grenvik Direct, pp. 6, 12, 17]. We simply added up the differences for each Mineral Group at issue in this case. Supra, ¶¶81-85. The combined difference in taxable value for the three taxpayers is $44,457,285.

149. The second approach to return on investment was to derive rate of return from other information, as the Department does in its Comp II Statistics exhibits for each taxpayer. [Confidential Exhibits 505, 509, 532]. The Department used the operating cost and depreciation reported by each Petitioner as a surrogate for plant costs. As a surrogate for plant revenues, the Department used the processing allowance from its Notices of Valuation. [Grenvik Direct, pp. 8, 13, 18]. The Department then calculated the difference between these two surrogates, and divided this difference by the taxpayer’s un-depreciated asset balance. [Grenvik Direct, pp. 8, 13, 18; Confidential Exhibits 505, 509, 532; Transcript Vol. V, pp. 931-944]. The Department characterized the result, entitled “ROI on Assessed Processing” in the Comp II statistics exhibits, as an implied rate of return on each Petitioner’s invested capital. [Grenvik Direct, pp. 8, 13, 18; Confidential Exhibits 505, 509, 532; Transcript Vol. V, pp. 931-944].

150. Deriving a rate of return from revenue and cost data is inherently backward looking. [Transcript Vol. IV, p. 665]. Since we are interested in answering a question about what occurred in production year 2001, and taking into account the information at our disposal, we find it more useful to focus our attention on deriving a rate of return. We have done so for each Petitioner, following the Department’s model, and on a combined basis for all three Petitioners. We incorporated the adjustments addressed thus far in our findings.

151. For each taxpayer individually, we find that plant revenues cover plant operating expenses and reasonable depreciation, plus a return on investment.

152. For BP, we only adjusted the Department’s processing allowance, which we found to understate BP’s revenue when used as a surrogate for plant revenue. We adjusted the Department’s processing allowance upward by 8.37%. Supra, ¶103. BP’s implied rate of return rose to 13.97% when we made this adjustment.

153. For RME, we revised the Department’s calculation of implied rate of return [Confidential Exhibit 509] in five ways:

(1) We reduced the Department’s statement of Gross Revenue, to eliminate revenue from Mineral Group 14366, which is not at issue. Supra, ¶84.

(2) We increased the Department’s processing allowance by 27.76% to reflect the revenue associated with RME’s ownership share. Supra, ¶112.

(3) We reduced RME’s total costs to amortize turnaround expense, by accepting the processing cost information on RME’s revised proportionate profits calculation, identified as NonOp Billing from Outsiders, Ad valorem tax, and Depreciation. [Rev. Confidential Exhibit RME-6].

(4) We then adjusted RME’s revised depreciation by substituting the amount of depreciation RME took from 1992 through 1995. Supra, ¶136.

(5) We allowed an increase to total processing expenses for overhead, as RME proposed. [Rev. Confidential Exhibit RME-4]. We did so principally to be consistent with our review of Chevron, infra, ¶116, but also for the sake of erring on the side of the taxpayer so that our final result will, if anything, understate the implied rate of return.

154. With these RME adjustments, we found an implied rate of return of 8.45%. This implied rate of return is less than the 10% RME itself proposed in support of its direct testimony. [Rev. Confidential Exhibit RME-4, line 8, production year 2001]. If we had used depreciation proportionate to that of BP, supra, ¶132, RME’s rate of return would be 10.4%.

155. For Chevron, we revised the Department’s calculation of implied rate of return [Confidential Exhibit 532] relying on Chevron’s distinction between its two sets of interests, and on details of Chevron’s annual gross products reports that were disclosed in Chevron’s rebuttal case. [Confidential Exhibit 204]. We adjusted the Department’s statistics to reach a rate of return for Chevron (Gulf) in three ways:

(1) We reduced Gross Revenue to eliminate the revenue associated with production processed at Carter Creek, and revenue associated with the 1995 Chevron Agreement. We therefore used the same amount that Chevron used in its Chevron (Gulf) proportionate profits calculation. [Confidential Transcript Vol. V, pp. 1010,1013; Confidential Exhibits 532, 204, p. 2].

(2) We recalculated the Department’s 25% comparable value processing allowance, using the revised Gross Revenue figure which Chevron proposed. [Confidential Transcript Vol. V, p. 1013].

(3) We adjusted the Department’s processing allowance upwards by 1.76%, to correct an understatement of plant revenue. Supra, ¶120.

156. With these Chevron adjustments, we found an implied rate of return of 10.64%, as opposed to the Department’s conclusion that Chevron’s implied rate of return on assessed processing was 19.03%. [Confidential Exhibit 532]. Generally speaking, our decision to accept Chevron’s distinction between the two sources of its interests, supra, ¶71, substantially reduced Chevron’s return on investment.

157. Chevron proposed that we increase its reported total processing costs by including all turnaround expenses in 2001. [Confidential Transcript Vol. V, p. 1016; Confidential Exhibit 204, p. 1]. We have already found that it is more reasonable to amortize the turnaround expenses over a minimum three years, as Chevron did when it reported using the proportionate profits method. Supra, ¶75. We did not increase Chevron’s total processing costs to include an allowance for overhead, as we did for RME. Chevron’s representative did not request such an allowance [Confidential Transcript Vol. V, pp. 1010-1022], and our review of the joint interest billings indicated that Chevron already included overhead in its computation of plant processing costs. Infra, ¶116.

158. We combined the information for each taxpayer to estimate an overall implied rate of return for the plant, exclusive of the interest of Forest Oil. In doing so, we eliminated the overhead credit from BP’s processing costs [Confidential Exhibit BP-2], and eliminated the overhead charges included in RME and Chevron’s processing costs, because we believed the elimination of these internal transfers improved the accuracy of the comparison of revenues and costs. The overhead amount we eliminated from Chevron’s processing costs was equal to its ownership share times the total L00001 entries in the joint interest billings, or $439,828. [Exhibit 975]; supra, ¶108.

159. For our comparison of plant revenues and plant costs, we reached the following consolidated amounts:

Total surrogate plant revenue, as adjusted	$42,845,748
Total surrogate plant costs, including depreciation	$25,353,413
Total un-depreciated asset balance	$139,563,495

160. We can illustrate the general effect of eliminating gathering costs from processing costs by eliminating the 26% of operating costs associated with the Gas Collection System invoices. See supra, ¶127. If we do so, we reach a consolidated rate of return of 15.0%. This illustration shows that if we had made a further adjustment, the result would have favored the Department’s position. We are mindful that gathering system costs are only a portion of the Gas Collection System invoices.

161. For the plant owners individually and together, we find that plant revenues from the 25% processing fee enabled the plant owners to recover plant operating expenses.

Did the Petitioners demonstrate that the Department improperly applied the comparable value method by its selection of sources of comparable value?

162. The taxpayers ask that the Board view each of the Department’s selected comparable contracts in light of numerous criticisms. The taxpayers rely principally on the evidence of witnesses who testified for BP. Those witnesses were:

Rebecca Leo, a retired Amoco lawyer. Leo was employed during the period when the C&O Agreement was negotiated. [Transcript Vol. I, pp. 130-131].

Clyde Miller, BP’s Commercial Engineer. Miller is currently responsible for contract management, oversight of joint interest accounting, and new business development for the Whitney Canyon plant. He is the BP employee most knowledgeable about BP contracts. [Miller Direct, Questions 3,7,9].

Neil Bidwell, BP’s Overthrust turnaround manager and project engineer. BP’s Overthrust area includes the Whitney Canyon Plant. [Bidwell Direct, Question 1].

Lisa Adair, who performs analysis of economic and technical issues in the energy industry. [Adair Direct, Questions 1-3].

Joseph Wilkinson described himself as an industry expert who provides Dispute and Financial Advisory Services to many energy companies. [Wilkinson Direct, Question 4]. He was retained by Petitioners “to provide an opinion on whether fair cash market value at the wellhead of the Whitney Canyon production in 2001 can be achieved by using the ‘comparable value methodology’ and particularly, applying the 25 percent processing deduction allowed by the DOR.” [Wilkinson Revised Direct, Question 12].

163. The Taxpayers’ Revised Proposed Findings of Fact have generally served as our guide to the specific matters on which the taxpayers rely for their position that the Department misapplied the comparable value method. We note that many fact issues that might have been embraced by the initial statements of the parties were not in dispute after the close of evidence. For example, there is no dispute that Merit gas is of like quality compared to the gas of the Petitioners. [Transcript Vol. II, p. 226].

164. Miller testified that the original business plans and forecasts for the Whitney Canyon plant did not prove to be accurate. [Miller Direct, Questions 121, 122]. Ms. Adair elaborated on this testimony with an opinion that the C&O Agreement, together with business assumptions that would have supported it, are now far out of date from the perspective of current market conditions. [Adair Direct, Question 30]. Neither view was supported by documentation from the period.

165. We find that this testimony of original plans and forecasts to be unpersuasive as a criticism of the Department’s use of the comparable value method. We have already found that the 25% processing fee covered the plant owners’ processing costs, and that the contracts which are the source of the processing fee were still effective in production year 2001. In doing so, we further find that Miller and Adair urge a perspective that ignores the many facts now at our disposal, and does so to a degree that suggests bias.

166. Leo testified that none of the taxpayers is a third party or third party producer with respect to the plant owners. [Leo Direct, Questions 2, 18]. This opinion is a view on a legal question rather than a fact, and we will address it as such. Infra, ¶¶314-315.

167. Leo testified that the 25% processing fee is just taking money “from one pocket and putting it in another pocket, and it is just not that important for purposes of the profitability of the parties.” [Transcript Vol. I, p. 166; likewise, Syring Direct, Question 17]. We have already rejected the one-pocket-to-the-other analysis. Supra, ¶89. We also find that the taxpayers’ beliefs about profitability of the plant have no bearing on whether the plant owners’ operation of the plant generates sufficient revenue to cover their costs.

168. Miller testified that the C&O Agreement does not allow the plant operator a profit component. [Miller Direct, Question 145]. The plant operator’s compensation has no bearing on whether the plant owners’ operation of the plant covers their costs and provides a return on their investment.

169. Leo testified that the C&O Agreement reflects nothing more than an agreement of the producers who built the plant to process their own gas from dedicated acreage, with the opportunity to process gas outside the dedicated acreage if capacity was available. [Leo Direct, Question 9]. In 2001, there was no longer a question of opportunity. The plant processed gas from outside the dedicated acreage, and capacity was available.

170. Leo testified that the C&O Agreement does not create a partnership or any other separate legal entity under Wyoming law. [Leo Direct, Question 5]. Miller similarly testified that he is unaware of “a partnership of any kind owning [the Whitney Canyon plant] assets.” [Miller Direct, Question 102]. This testimony addressed a finding the Board made in Whitney Canyon 2000, ¶8, based on the information available to the Board at that time. [See taxpayers’ opening statement, Transcript Vol. I, pp. 28-29]. Most of that information remains true: for example, the C&O Agreement still provides that, “[t]he Owners hereto recognize that this Agreement creates a partnership for tax purposes.” [Exhibit 920, Section 16.4 and Exh. G]. We note that the existence of a partnership was not an issue identified by the parties in advance of the hearing of Whitney Canyon 2000, nor did the taxpayers seek a rehearing from the Board to correct a finding that they believed to be in error. [Board Record, Whitney Canyon 2000].

171. Leo’s understanding is based on attorney staff meetings at Amoco during the time when the C&O Agreement was negotiated. [Transcript Vol. I, pp. 131, 152-153]. Frank Hauck, the staff attorney who represented Amoco on the C&O Agreement drafting team, is deceased. [Transcript Vol. I, pp. 131-132].

172. We accept Leo’s testimony that Amoco “made some effort to avoid creating legal relationships” as a reflection of Amoco’s intention to avoid the creation of a partnership [Transcript Vol. I, pp. 132-133], although her testimony must be weighed against the fact that the C&O Agreement obviously creates a legal relationship between the parties to that contract. Nonetheless, Leo is not in a position to provide us a complete picture of the transaction. She has no knowledge regarding the creation of the tax partnership referenced in the C&O Agreement; a “tax partnership was considered a different animal,” and was handled by a separate tax department in Amoco. [Transcript Vol. I, pp. 173-174]. She freely admits that she is neither a tax lawyer nor familiar with Wyoming tax law, her specialty being royalties. [Transcript Vol. I, pp. 143, 157]. BP did not call a tax lawyer.

173. Leo did not characterize the bundle of rights associated with the C&O Agreement, other than to insist that those rights did not amount to a legally recognized entity. [Transcript Vol. I, p. 159]. For example, she did not know how to characterize the plant for property ownership purposes. [Transcript Vol. I, p. 158].

174. Leo nonetheless agreed to certain aspects of the rights created by the C&O Agreement. She agrees that the Exhibit F processing agreement distinguishes the roles of owners and producers. [Transcript Vol. I, p. 165]. She agrees that the parties to the Exhibit F Processing Agreement have the ability to enforce rights against one another. [Transcript Vol. I, pp. 169-170]. She agrees that BP, as operator to the Whitney Canyon plant, acts on behalf of all four owners – that the owners are a team and BP is the team captain. [Transcript Vol. I, p. 159]. She agrees that the owners each have a vote as the means to assert their views about how the plant should be run, and that each owner’s vote is commensurate with its undivided ownership interest. [Transcript Vol. I, pp. 161, 177]. These undivided ownership interests can be transferred by an assignment and bill of sale made subject to existing agreements. [Transcript Vol. I, pp. 177-178]. We find this testimony to be credible.

175. The Department was not concerned with defining a legal entity, much less a partnership, but simply viewed the plant owners together as separate and distinct from each individual producer. [Transcript Vol. V, pp. 855-856]. The Department considered the existence of a partnership or other business entity to have arisen entirely from the Board’s findings, rather than from its own analysis. [Transcript Vol. V, p. 856].

176. Petitioners generally criticize the Department’s use of the Exhibit F Processing Agreement by asserting that it is not an arms-length agreement, or a third party agreement. [E.g., Miller Direct, Question 117; Leo Direct, Questions 17-18]. However, despite some contradictory testimony from the Petitioners based upon distinctions too strained to be credible, no one questions that the C&O Agreement was itself an arms-length agreement. [Miller Direct, Question 117; Transcript Vol. II, p. 236]. Since the Exhibit F Processing Agreement was an element of the C&O Agreement, and executed as a part of the C&O Agreement, we find that the Exhibit F Processing Agreement was also an arms-length agreement. Lay and experts opinions to the contrary are merely statements of the Petitioners’ legal position, and are not credible.

177. As we briefly noted, the Department had sound reasons for considering the co-owners of the Whitney Canyon plant to be arms-length parties. Supra, ¶40. No co-owner was an affiliate of another co-owner. [Bolles Direct, p. 27]. The co-owners negotiated the C&O Agreement when it was first written, and must continue to do so for amendments. [Bolles Direct, p. 27]. The C&O Agreement contains language that indicates the parties acted in an arms-length manner. [Bolles Direct, pp. 27-29]. The co-owners generally competed with one another for supply, production, transportation, and marketing of gas. [Bolles Direct, p. 27].

178. The Department introduced evidence intended to show that in the years before 1990, Amoco sought to use the 25% processing fee as the measure of its processing deduction. [Bolles Direct, pp. 32-33; Exhibits 524, 525]. Amoco elicited testimony that the Department of Audit refused to allow the fee, and instead audited to actual costs. [Transcript Vol. V, pp. 884-885]. We find these facts to be remote in time and related to a statutory regime that was modified in 1990, and so have given these facts no weight in our disposition of this case.

179. Petitioners have also asked us to consider testimony and argument from previous proceedings on the subject of whether the 25% processing fee in Exhibit F is an arms-length fee. [Taxpayers’ Revised Proposed Findings of Fact and Conclusions of Law, ¶¶226-238]. Petitioners made no effort to introduce such materials into the record in this case, and we refuse to consider either the materials, or the related arguments made in Petitioners’ proposed conclusions of law. In addition to our statutory obligation to decide this case based on the record, any consideration of such material works a prejudice to the Department, which cannot respond to the Petitioners’ materials and could not prepare for the Petitioners’ materials. The late references to materials also impair the Board’s ability to make timely enquiry of witnesses with knowledge of such matters.

180. The Wahsatch Gathering System Agreement was a component of a larger transaction involving the development of the Yellow Creek field and a sour gas pipeline from the Yellow Creek property to the Whitney Canyon plant. [Transcript Vol. I, pp. 135-136]. Amoco owned the Yellow Creek property, which is located close to Evanston, Wyoming. [Transcript Vol. I, p. 135]. Amoco “felt it was too dangerous to develop,” but UPRC was willing to assume the risk. [Transcript Vol. I, pp. 135, 176]. As part of a transaction in which UPRC acquired Yellow Creek from Amoco, Amoco proposed to the plant owners, including UPRC, that UPRC would get a Whitney Canyon processing agreement. [Transcript Vol. I, pp. 135-136]. Both plant owners preferred to reap the benefit of the Yellow Creek processing fees at Whitney Canyon, rather than letting the gas be processed at Carter Creek. [Transcript Vol. II, p. 277]. We find this testimony to be credible.

181. Taking the history into account, we nonetheless find that the Wahsatch Gathering System Agreement is a suitable source for determining comparable value. We doubt the contention that the contract was unduly favorable, particularly in view of BP testimony that the costs associated with processing the Wahsatch gas are less than for other gas. Infra, ¶183. To the extent that the original processing fee was in some way preferential, that preference must be viewed in the context of the plant owners’ common interest in securing processing revenue from the Wahsatch production, and in light of the costs of transporting the Wahsatch gas to Whitney Canyon. As important, this history has generally ceased to be of interest. By 2001, the reciprocal rights established by the gas processing agreement were no longer contingent upon aspects of the earlier global transaction; a contractual 40 BCF residue limit was achieved in 1999. [Miller Direct, Question 45]. The Wahsatch producer was no longer a plant owner. Supra, ¶14.

182. Despite the regular transactions under the Wahsatch Agreement, taxpayers’ witness Adair opined that the Agreement was too old to be representative of current market conditions. [Adair Direct, Question 33]. We find that the regular transactions in 2001 were indicative of present market value, but Adair’s speculation about the motivations of the parties in 1982 was not. [Adair Direct, Question 33]. In particular, we note that Adair provides us with only parts of the picture. She testified to 1982 forecasted prices for gas, without corresponding forecasts for operating costs; she relied on information received at several levels removed from the original sources, without supporting documentation. [Adair Direct, Question 33]. However, even if we had such history reliably at hand, Adair would have to provide more than history to persuade us that the 25% had ceased to be an appropriate measure of costs for production year 2001. Adair’s position seems particularly doubtful when we know that Chevron relied on the 25% processing fee to report its production under the 1995 Chevron Agreement.

183. The Wahsatch producer compressed and separated its gas before that gas joined the process stream at the Whitney Canyon plant. [Bidwell Direct, Questions 19, 39, 40; Miller Direct, Questions 55-56]. It follows that the Wahsatch producer received less service from the Whitney Canyon plant for its 25% fee than the other producers received. [Miller Direct, Question 57]. Bidwell argued that 40% of the cost of plant operation was in compression and separation services that Wahsatch did not receive. [Transcript Vol. I, p. 62]. He argued that 35% more of the cost of plant operation was in labor that had to be in place to service gas from the Whitney Canyon field, such that “no additional labor is necessitated in processing any other gas in the plant.” [Transcript Vol. I, p. 62]. Bidwell concluded that “almost all of [the plant owners’] processing fee would be pure profit.” [Bidwell Direct, Question 56].

184. Bidwell’s arguments did not tie to any cost documentation, and Miller testified that there is no way to pull Wahsatch expenses out of the joint interest billings. [Transcript Vol. II, p. 255]. Bidwell also assumed that field compression services and gathering services were properly included in deductible processing costs, an assumption we reject. Supra, ¶¶125-128. The record does not include enough information for us to evaluate the magnitude of the difference between the costs incurred by Whitney Canyon field producers and the costs incurred by the Wahsatch producer, but we do not find the difference to be a compelling concern in any event.

185. We accept the general proposition that the Wahsatch producer received less service for its fee than other producers. Even if the Wahsatch producer received less service for its fee than other producers, Petitioners did not persuade us that the Wahsatch Gathering System Agreement cannot be a source of comparable value. A purchaser of services commonly cannot avail itself of the full range of services included in a package of services that has a set fee, even though another purchaser may be able to enjoy all of the benefits of the package. Similarly no one testified that the Wahsatch producer needed these additional services, but was deprived of them. We find it likely that separation and compression were essential for cost-effective transportation of gas from the Yellow Creek property to the Whitney Canyon plant. [See Transcript Vol. II, p. 254 about Wahsatch corrosion problems].

186. There is no question that the Wahsatch producer incurred more expense to get to the plant inlet than Whitney Canyon field producers; Ostroff testified that RME’s total Wahsatch fees, wellhead-to-tailgate, approached 51% in 1999. [Transcript Vol. III, p. 506]. The fact that the Wahsatch producer has higher costs to reach the tailgate of the plant does not persuade us that the Wahsatch costs must be viewed as unique or unrepresentative. Wahsatch merely incurred costs that the Whitney Canyon field producers did not incur.

187. Petitioners next argued that, because the Wahsatch gas receives fewer processing services, it is of higher quality, and therefore not of like quality. [Miller Direct, Question 59]. For the purposes of applying the comparable value method, it is enough that gas has been processed in the same plant without substantial special adjustment to the plant operations. [Compare Bidwell Direct, Question 16]. Moreover, the quality of gas in the Whitney Canyon field varies from well to well, infra, ¶¶198-199, which implies that gas from some Whitney Canyon wells places greater demands on the plant than gas from other wells, although all gas is subject to the same fee of 25%. We find the Department’s focus on the consistency in the processing fee for gas from this plant is more compelling than the Petitioners’ focus on the ways in which one might describe the Wahsatch gas as different.

188. We likewise disagree that Wahsatch gas cannot be the source of a comparable value because the plant curtailed production of Wahsatch gas more frequently than other gas. These curtailments were attributed to excess water, and to maintenance and operational capacity limitations of the plant. [Bidwell Direct, Question 46; Transcript Vol. I, pp. 89-90]. The excess water problem was “a real problem for a month,” then the producer fixed its own operations to cure the difficulty. [Transcript Vol. I, pp. 89-90]. Bidwell could not otherwise quantify the effect of maintenance issues without looking at records [Transcript Vol. I, p. 94], and no such records were introduced. Neither excess water nor maintenance were aspects of the plant turnaround, another source of curtailments. The turnaround was necessary because the plant had reached the end of its original design life of twenty years, and required extensive refurbishment. [Transcript Vol. I, pp. 86-87]. Taxpayers have not persuaded us that these operational concerns were more important than the pattern of processing fees in the Whitney Canyon processing agreements.

189. BP witnesses testified that Wahsatch gas production is falling, and is unlikely to extend the Plant’s life beyond 2005. [Transcript Vol. I, pp. 77-78; Miller Direct, Questions 49-53]. We find that this concern has little bearing on production year 2001, and is at odds with turnaround investments intended to last through 2008. [Transcript Vol. I, p. 87]. Forecasts about the Whitney Canyon plant have been unreliable in any event. [Miller Direct, Questions 121-122]. Forecasts are broadly helpful for our understanding of the plant and its operations, but of little value for disposing of the issues presented by this case.

190. Miller testified that the Merit Agreement should be disregarded because Merit’s gas is captive, i.e., Merit had no alternative for processing the gas. [Transcript Vol. II, p. 219; Leo Rebuttal, Question 3]. However, the plant owners were themselves constrained, by practical and legal considerations that included antitrust concerns, from charging Merit a higher fee. [Miller Direct, Question 78; Transcript Vol. II, pp. 250, 274]. The fact that one or both parties to an agreement were, and still remain, under practical negotiating constraints does not make the contract any less valid and enforceable.

191. The Merit processing agreement was the only one with a processing fee that includes 100% of sulfur produced. [Miller Direct, Question 85]. The origin of this provision was the plant owner’s desire to control such a small portion of the total sulfur. [Transcript Vol. II, pp. 265-266]. Sulfur also generated losses for the other producers in 2001, which we take to be a fair measure of its economic value. [Transcript Vol. II, p. 265]. The unique arrangement for sulfur in the Merit contract does not persuade us that the Merit contract must be disregarded as a source of comparable value.

192. Petitioners’ principal point regarding Merit concerns volume. All of Petitioners’ witnesses characterize the volume of Merit gas as insignificant. [E.g., Miller Direct, Question 80; Transcript Vol. I, p. 149, Vol. II, p. 342, Vol. IV, p. 652]. Miller concluded that the Merit gas is therefore not of like quantity when compared to that of taxpayers. [Miller Direct, Question 83]. We nonetheless agree with the Department that quantity did not affect pricing terms. Supra, ¶43.

193. The taxpayers have assumed but not demonstrated that comparisons of processing agreements must be based on aggregated volumes. Miller asserted without explanation that, “in terms of processing agreements, you look at the total volume being committed.” [Transcript Vol. I, p. 225]. Syring spoke from the perspective of comparing overall market value of BP gas to Merit gas, but this is merely one perspective. [Transcript Vol. II, pp. 341-342]. Wilkinson adopts the views of Petitioners’ other witnesses, without offering a rationale of his own. [Transcript Vol. pp. 714-716].

194. In contrast, the Whitney Canyon and Carter Creek plants, managed by different operators, have consistently competed for additional volumes of gas to process, including small volumes. Amoco supported development of the Wahsatch Gas project to capture incremental revenues. [Miller Direct, Question 43]. Wahsatch gas was exclusively committed to Whitney Canyon, even though Miller minimized the possibility of competition from Carter Creek. [Transcript Vol. II, pp. 206, 258]. The plant operators have both sought to process gas from two wells that could be sent to either plant. [Transcript Vol. II, pp. 203-204]. More generally, Miller acknowledged that even modest volumes of additional gas were desirable, and that an agreement with Merit was better than no agreement. [Transcript Vol. II, p. 249].

195. The question of like quantity takes on a different complexion when viewed in the context of the unit by which Petitioners actually report their production, which is the Mineral Group. The Mineral Group is often associated with individual wells, and is likewise the pertinent unit for appeal purposes. Supra, ¶¶70, 81-86. Merit produces 32.5% of the gas from the Champlin 505B1 well. [Miller Direct, Question 85]. Thirty-two point five percent is a significant percentage in the context of that Mineral Group.

196. If we focus on individual Mineral Groups rather than on an aggregation of Mineral Groups associated with the plant, the Department’s point about the consistency of the 25% fee becomes stronger. It is clear that the fee is a constant despite wide variations in the quantity and quality of gas produced from individual Mineral Groups, and from individual producers.

197. The Department’s summaries of each Petitioner’s annual reports demonstrated the wide variation in quantities produced from Mineral Groups. [Confidential Exhibits 504, 506, 508]. For example, the volume that BP reported for its Mineral Group with the largest volume was millions of times larger than the reported volume of its smallest. [Confidential Exhibit 504].

198. The same summaries also demonstrated wide variation in quality, in the form of sales price per unit of sales volume. [Confidential Exhibits 504, 506, 508 (comparison of columns entitled “G Sales Vol” and “G Sales Val”)]. For example, BP’s reported unit price received for Mineral Group 1024 was more than double the unit price received for its production from Mineral Group 1028, with unit prices for BP’s other Mineral Groups being well distributed between these two extremes. [Confidential Exhibit 504]. Similarly, there was a five-fold unit price difference between two Chevron Mineral Groups, and a four-fold unit price difference between two RME Mineral Groups. [Confidential Exhibits 506, 508].

199. We find generally that the variations in price per unit of volume related principally to differences in the methane content of gas produced from each well. The plant operator informed the plant owners of these differences with a plant allocation statement. [Transcript Vol. V, p. 543]. As Adair put it, the dollars attributable to specific gas streams vary widely. [Transcript Vol. IV, pp. 649-650]. However, because different taxpayers received different prices for their gas, the taxpayers reported different unit prices even for production from the same Mineral Group. [Confidential Exhibits 504, 506, 508; e.g., Mineral Group 1031].

200. Petitioners have asked us to consider legal argument from previous proceedings on the subject of the Department’s previous interpretation of the comparable value statute, including aspects of the “like quantity” words of the statute. [Taxpayers’ Revised Proposed Findings of Fact and Conclusions of Law, ¶¶199, 201, 207]. Petitioners made no effort to introduce the referenced materials into the record in this case, and we refuse to consider either the materials or related arguments made in Petitioners’ proposed conclusions of law. See supra, ¶179.

201. Miller sought to distinguish the 1995 Chevron agreement based on a history going back to 1982, before either Whitney Canyon or Chevron’s Carter Creek plant were in operation. [Transcript Vol. II, p. 189]. In that era, Amoco and Chevron were commercially hostile. [Transcript Vol. I, p. 223]. According to Miller, the enmity arose over a disagreement about how best to process gas from the adjoining Whitney Canyon and Carter Creek fields. [Transcript Vol. II, pp. 263-264]. Amoco and all other producers but Chevron favored a single large facility; Chevron insisted on building its own Carter Creek plant. [Transcript Vol. II, pp. 263-264]. So, when Chevron sought to process its gas at the Whitney Canyon plant, the plant operator charged Chevron a 50% processing fee. [Transcript Vol. II, p. 189].

202. By the middle of the 1990's, following Chevron’s acquisition of the Gulf ownership interests in 1985, relations between Amoco and Chevron had thawed. [Transcript Vol. II, p. 223]. When the 1995 Chevron processing agreement was negotiated, the parties removed the dedication requirement from the pre-Gulf gas, and made the gas second priority. [Miller Direct, Question 163]. Chevron could thereafter take a portion of the gas covered by the 1995 Agreement to Carter Creek for processing, and did so as part of swap arrangement. [Transcript Vol. II, pp. 203, 228].

203. Nothing in the history of the 1995 Chevron Agreement caused us to doubt the rights established by the 1995 Chevron Agreement, or otherwise persuaded us that it cannot be used as source of comparable value.

204. Miller testified that the processing priority of Chevron’s gas was originally third priority, but later became second priority. [Miller Direct, Questions 161, 169]. He also testified that on a day to day basis, priority didn’t mean anything in terms of determining the rights of the parties, and didn’t have any impact on the processing fee. [Transcript Vol. II, p. 234]. Within the Whitney Canyon field, the plant’s reservoir engineer shut in Whitney Canyon wells based on well characteristics, not contact terms. [Transcript Vol. I, pp. 95-96]. Further, in a well in which Merit held a stake, there were four different producers, and hence four different priorities. [Transcript Vol. II, pp. 217-218]. Miller also conceded that priority doesn’t affect the processing fee. [Transcript Vol. II, p. 198]. The Petitioners have not proven that concerns about contractual priorities are sufficiently significant that, taken alone, contractual priorities should be a cause for disregarding the 1995 Chevron Agreement, or the Merit agreement, as a source of comparable value.

205. However, we accept Leo’s testimony that priorities are commercially significant. [Transcript Vol. I, pp. 133-134].

206. Miller testified that during 2001, the Whitney Canyon plant processed an average of 500 MCFD of 1995 Chevron Agreement gas. [Miller Direct, Question 175]. This cannot be squared with the total volume of 5.13% of all gas processed. Supra, ¶91. We take Miller’s statement to be either limited to a single one of the four wells from which 1995 Chevron Agreement gas is produced, the Cummins Federal, or to be a comment on production levels when he testified in 2004. [See Miller Direct, Questions 166, 168; Transcript Vol. I, p. 191]. We disagree with the conclusion that the quantity of production under the 1995 Chevron Agreement is cause for disregarding the Agreement as a source of comparable value, both due to BP’s understated characterization of the volumes in question, and for the same reasons that we stated regarding the Merit Agreement. Supra, ¶¶192-199.

207. The Carter Creek Mutual Backup Agreement provides for short term processing during plant shutdowns, on a third priority basis. [Miller Direct, Questions 188, 195]. The Carter Creek plant processed Whitney Canyon gas during the Whitney Canyon turnaround in 2001. [Transcript Vol. I, p. 65]. The fee for that processing was 20% in-kind if no inlet compression was used, and 22% if inlet compression was used. [Miller Direct, Question 184].

208. The Petitioners testified to a number of circumstances that they say distinguish the Mutual Back-up Agreement from the other gas processing agreements. Miller argued that the Mutual Backup Agreement cannot be a comparable because Chevron is an owner of both plants; because it is temporary; because no other facilities are available to either plant in the event of a shutdown; because there is a reciprocal fee; and because the agreement has been used infrequently. [Miller Direct, Questions 109, 191; Transcript Vol. I, p. 192].

209. Although there are elements of truth in Miller’s testimony, we did not find the items he listed to be impediments to use of the Mutual Back-up Agreement as a source of comparable value. Generally speaking, we find that the terms and conditions of the Mutual Backup Agreement differ from those of the other processing agreements, but these differences are reflected in the processing fee. The Department recognized these differences by determining that the appropriate processing fee for Whitney Canyon production was 25%.

210. However, we are not prepared to accept the Mutual Back-up Agreement as a source of comparable value, because we do not have an adequate evidence of the contractual obligations that support the Department’s position. The parties to the Mutual Back-up Agreement were Amoco, as operator of the Whitney Canyon plant, and Chevron, as operator of the Carter Creek plant. [Exhibit 927]. The plant that processes gas supplied by the producer is defined as the processor. [Exhibit 927]. However, the producer is defined as the well operator that produces gas to the other plant. [Exhibit 927]. In this respect, the Mutual Back-up Agreement is unlike any of the other gas processing agreements that the Department identified as a comparable.

211. The record does not include any evidence that enabled us to determine with certainty how the fee paid by the well operator becomes an obligation of a particular producer. Given BP’s testimony that the Whitney Canyon plant takes custody of field gas at the wellhead, supra, ¶125, the answer for the Whitney Canyon field may simply be that the C&O Agreement controls, but we do not know that this is so. However, even if we make this assumption, it is not clear who the well operator would be for the Wahsatch gas. While we are aware of the basic mechanics of billing and accounting arrangements for the Whitney Canyon plant, e.g., supra, ¶¶8, 10, 108, we do not have enough information to determine how or whether the same arrangements were used to bill and account for gas processed at Carter Creek during the turnaround.

212. Without the final link to a producer, we are uncertain about what party is actually paying a processing fee, a fact which we believe to be a prerequisite for application of the comparable value method. We are not prepared to assume that the well operator and the producer are one and the same. The Department’s arguments glossed over this problem. [Wyoming Department of Revenue’s Proposed Findings of Fact and Conclusions of Law, ¶178].

213. We find that the Mutual Back-up Agreement lends support to the Department’s general position, but cannot agree that it is a comparable.

214. Under the Gas Processing Agreement attached to the C&O Agreement as Exhibit F, BP is a Producer separate and distinct from the Plant Owners identified in the same Gas Processing Agreement. [Exhibit 920]. The Plant Owners are likewise separate and distinct from BP as a Producer. BP’s rights and responsibilities as Producer, with respect to the Plant Owners, are established by the Gas Processing Agreement.

215. Under the Gas Processing Agreement attached to the C&O Agreement as Exhibit F, Chevron is a Producer separate and distinct from the Plant Owners identified in the same Gas Processing Agreement. [Exhibit 920]. The Plant Owners are separate and distinct from Chevron as a Producer. Chevron’s rights and responsibilities as Producer, with respect to the business entity of Plant Owners, are established by the Gas Processing Agreement.

216. Under the Gas Processing Agreement attached to the C&O Agreement as Exhibit F, RME is a Producer separate and distinct from the Plant Owners identified in the same Gas Processing Agreement. [Exhibit 920]. The Plant Owners are likewise separate and distinct from RME as a Producer. RME’s rights and responsibilities as Producer, with respect to the business entity of Plant Owners, are established by the Gas Processing Agreement.

217. With respect to BP as a Producer under its Exhibit F Gas Processing Agreement, we find that the Exhibit F Gas Processing Agreement of Chevron, as a Producer, is a reliable source of information, or a comparable, from which the Department could infer and impute a reasonable processing fee which would be paid by an other party for processing of gas of like quantity, taking into consideration the quality, terms and conditions under which the gas was processed. The same is true of the Exhibit F Gas Processing Agreements of RME, as a Producer, and Forest Oil, as a Producer. That fee is an in-kind processing fee of 25% of the plant production recovered during each settlement period, and attributable to the Producer in question. Sufficient similarity in quantity is assured by the fact that the fee provided in the comparable Exhibit F Gas Processing Agreements does not vary with respect to production. Sufficient similarity in quality is assured by the fact the gas processed in the plant is commingled, and the measure of the fee is the product(s) recovered after processing. Sufficient similarity of terms and conditions is assured by the identical terms and conditions of the Exhibit F Gas Processing Agreements.

218. With respect to Chevron as a Producer under its Exhibit F Gas Processing Agreement, we find that the Exhibit F Gas Processing Agreement of BP, as a Producer, is a reliable source of information, or a comparable, from which the Department could infer and impute a reasonable processing fee which would be paid by an other party for processing of gas of like quantity, taking into consideration the quality, terms and conditions under which the gas was processed. The same is true of the Exhibit F Gas Processing Agreements of RME, as a Producer, and Forest Oil, as a Producer. That fee is an in-kind processing fee of 25% of the plant production recovered during each settlement period, and attributable to the Producer in question. Sufficient similarity in quantity is assured by the fact that the fee provided in the comparable Exhibit F Gas Processing Agreements does not vary with respect to production. Sufficient similarity in quality is assured by the fact the gas processed in the plant is commingled, and the measure of the fee is the product(s) recovered after processing. Sufficient similarity of terms and conditions is assured by the identical terms and conditions of the Exhibit F Gas Processing Agreements.

219. With respect to RME as a Producer under the Exhibit F Gas Processing Agreement, we find that the Exhibit F Gas Processing Agreement of BP, as a Producer, is a reliable source of information, or a comparable, from which the Department could infer and impute a reasonable processing fee which would be paid by an other party for processing of gas of like quantity, taking into consideration the quality, terms and conditions under which the gas was processed. The same is true of the Exhibit F Gas Processing Agreements of Chevron, as a Producer, and Forest Oil, as a Producer. That fee is an in-kind processing fee of 25% of the plant production recovered during each settlement period, and attributable to the Producer in question. Sufficient similarity in quantity is assured by the fact that the fee provided in the comparable Exhibit F Gas Processing Agreements does not vary with respect to production. Sufficient similarity in quality is assured by the fact the gas processed in the plant is commingled, and the measure of the fee is the product(s) recovered after processing. Sufficient similarity of terms and conditions is assured by the identical terms and conditions of the Exhibit F Gas Processing Agreements.

220. For all three taxpayers, as Producers, the Wahsatch Gathering System Agreement is a reliable source of information, or a comparable, from which the Department could infer and impute a reasonable processing fee which would be paid by an other party for processing of gas of like quantity, taking into consideration the quality, terms and conditions under which the gas was processed. [Exhibit 924]. That fee is an in-kind processing fee of 25% of the plant production recovered during each settlement period, and attributable the Wahsatch Gathering System interests. Sufficient similarity in quantity is assured by the fact that the maximum processing fee required (except with regard to sulfur) during 2001, under any known gas processing agreement related to Whitney Canyon, was 25%. Sufficient similarity in quality is assured by the fact the gas processed in the plant is commingled, and the measure of the fee is the product(s) recovered after processing. Sufficient similarity of terms and conditions is assured by comparison of the terms and conditions of the Exhibit F Gas Processing Agreements of the Producers and the terms and conditions of the Wahsatch Gathering System Agreement. [Exhibits 920, 924].

221. For all three taxpayers, as Producers, the Merit Agreement is a reliable source of information, or a comparable, from which the Department could infer and impute a reasonable processing fee which would be paid by an other party for processing of gas of like quantity, taking into consideration the quality, terms and conditions under which the gas was processed. That fee is an in-kind processing fee of 25% of the plant production recovered during each settlement period, and attributable to Merit. [Exhibit 928]. Sufficient similarity in quantity is assured by the fact that the maximum processing fee required (except with regard to sulfur) during 2001, under any known gas processing agreement related to Whitney Canyon, was 25%. Sufficient similarity in quality is assured by the fact the gas processed in the plant is commingled, and the measure of the fee is the product(s) recovered after processing. Sufficient similarity of terms and conditions is assured by comparison of the terms and conditions of the Exhibit F Gas Processing Agreements of the Producers and the terms and conditions of the Merit Agreement. [Exhibits 920, 928].

222. For BP and RME, as Producers, the 1995 Chevron Agreement is a reliable source of information, or a comparable, from which the Department could infer and impute a reasonable processing fee which would be paid by an other party for processing of gas of like quantity, taking into consideration the quality, terms and conditions under which the gas was processed. That fee is an in-kind processing fee of 25% of the plant production recovered during each settlement period, and attributable to the Chevron interests covered by the 1995 Chevron Agreement. [Exhibit 963]. Sufficient similarity in quantity is assured by the fact that the maximum processing fee required (except with regard to sulfur) during 2001, under any known gas processing agreement related to Whitney Canyon, was 25%. Sufficient similarity in quality is assured by the fact the gas processed in the plant is commingled, and the measure of the fee is the product(s) recovered after processing. Sufficient similarity of terms and conditions is assured by comparison of the terms and conditions of the Exhibit F Gas Processing Agreements of BP and RME as Producers and the terms and conditions of the 1995 Chevron Agreement. [Exhibits 920, 963].

Did the Petitioners demonstrate that the Department erred by not applying general appraisal principles when determining the value of Petitioners’ production using the comparable value method?

223. In determining the value of Petitioners’ minerals, the Department did not consider itself to be an appraiser and did not use the guidelines which an appraiser would use. [Transcript Vol. IV, p. 835]. Taking this fact as a key premise, the Petitioners mounted a number of attacks on the Department’s use of the comparable value method.

224. Petitioners direct our attention to a February 1, 1990, Memorandum to Members of the Fiftieth Wyoming Legislature from the Chairman of the Joint Interim Revenue Committee. [Exhibit 974]. In pertinent part, the Memorandum states:

The Committee spent a great deal of time receiving testimony and analyzing various appraisal methods that could be used for valuing WYOMING’S minerals. The Committee felt that the “proportionate profits” method was best suited to the valuation of coal, while the valuation of oil and gas could be developed using any one of the four valuation methods. It is the feeling of the Committee that the methods approved for coal, uranium and oil and gas meet the uniform and equal requirements of the Constitution and also meet professional valuation standards.

[Exhibit 974, p. WC 0668]. BP stated that the Legislature “intended for the use of the definitions of these terms as it pertains to the practice of appraising properties.” [Syring Direct, Question 45]. We understand this difficult locution to argue that the Department must overlay the four statutory methods with professional valuation standards. [Taxpayers’ Revised Proposed Findings of Fact, ¶206].

225. Setting aside the question of whether Exhibit 974 may be considered legislative history, the Memorandum merely stated that each of the four statutory methods – comparable sales, comparable value, netback, and proportionate profits – satisfied professional valuation standards, and that all four methods were suitable for the valuation of oil and gas. We found nothing in the quoted paragraph, or elsewhere in the Memorandum, to the effect that the four methods required further interpretation in light of professional valuation standards, were subject to modification by professional valuation standards, or the like. If anything, the Memorandum persuaded us that the Joint Interim Revenue Committee intended to have the Department apply any one of the chosen valuation methods without further refinement by reference to professional valuation standards.

226. BP’s tax representative testified to his own general understanding of appraisal principles to buttress BP’s restrictive view of the comparable value method. [Syring Direct, Questions 4-6, 27; Transcript Vol. II, pp. 282-284]. However, BP’s tax representative was no more an appraiser than the Administrator of the Mineral Tax Division. [Transcript Vol. II, p. 290]. He conceded that he was not an expert. [Transcript Vol. II, pp. 355-356]. His lay opinions are not entitled to any weight.

227. BP called two industry witnesses, Lisa Adair and Joseph Wilkinson, neither of whom claimed to be a professional appraiser. Supra, ¶162. Both witnesses merely offered an “industry perspective.” [Transcript Vol. IV, p. 640, Vol. IV, p. 702; Wilkinson Direct, Question 4]. In addition to specific points that we have already considered, e.g., supra, ¶¶164-166, 182, each generally criticized the Department’s application of the comparable value method. For example, Adair would have looked for contracts negotiated in 2001, and at market gas prices in 2001. [Transcript Vol. IV, p. 657]. Wilkinson would have searched the industry for standards, methods, or contracts that were “near contemporaneous and similar in terms.” [Transcript Vol. IV, p. 728]. By these general views, neither witness did more than offer a perspective that differed from the perspective of the Department. From our detailed review of their testimony, neither Adair nor Wilkinson persuaded us that the Department’s approach was invalid, or that the Department had misapplied the comparable value method.

Did the Petitioners demonstrate that the values determined by the Department did not reach fair market value?

228. The Petitioners claim that the comparable value method did not reach fair market value, but offered no evidence to measure the proportionate profits method against the same standard. Neither of Petitioners’ witnesses Adair nor Wilkinson, were asked to calculate fair market value of Petitioners’ production, or to evaluate the results of the proportionate profits method. [Transcript Vol. IV, p. 643, Vol. IV, pp. 769, 800].

229. BP’s tax representative testified that the proportionate profits method reached fair market value for production year 2001 simply because it is one of the methods identified by statute. [Transcript Vol. II, pp. 360-361]. The logic of this concession casts doubt on whether, exclusive of the results of a valuation method authorized by statute, fair market value can be demonstrated by opinion testimony, whether lay or expert. The taxpayers nonetheless presented two separate studies intended to demonstrate that the comparable value method did not reach fair market value.

230. An RME study compared the results of several different valuation methods, and measured those results against a netback standard for the period 1990 through 2002. [Corrected Ostroff Direct, pp. 6-14; Rev. Confidential Exhibits RME-1, RME-2, RME-3, RME-4]. As a threshold matter, RME’s comparison of methods is a hypothetical exercise, because the Department did not use comparable value prior to production year 2000. Our concern is principally with what actually occurred in production year 2001, because production year 2001 is the subject of this appeal. Our focus on production year 2001 applies to both of Petitioners’ studies.

231. RME’s representative testified that “the comparable value method is the only method that consistently and uniformly exceeds the valuation produced by the netback method every year, no matter what.” [Corrected Ostroff Direct, p. 11]. To evaluate this testimony, we must again review what version of the netback method was applied.

232. The current statutory netback method contradicts RME’s conclusion that netback and comparable value differ. RME’s representative mistakenly testified that, “[u]nder netback, as defined in Wyoming Statute §39-14-203(b)(vi)(C), the processor’s actual costs of processing and transportation are deducted from the total revenues.” [Corrected Ostroff Direct, p. 6]. The statute refers to “third party processing fees,” not actual costs of processing. Wyo. Stat. Ann. §39-14-203(b)(vi)(C). Taking Chevron’s reporting of production under the 1995 Chevron Agreement since production year 1990 into account, supra, ¶31, we find that the correct processing deduction under the present statutory netback is 25%, or precisely the same as the processing deduction under comparable value.

233. To the extent that RME’s netback analysis is intended to substantiate its position regarding the comparison of plant revenues and plant costs [e.g., Corrected Ostroff Direct, p. 13], we have already found RME’s analysis to be unpersuasive for production year 2001. E.g., supra, ¶¶132-135. RME’s view that the comparable value method “penalizes” the Petitioners, or “exaggerates” taxable value [Corrected Ostroff Direct, pp. 12, 14], is baseless for production year 2001.

234. We do not have sufficient information to evaluate RME’s calculations for years before 2000. Without the means to evaluate RME’s calculations for other years, and being mindful of the shortcomings of RME’s calculations for production year 2001, supra, ¶¶75-77, 111, 132-136, we accord little weight to RME’s calculations for earlier years. However, despite the shortcomings, we note that RME’s calculations show that Whitney Canyon plant revenues exceeded plant costs in production year 2000. [Corrected Ostroff Direct, pp. 7-8; Confidential Exhibit RME-4].

235. RME’s comparison of methods raises the issue of whether any baseline or benchmark can be used for all years in the life of a plant. RME appears to be under the impression that netback can serve that purpose. [Corrected Ostroff Direct, p. 6]. The Department points out that a netback method may be unsatisfactory in the early years of a facility, because a large remaining un-depreciated asset balance can require a return on investment so large that it overwhelms the calculation, yielding an unsatisfactory result. [Grenvik Direct, p. 23]. The Department’s view is persuasive, and RME’s view is not.

236. RME’s analysis also ignores a likely future effect. The Whitney Canyon plant is late in its productive life. Supra, ¶¶75, 146. In a plant’s late years, as the remaining un-depreciated asset balance becomes smaller and smaller, a constant difference between costs and revenues will yield ever larger implied rates of return, because the difference between costs and revenues is being measured against a progressively smaller investment base. In other words, the same margin of revenue over cost will generate increasing rates of return on investment. We can foresee circumstances under which the 25% comparable value processing allowance covers operating costs, depreciation, and a handsome return on the remaining capital investment. Although we cannot and do not find that the difference between costs and revenues will be constant in future years, we nonetheless find that RME’s backward-looking analysis provides an incomplete picture.

237. In the second study, Joseph Wilkinson testified to his opinion that fair cash market value at the wellhead of the Whitney Canyon production in 2001 cannot be achieved by using the 25% processing deduction allowed by the DOR. [Wilkinson Rev. Direct, Questions 14, 15]. The principal grounds for this opinion were that a 25% processing allowance would have equaled only a 6% internal rate of return on investment through 2001. [Wilkinson Rev. Direct, Question 15]. He further testified that comparison with other methods – including his own netback calculation and the Canadian Jumping Pound formula – shows that the 25% fails to achieve fair cash market value “of the production at the wellhead.” [Wilkinson Rev. Direct, Question 15]. We find that neither the opinion, nor the grounds for the opinion, are persuasive.

238. We do not find Wilkinson’s calculations of the plant’s implied rate of return to be a reliable standard of measurement, principally because of the many ways in which his calculations diverge from our own comparison of plant costs and revenues, but for additional reasons as well:

Wilkinson failed to account for the revenue paid to the plant owners under the Wahsatch Gathering, 1995 Chevron, and Merit agreements. [Rev. Exhibit 972, attached Exh. F];

Wilkinson calculated costs on the premise that he was determining value at the wellhead, and has therefore included gathering system costs in his processing costs;

Wilkinson included a annual working capital charge of 15%, calculated against incremental revenue; the charge was not identified as an operating cost by the individual taxpayers, or the Department. [Rev. Exhibit 972, attached Exh. F]. The Department correctly points out that this is not an actual cost;

Most of Wilkinson’s historical data was extrapolated from the web site of the Wyoming Oil and Gas Conservation Commission, rather than being actual data, and he acknowledged that years before 2000 and 2001 are “theoretical.” [Transcript Vol. IV, pp. 753, 782];

Wilkinson’s depreciation estimate was taken on a straight line basis over twenty years, although he acknowledged that the plant had twenty-five years of life. [Transcript Vol. IV, p. 789; Rev. Exhibit 972, attached Exh. F];

Wilkinson added an arbitrary annual cost of $1,500,000 for additional capital expenditures. [Rev. Exhibit 972, attached Exh. F].

239. Like other witnesses, Wilkinson revised his exhibits. He did so in a way that markedly favored the Petitioners. Despite his explanations of the revisions, we found his role to be primarily that of an advocate, rather than a witness called to assist us as trier of fact. Among other things, Wilkinson’s original calculations showed a 29% rate of return on investment in 2000, and a 3% rate of return in 2001, when Wilkinson included nearly $12.5 million of operating costs that were later eliminated from his revised report. [Rev. Exhibit 972, attached Exh. F; Exhibit 972, attached Exh. F]. All annual rates of return were eliminated in the revised report. [Rev. Exhibit 972, attached Exh. F; Exhibit 972, attached Exh. F].

240. We accorded no weight to Wilkinson’s other standards of comparison. Wilkinson acknowledged that the Jumping Pound method [Rev. Exhibit 972] is not authorized by Wyoming statutes. [Transcript Vol. IV, p. 774]. He conceded that the Board could not do anything with the Jumping Pound, and stated that he was just trying to give the Board a different perspective. [Transcript Vol. IV, p. 792]. Wilkinson’s netback calculation assumed a rate of return of 24%; un-depreciated investment; aggregate expenses as provided by BP; and a hidden subsidy in the form of an assumed federal tax rate of 38%. [Rev. Exhibit 972, attached Exh. B; Grenvik Rebuttal, p. 2]. In the end, Wilkinson’s netback calculation was – like Jumping Pound – merely another perspective, not well grounded in either the details of the case or the requirements of Wyoming statute.

Did the Petitioners demonstrate that the Department violated prescribed procedures when determining the value of each Petitioner’s gas production?

241. With the passage of time, the Department has changed its approach to the administration of the comparable value method. In 1992, an Administrator of the Mineral Tax Division issued a formula for determining comparable value. [Exhibit 933]. The approach of that formula was challenged by Amoco and rejected by the Wyoming Supreme Court. Amoco Production Company v. State Board of Equalization, 882 P.2d 866 (Wyo. 1994). The record does not show that the formula in Exhibit 933 was ever successfully used to determine the value of any taxpayer’s oil and gas production, nor does the record show that the formula was ever adopted by rulemaking.

242. For production years 1995 and 1996, the Department had a stated policy for allowing taxpayers to report using the proportionate profits method. On November 30, 1995, the Department issued a Memorandum to all oil and gas producers, entitled “Valuation of Gas for 1995 Production year/Severance and Ad Valorem Tax – Non Arms-Length Transactions.” [Exhibit 938]. The Memorandum referred to the Department’s choice of the comparable value method for production years 1991-1993, and 1994-1996. [Exhibit 938, p. 1]. For taxpayers who attested to the fact that no comparable values existed for their production, the Department authorized the use of the proportionate profits method. [Exhibit 938, p. 1]. A letter to Chevron dated January 31, 1996, underscored the condition that the taxpayer was attesting to the fact that no comparable values existed. [Exhibit 940]. A subsequent letter agreement between the Department and Chevron refers to the Memorandum of November 30, 1995, as “describing how the valuation procedure for the 1995 and 1996 production years would be carried out.” [Exhibit 941].

243. Chevron’s tax representative testified that subsequent valuation directives from the Department were “sent to comply with the Department’s policy as established in November 1995.” [Chambers Direct, Question 69; see Syring Direct, Questions 61-62]. The characterization of the 1995 Memorandum is not supported by the Memorandum itself, by contemporary documents, or by witnesses from the Department. We note that Petitioners’ tax representatives frequently claimed to speak for the Department, when at most they were competent to speak of their own perceptions of Department policy. We have placed little weight on such testimony when it was not supported by contemporaneous documentation, and by the testimony of officials charged with administering the Department.

244. When the Department notified oil and gas producers of its selection of the comparable value method for production years 1997-1999, the Department expressed a similar policy for allowing taxpayers to report using the proportionate profits method. [Exhibit 942]. If the taxpayer attested that no comparable values existed in an “exception letter,” the Department notified the taxpayer that the proportionate profits method was to be used. [Exhibit 942, p. WC0292]. A letter to Chevron dated December 21, 1996, looking forward to valuing production year 1997 as the first year of a three year valuation cycle, underscored the condition that the taxpayer was attesting to the fact that no comparable values existed. [Exhibit 943].

245. When the Department notified oil and gas producers of its selection of the comparable value method for production years 2000-2002, it did not reiterate the attestation/exception letter policy that had been in place for the preceding years. [Exhibit 900]. Instead, the Department’s revised policy was as follows:

In the event the taxpayer has made a determination that a representative Comparable Value does not exist for a specific mineral property the taxpayer shall notify the Department in writing by October 30, 1999. This notification shall include specific justification for that determination. It shall also include the identification, with statutory citation, of the method that the taxpayer proposes to use. The department will respond in writing to the taxpayer on or before December 15, 1999 stating acceptance or rejection of the requested method.

246. BP and Chevron complain that the Department did not continue to use the policy articulated in 1995. [Chambers Direct, Question 53; Syring Rebuttal, Question 10]. BP complains that it never received notice that the November 30, 1995, Memorandum had been revoked. [Syring Direct, Question 73]. BP’s tax representative stated that BP reported its 2001 production using the proportionate profits method because BP “felt there was no change in the policy of the DOR from the 1995 policy statement previously issued by the DOR.” [Syring Direct, Question 101]. From our review of the pertinent documents, we find that the November 30, 1995, Memorandum was not, and did not purport to be of indefinite duration. We find that the policy expressed in the November 30, 1995, Memorandum was never adopted by rule making. The Department’s policy for each separate three-year cycle of valuation method was adequately expressed in contemporaneous documents. We find that the Petitioners’ various complaints to the contrary are groundless.

247. In a similar vein, the Petitioners direct our attention to the fact that audits of production years 1999 and earlier were directed to the taxpayers’ actual costs, an entirely appropriate focus in view of the valuation methods employed for those audited years. [Taxpayers’ Revised Proposed Findings of Fact, ¶¶135-143]. These audits have no discernible bearing on the taxable values determined for production year 2001. The audits were primarily of interest to show that Amoco had reported using the comparable value method in 1990 and 1991. [Transcript Vol. V, pp. 877-880]. While this supports the Department’s position, it is of very modest interest to us.

248. Petitioners also ask that we view the actions of the Department over the decade preceding production year 2001, and find that the Department’s selection of comparable value for 2000-2002 was an abrupt and unwarranted departure from established policies. [Syring Rebuttal, Question 10; Taxpayers’ Revised Proposed Findings of Fact, ¶134]. The record does not support the Petitioners’ view. Petitioners would have us ignore the their dubious attestations to the absence of comparable values [Bolles Direct, pp. 10-20]; reporting which obscured rather than highlighted taxpayers’ positions on accounting for costs; and the prolonged process by which significant information concerning the Whitney Canyon plant and its operations came to light. We find no reason to condemn the actions of the Department. To the contrary, we will conclude that the Department’s emerging conviction that sources of comparable value existed place a constitutional obligation on the Department to apply the comparable value method. Conclusions, infra, ¶363.

Did the Petitioners demonstrate that there were taxpayers similarly situated to themselves who were allowed to report taxable value using the proportionate profits method?

249. Petitioners base one or more of their constitutional claims on the premise that they are similarly situated to other mineral taxpayers who (1) sent their gas to processing plants prior to sale, and (2) requested and were granted the right to report on a proportionate profits basis, as an exception to the comparable value method. In production year 2001, the only taxpayers who sought to use the proportionate profits were Petitioners, Burlington Resources, and Marathon. [Transcript Vol. I, pp. 105-106].

250. The taxpayers stated their five points of similarity between and among these mineral taxpayers without specific references to the record:

(1) They were producers of production that was processed at plants in which they owned an interest. Throughout the history of Supreme Court and Board litigation, entities in that position have been referred to as “producer-processors.”

(4) The C&O Agreements provided that one of the producers would be chosen as the “Operator” of the plant; and

(5) Any producer who was not an Operator, could audit the operations of the plant.

[Taxpayers’ Revised Proposed Conclusion of Law, ¶271]. The Petitioners have not carried their burden of demonstrating these five points, for at least three reasons.

251. First, Petitioners did not call witnesses with first hand knowledge of the other plants and the operations of those plants, or of the revenues, costs, and tax reporting of producers serviced by the other plants. Petitioners were content to make broad and generally unsupported points. The Department found that there were significant differences between and among plants, and made an effort to take those differences into account when it authorized use of the proportionate profits method. [Bolles Rebuttal, pp. 6-7]. We find only the Department’s position to be credible.

252. Second, Petitioners’ points of similarity highlighted potential differences more than they established actual similarities. For example, the Whitney Canyon plant processed gas that is not dedicated, but Petitioners’ only evidence of dedications at other plants was by inference from the Mutual Back-up Agreement, which was unrelated to Burlington Resources or Marathon. We also know that the Whitney Canyon plant owners receive a processing fee, but Petitioners presented nothing more about the fees of other plants than what we could discern from contracts in the record.

253. The Department’s rebuttal case confirmed our concerns about the differences latent in Petitioners’ first three points, regarding production from processing plants where the Department was unable to use the comparable value method. For example, the construction and operation agreement for the Lost Cabin Plant (associated with Burlington Resources) provides for sharing of plant expenses in proportion to ownership, with no processing fee added. [Bolles Rebuttal, p. 7]. The Department found that the Lost Cabin plant processed only gas from dedicated wells. [Bolles Rebuttal, p. 7]. For the Garland/Oregon Basin property (associated with Marathon), the Department found a processing fee for undedicated gas that was a floor set by settlement, without any commitment from the owners to a specific fee. [Bolles Rebuttal, p. 7]. The Department made similar findings that distinguish the circumstances of the Garland facility, the Oregon Basin plant, and the JT Gas Separation Facility. [Bolles Rebuttal, pp. 7-8].

254. Third, the premise of the Petitioners’ fourth and fifth points is incorrect. We find that the parties to the Whitney Canyon C&O Agreement are plant owners, and that Petitioners are only producers with respect to the processing agreement which is Exhibit F to the C&O Agreement. [Exhibit 920]. BP is Operator of the Whitney Canyon plant by virtue of its position as a plant owner, not as a producer. [Exhibit 920]. Similarly, any right to audit the Operator is the right of a plant owner, not a producer. [Exhibit 920]. This being said, it is not clear why Petitioners selected these two features of the C&O Agreement among the many that were discussed in the record.

255. We find Petitioners’ approach to similarity to be unpersuasive for other factual reasons. Petitioners acknowledged that there were differences between the gas streams that feed other plants, but belittled those differences. Among Petitioners’ witnesses, Bidwell of BP (not designated or qualified as an expert) opined that the Lost Cabin and LaBarge plants could both process Whitney Canyon gas, based on what he has learned, second hand, from industry papers. [Transcript Vol. I, pp. 71, 82-83]. Bidwell seemed to be aware that the gas composition and processes at the two plants differed substantially from Whitney Canyon. [Transcript Vol. I, pp. 79-83]. The Department views these same differences in gas composition and operating conditions as significant. [Transcript Vol. V, pp. 904-905; Bolles Rebuttal, pp. 9-10]. We find the Department’s view to be more credible.

256. Bidwell was unaware of the cost structures of the other two plants. [Transcript Vol. I, p. 83]. Petitioners nonetheless generally asserted that other gas processing plants had expenses similar to those of Whitney Canyon. [Chambers Direct, Questions 94-108]. Like Bidwell, Chevron identified two similar plants as the Lost Cabin Plant, and the LaBarge plant of Exxon Mobil. [Chambers Direct, Question 95]. Chevron identified similar producers as Burlington Resources, Marathon, and Exxon Mobil. [Chambers Direct, Question 94].

257. We exclude Exxon Mobil from the potential universe of similarly situated taxpayers. Exxon Mobil reported under a settlement agreement, rather than using the proportionate profits method. [Chambers Direct, Question 107].

258. Chevron introduced three letters for the purpose of documenting the similarity of the Lost Cabin Plant. Anthony Fasone, identified as Specialist, Royalty Compliance, was the author of these letters, all of which are on Burlington Resources letterhead. [Confidential Chevron Exhibits 2, 3, 4]. Two letters are dated July 18, 2002, and the third is dated August 23, 2003. [Confidential Chevron Exhibits 2, 3, 4]. No Petitioner listed or called Mr. Fasone as a witness.

259. Chevron’s cost information for the Lost Cabin Plant is limited to a one-page summary in the letter of August 23, 2003. [Confidential Chevron Exhibit 4]. The figures purport to be a summary of cost information provided by the operators of the Madden Deep Unit to the Department of Revenue. [Confidential Chevron Exhibit 4]. The letter discloses nothing about accounting policies with regard to such items as gathering costs or depreciation policies. [Confidential Chevron Exhibit 4]. Nor does the letter describe the operations of the Lost Cabin Plant, or its age or gas stream. [Confidential Chevron Exhibit 4]. The cost information is not supplemented by information regarding an un-depreciated asset balance, return on investment, or other information that might enable us to evaluate whether its cost structure truly resembles that of Whitney Canyon, or other plants. All of the aforementioned information has proven significant for our understanding of the merits of Petitioners’ case. The exhibits are inadequate to support a claim that Lost Cabin expenses are similar to those of Whitney Canyon. Petitioners failed to provide enough information to show that the expenses of these other plants were similar, and failed to carry their burden of demonstrating that the other plants are similar in any way other than being gas processing plants.

260. The Department authorized Burlington Resources to use the proportionate profits method, and Burlington Resources claimed a processing allowance of 67.97 % for production year 2001. [Chambers Direct, Question 104; Confidential Chevron Exhibit 2]. We note that Chevron’s Exhibit 102 treated this fact as confidential, but Chevron’s witness did not seek that protection.

261. In rebuttal, the Department explained that it will continue to investigate the existence of sources of comparable value for those producers authorized to use the proportionate profits method. [Bolles Rebuttal, p. 8]. If the comparable value method can be used, the proportionate profits method will be disallowed. [Bolles Rebuttal, p. 8]. Petitioners presented no evidence that comparable values exist for the Burlington Resources or Marathon production that was reported using the proportionate profits method.

262. Any Conclusion of Law set forth below which includes a finding of fact may also be considered a finding of fact and is therefore incorporated herein by reference.

263. The Wyoming Constitution requires the gross product of mines to be taxed “in proportion to the value thereof” and “uniformly valued for tax purposes at full value as defined by the legislature.” Wyo. Const. art. 15, §§ 3, 11. Further, “All taxation must be equal and uniform within each class of property. The legislature shall prescribe such regulations as shall secure a just valuation for taxation of all property, real and personal.” Wyo. Const. art. 15, § 11(d).

264. For oil and gas, the “[v]alue of the gross product ‘means fair market value as prescribed by W. S. 39-14-203(b) less any deductions and exemption allowed by Wyoming law or rules.’” Wyo. Stat. Ann. §39-14-201(a)(xxix).

265. The fair market value for natural gas must be determined “after the production process is completed.” Wyo. Stat. Ann. §39-14-203(b)(ii). Expenses “incurred by the producer prior to the point of valuation are not deductible in determining the fair market value of the mineral.” Wyo. Stat. Ann. §39-14-203(b)(ii).

266. “The production process for natural gas is completed after extracting from the well, gathering, separating, injecting, and any other activity which occurs before the outlet of the initial dehydrator.” Wyo. Stat. Ann. §39-14-203(b)(iv). “When no dehydration is performed, other than within a processing facility, the production process is completed at the inlet of the initial transportation related compressor, custody transfer meter or processing facility, whichever occurs first.” Wyo. Stat. Ann. §39-14-203(b)(iv).

267. If the producer does not sell its natural gas prior to the point of valuation “by a bona fide arms-length sale,” the Department must identify the method it intends to apply to determine fair market value, and “notify the taxpayer of that method on or before September 1 of the year preceding the year for which the method shall be employed.” Wyo. Stat. Ann. §39-14-203(b)(vi).

268. If the Department determines fair market value using one of the four methods found in Wyo. Stat. Ann. §39-14-203(b)(vi), it must use the same method “for three years including the year in which it is first applied or until changed by mutual agreement between the department and the taxpayer.” Wyo. Stat. Ann. §39-14-203(b)(vi).

269. The Department may unilaterally employ only one of four methods to determine fair market value of natural gas not sold prior to the point of valuation. Wyo. Stat. Ann. §39-14-203(b)(vi). All four methods have been discussed in the record:

(A) Comparable sales – The fair market value is the representative arms-length market price for minerals of like quality and quantity used or sold at the point of valuation provided in paragraphs (iii) and (iv) of this subsection taking into consideration the location, terms and conditions under which the minerals are being used or sold;

(B) Comparable value – The fair market value is the arms-length sales price less processing and transportation fees charged to other parties for minerals of like quantity, taking into consideration the quality, terms and conditions under which the minerals are being processed or transported;

(C) Netback – The fair market value is the sales price minus expenses incurred by the producer for transporting produced minerals to the point of sale and third party processing fees. The netback method shall not be utilized in determining the value of natural gas which is processed by the producer of the natural gas;

(I) The total amount received from the sale of the minerals minus exempt royalties, nonexempt royalties and production taxes times the quotient of the direct cost of producing the minerals divided by the direct cost of producing, processing and transporting the minerals; plus

Wyo. Stat. Ann. §39-14-203(b)(vi). The Legislature prescribed these methods in 1990. 1990 Wyo. Sess. Laws, Ch. 54.

270. “[T]he reasonableness of the comparable value methodology is tested by whether there exist reliable, available information within the ‘market’ of natural gas processing fees paid by others (i.e., the ‘known’), which can be used to reasonably infer or estimate a just and fair processing fee (the ‘unknown’) that would have been paid by Petitioner had it been in a ‘third party’ producer position vis-à-vis the processing plant.” Appeal of Amoco Production Company, SBOE Docket 91-174, 1992 WL 126533 (Wyo. St. Bd. Eq. 1992); quoted in Amoco Production Company v. State Board of Equalization, 882 P.2d 866, 870 (Wyo. 1994); Whitney Canyon 2000, ¶134.

271. General appraisal principles must be applied sparingly, if at all, in the context of Wyo. Stat. Ann. §39-14-203(b)(vi) and the specific methods the legislature has chosen to define fair market value. Whitney Canyon 2000, ¶¶173-182.

272. The Department has not issued rules interpreting the comparable value, netback, or proportionate profits methods. However, rule making is not required “so long as statutory and constitutional rights to protest and contest are afforded the taxpayer.” Pathfinder Mines v. State Board of Equalization, 766 P.2d 531, 535 (Wyo. 1988); Amoco Production Company v. Wyoming State Board of Equalization, 899 P.2d 855, 860 (Wyo. 1995).

273. The Board previously interpreted the words and phrases employed in the definition of the comparable value method. Whitney Canyon 2000. The words “other parties” mean simply persons or groups distinct from the individual taxpayer. Whitney Canyon 2000, ¶127. The words are unambiguous. Whitney Canyon 2000, ¶128.

274. The phrase, “processing fees…charged to other parties for minerals of like quantity” is a broad test which must be used by the Department when the Department applies the comparable value methodology to determine fair market value. That test requires the Department to exercise its sound discretion to analyze available information of known processing fees in the context of known volumes of gas for which such fees are charged, with the objective of securing reliable information from which reasonable estimates can be made regarding processing fees which would be paid by a specific taxpayer had it been in the position of a third party producer requiring the services of a gas processing plant. Whitney Canyon 2000, ¶¶130-135.

275. The phrase “taking into consideration the quality, terms and conditions under which the minerals are being processed or transported” is likewise a test. Under this test, the Department must reasonably assure itself of the reliability of any comparison upon which it bases inferences regarding processing fees. The Department must consider at least the quality of the minerals, and the terms and conditions under which the minerals are being processed. Whitney Canyon 2000, ¶140.

276. The Board previously interpreted a key phrase employed in the proportionate profits method. “Direct cost of producing the minerals” includes production taxes, and includes royalties. In the Matter of the Appeals of Chevron U.S.A., Inc., Docket Nos. 2002-50, et al., 2004 WL 1294512 (Wyo. St. Bd. of Eq. 2004); In the Matter of the Appeal of Burlington Resources Oil & Gas Co., Docket No. 2002-49, In the Matter of the Appeals of Louisiana Land & Exploration Co., Docket Nos. 2002-123 & 2003-14, 2004 WL 1174649 (Wyo. St. Bd. of Eq. 2004); In the Matter of the Appeal of RME Petroleum Company, Docket No. 2002-52, 2003 WL 22814612 (Wyo. St. Bd. of Eq. 2003); In the Matter of the Appeal of Fremont County, Docket No. 2000-203, 2003 WL 21774604 (Wyo. St. Bd. of Eq. 2003).

277. The Wyoming Supreme Court recently set out the process used to value mineral production:

The process of “valuing” mineral production for tax purposes is lengthy, involving these steps:

1.The taxpayer files monthly severance tax returns. Wyo. Stat. Ann. §39-14-207(a)(v)(LexisNexis 2001).

2. The taxpayer files an ad valorem tax return by February 25 in the year following production, and certifies its accuracy under oath. Wyo. Stat. Ann. §39-14-207(a)(i)(LexisNexis 2001).

3. The Department of Revenue values the production at its fair market value based on the taxpayer’s ad valorem return. Wyo. Stat. Ann. §39-14-202(a)(ii)(LexisNexis 2001).

4.The Department of Revenue then certifies the valuation to the county assessor of the county the minerals were produced in to be entered on the assessment rolls of the county. Wyo. Stat. Ann. §39-14-202(a)(ii)(LexisNexis 2001).

5.The taxpayer then has one year to file an amended ad valorem return requesting a refund. Wyo. Stat. Ann. §39-14-209(c)(i)(LexisNexis 2001).

6.The Department of Audit has five years from the date the return is filed to begin an audit, and must complete the audit within two years. Wyo. Stat. Ann. §39-14-208(b)(iii), (v)(D), (vii)(LexisNexis 2001).

7.Any assessment resulting from the audit must be issued within one year after the audit is complete. Wyo. Stat. Ann. §39-14-208(b)(v)(E)(LexisNexis 2001).

Board of County Commissioners of Sublette County v. Exxon Mobil Corporation, 2002 WY 151, ¶11, 55 P.3d 714 (Wyo. 2002).

278. A taxpayer “aggrieved by any final administrative decision of the Department may appeal to the state board of equalization.” Wyo. Stat. Ann. §39-14-209(b)(i),(vi). Oil and gas taxpayers are entitled to this remedy:

Following [the Department’s] determination of the fair market value of... natural gas production the department shall notify the taxpayer by mail of the assessed value. The person assessed may file written objections to the assessment with the state board of equalization within thirty (30) days of the date of postmark and appear before the board at a time specified by the board...

Wyo. Stat. Ann. §39-14-209(b)(iv). This provision is found in Title 39, Chapter 14, of the Wyoming Statutes, pertaining to Mine Products Taxes on Oil and Gas.

279. From Title 39, Chapter 13 of the Wyoming Statutes, one subsection addresses ad valorem tax appeals:

Following the determination of the fair market value of property the department shall notify the taxpayer by mail of the assessed value. The person assessed may file written objections to the assessment with the [the state board of equalization] within thirty (30) days of the date of the postmark and appear before the board at a time specified by the board. The person assessed shall also file a copy of the written objections with the county treasurer of the county in which the property is located, who shall notify the county assessor and the board of county commissioners, with an estimate of the tax amount under appeal based upon the previous year’s tax levy.

280. The Board shall “review final decisions of the department [of revenue] upon application of any interested person adversely affected...under the contested case procedures of the Wyoming Administrative Procedure Act....In addition, the board shall:

(iv) Decide all questions that may arise with reference to the construction of any statute affecting the assessment, levy and collection of taxes, in accordance with the rules, regulations, orders and instructions prescribed by the department:

(viii) Hold hearings after due notice in the manner and form prescribed by the Wyoming Administrative Procedure Act and its own rules and regulation of practice and procedure...

281. Among other requirements for contested case procedures, the Wyoming Administrative Procedure Act states, “[o]pportunity shall be afforded all parties to respond and present evidence and argument on all issues involved.” Wyo. Stat. Ann. §16-3-107(j).

282. The Board may adjudicate a dispute between a taxpayer and the Department only by “approving the determination of the Department, or by disapproving the determination and remanding the matter to the Department.” Amoco Production Company v. Wyoming State Board of Equalization, 12 P.3d 668, 674 (Wyo. 2000).

283. The Supreme Court recently summarized the procedure the Board must follow when an oil and gas taxpayer challenges the fair market value determined by the Department of Revenue:

The Department’s valuations for state-assessed property are presumed valid, accurate, and correct. Chicago, Burlington & Quincy R.R. Co. v. Bruch, 400 P.2d 494, 498-99 (Wyo. 1965). This presumption can only be overcome by credible evidence to the contrary. Id. In the absence of evidence to the contrary, we presume that the officials charged with establishing value exercised honest judgment in accordance with the applicable rules, regulations, and other directives that have passed public scrutiny, either through legislative enactment or agency rule-making, or both. Id.

The petitioner has the initial burden to present sufficient credible evidence to over come the presumption, and a mere difference of opinion as to value is not sufficient. Teton Valley Ranch v. State Board of Equalization, 735 P.2d 107, 113 (Wyo. 1987); Chicago, Burlington & Quincy R.R. Co., 400 P.2d 499. If the petitioner successfully overcomes the presumption, then the Board is required to equally weigh the evidence of all parties and measure it against the appropriate burden of proof. Basin [Electric Power Coop. Inc. v. Dep’t of Revenue, 970 P.2d 841,] at 851 [(Wyo. 1998)]. Once the presumption is successfully overcome, the burden of going forward shifts to the Department to defend its valuation. Id. The petitioner, however, by challenging the valuation, bears the ultimate burden of persuasion to prove by a preponderance of the evidence that the valuation was not derived in accordance with the required constitutional and statutory requirements for valuing state-assessed property. Id.

Amoco Production Company v. Department of Revenue et al, 2004 WY 89, ¶¶7-8, 94 P.3d 430; accord, Airtouch Communications, Inc. v. Department of Revenue, State of Wyoming, 2003 WY 114, ¶12, 76 P.3d 342, ¶12 (2003); Colorado Interstate Gas Company v. Wyoming Department of Revenue, 2001 WY 34, ¶¶9-11, 20 P.3d 528, ¶¶9-11. The presumption that the Department correctly performed the assessment rests in part on the complex nature of taxation. Airtouch Communications, Inc., 2003 WY 114, ¶13, 76 P.3d 342, ¶13 (2003).

284. The Board’s Rules describe a petitioner’s burden of going forward, and its burden of persuasion:

Except as specifically provided by law or in this section, the Petitioner shall have the burden of going forward and the ultimate burden of persuasion, which burden shall be met by a preponderance of the evidence. If Petitioner provides sufficient evidence to suggest the Department determination is incorrect, the burden shifts to the Department to defend its action....

285. The initial step in arriving at a correct interpretation of a statute is an enquiry respecting the ordinary and obvious meaning of the words employed according to their arrangement and connection. A statute must be construed as a whole in order to ascertain its intent and general purpose and also the meaning of each part. We give effect to every word, clause and sentence and construe all components of a statute in pari materia. Parker Land & Cattle Company v. Wyoming Game and Fish Commission, 845 P.2d 1040, 1042 (Wyo. 1993).

286. “Affidavits by legislators or other persons involved in the enactment of a statute are not a proper source of legislative history.” Independent Producers Marketing Corp. v. Cobb, 721 P.2d 1106, 1108 (Wyo. 1986).

287. “No State shall make or enforce any law which shall abridge the privileges or immunities of citizens of the United States; nor shall any State deprive any person of life, liberty, or property, without due process of law; nor deny to any person within its jurisdiction the equal protection of the laws.” U. S. Const. amend. XIV, § 1, second sentence.

288. “No person shall be deprived of life, liberty or property without due process of law.” Wyo. Const. art. 1, §6.

289. “All laws of a general nature shall have a uniform operation.” Wyo. Const. art. 1, § 34. (Petitioners misquote Article 1, §34 in their proposed conclusions of law. [Taxpayers’ Proposed Conclusions of Law, ¶267].)

290. “Equal protection in Wyoming requires a law to operate alike upon all persons or property under the same circumstances and conditions.” W. W. Enterprises, Inc., v. City of Cheyenne, 956 P.2d 353, 356 (Wyo. 1998) (emphasis in original).

291. A valuation method may yield a deduction so low that the valuation method is constitutionally impermissible. If:

an artificially low price were utilized for purposes of taxation, the result would be a lower tax for operators [with the excessive deduction] than that paid by other operators. That lack of uniformity would be unacceptable because ‘the Wyoming Constitution mandates that all [minerals] shall be uniformly taxed on the value of their gross product.’ Amax Coal West, Inc., 896 P.2d at 1332.

Wyodak Resources Development Corporation v. Wyoming Department of Revenue, 2002 WY 181, ¶34, 60 P.3d 129, 142 (Wyo. 2002).

292. “Many types of property are included within each of the three constitutional classes of property....For example, it has long been recognized that, even though mineral products are one class of property, different valuation methods should be applied to different types of minerals. Oil is not valued by using the same method as is used in valuing coal or uranium. See, e.g., Pathfinder Mines v. State Board of Equalization, 766 P.2d 531 (Wyo. 1988) (recognizing that uranium is valued by using a different method than is used in valuing other mineral products).” Amoco Production Company v. Wyoming State Board of Equalization, 899 P.2d 855, 860 (Wyo. 1995).

293. “Uniformity of assessment requires only that the method of appraisal be consistently applied....It is an intrinsic fact in mineral valuation that differences in values result from the application of an appraisal method.” In re Monolith Portland Midwest Company, Inc., 574 P.2d 757, 761 (Wyo. 1978).

294. Procedural due process is satisfied “if a person is afforded adequate notice and an opportunity to be heard at a meaningful time and in a meaningful manner.” Robbins v. South Cheyenne Water and Sewage Dist., 792 P.2d 1380, 1385 (Wyo. 1990)(citing Higgins v. State ex rel. Workers’s Compensation Div., 739 P.2d 129 (Wyo. 1987), cert. den. 484 U. S. 988 (1987).

295. Collateral estoppel and res judicata are generally stated, and distinguished, as follows:

The doctrines of res judicata and collateral estoppel incorporate “‘a universal precept of common-law jurisprudence * * *”’ that a right, question or fact put in issue, and directly determined by a court of competent jurisdiction, cannot be disputed in a subsequent suit by the same parties or their privies....While the interests of finality served by this doctrine are the same, this court has carefully distinguished between the two:

[A]lthough many cases speak of res judicata in the administrative context, they actually apply collateral estoppel. * * * Collateral estoppel...bars relitigation of previously litigated issues. * * * Res judicata on the other hand bars relitigation of previously litigated claims or causes of action.

Tenorio v. State ex rel. Wyoming Workers’ Compensation Division, 931 P. 2d 234, 238 (Wyo. 1997)(emphasis in original).

Generally, four factors are considered when determining application of collateral estoppel: (1) whether the issue decided in the prior adjudication was identical to the issue presented in the present action; (2) whether the prior adjudication resulted in a judgment on the merits; (3) whether the party against whom collateral estoppel was asserted was a party or in privity with a party to the prior adjudication; and (4) whether the party against whom collateral estoppel is asserted had a full and fair opportunity to litigate the issue in a prior proceeding.

Tenorio v. State ex rel. Wyoming Workers’ Compensation Division, 931 P.2d 234, 238-239 (Wyo. 1997).

297. Res judicata bars relitigation of previously litigated claims. Tenorio, 931 P.2d at 238. Res judicata applies if: (1) the parties were identical; (2) the subject matter was identical; (3) the issues were the same and related to the subject matter; and (4) the capacities of the persons were identical in reference to the subject matter and the issues between them. Livingston v. Vanderdiet, 861 P.2d 549, 551-552 (Wyo. 1993).

298. “Judicial estoppel is a doctrine which precludes a party from asserting inconsistent positions in different judicial proceedings. Under this doctrine, a party who by his pleadings, statements, and contentions, under oath, has assumed a particular position in a judicial proceeding is estopped to assume an inconsistent position in a subsequent action.” Ottema v. State ex. rel. Workers’ Compensation Division, 968 P.2d 41, 45 (Wyo.1998). “The principle is that if you prevail in Suit #1 by representing that A is true, you are stuck with A in all later litigation growing out of the same events.” Eagle Foundation, Inc., v. Dole, 813 F.2d 798, 810 (7^th Cir. 1987). However, a party is not bound to maintain a position it unsuccessfully maintained in the original claim. Matter of Cassidy, 892 F.2d 637, 641 (7^th Cir. 1990); 74 Am. Jur. 2d Estoppel and Waiver §73, p. 498.

Did the Department correctly apply the comparable value method to determine the value of each Petitioner’s production?

299. Chevron brought this appeal under Wyo. Stat. Ann. §39-14-209(b)(iv) and Wyo. Stat. Ann. §39-13-102(n); BP and RME appealed under Wyo. Stat. Ann. §39-14-209(b)(iv). [Notices of Appeal]. The Petitioners thereby challenge the Department’s determination of value of their gas production, a value that is used to levy state severance taxes and to levy county ad valorem taxes. [Notices of Appeal]. As a practical matter, a successful challenge to the valuation used for severance tax purposes also affects ad valorem taxes.

300. The Petitioners did not and could not contest the Department’s selection of a method pursuant to Wyo. Stat. Ann. §39-14-203(b)(viii). Production year 2001 was the second year of a three year cycle during which one valuation method selected by the Department remains in effect. Wyoming Statute Annotated Section 39-14-203(b)(viii) has its own standard for adjudication, i.e., whether the selected method accurately reflects the fair market value of the taxpayer’s production. Since this case was not brought pursuant to Wyo. Stat. Ann. §39-14-203(b)(viii), that standard does not apply. We specifically reject Petitioners’ assumption to the contrary. [Taxpayers’ Revised Proposed Findings of Fact and Conclusions of Law, ¶¶276-281]. However, our distinction is of limited significance because we found Petitioners did not demonstrate that the Department’s comparable value determination did not meet fair market value. Findings, ¶¶228-240.

301. Since the selection of the method is not at issue, we concern ourselves only with whether the comparable value method was properly applied, and with the Petitioners’ procedural and constitutional claims.

302. The Petitioners have appealed under statutes that do not establish any specific standard to guide the Board’s review. Wyo. Stat. Ann. §39-14-209(b). In the absence of specific standards set by statute or rule, we judge the Department’s valuation by the general standard that the valuation must be in accordance with constitutional and statutory requirements for valuing state-assessed property. Amoco Production Company v. Department of Revenue et al, 2004 WY 89, ¶¶7-8, 94 P.3d 430; Wyo. Stat. Ann. §39-14-209(b)(vi). In doing so, we must take into account “the rules, regulations, orders and instructions prescribed by the department.” Wyo. Stat. Ann. §39-11-102.1(c)(iv). We also consider the case in the context of the Board Rule governing the burdens of going forward and of persuasion. Rules, Wyoming State Board of Equalization, Chapter 2, §20.

303. As we did for production year 2000, we begin with the phrase “other parties.” Whitney Canyon 2000, ¶¶127-128. We previously concluded that this phrase means persons or groups distinct from the individual taxpayer, and is unambiguous. Whitney Canyon 2000, ¶¶127-128. The taxpayers have offered no new arguments that cause us to reconsider this conclusion. However, in Whitney Canyon 2000, we applied that principle to the facts in this way:

…the Plant Owners are an other party with respect to each of the Producers. Each of the taxpayers is before us in its capacity as a Producer. We conclude that the Plant Owners are a business entity separate from each Producer. We have characterized that entity as a partnership based on the evidence in the record, including the C&O Agreement with its attachments, and testimony regarding the conduct of the business of the Whitney Canyon gas processing plant…

304. In this case, Petitioners have presented new evidence to support their view that the plant owners were not a partnership or business entity of any specific nature. Findings, ¶¶170-174. The Department does not disagree. Findings, ¶175. Instead, the Department was simply satisfied that the plant owners were separate and distinct from each producer, and made it clear that this had been its position in the proceedings for production year 2000. Findings, ¶175. We take the Department’s position as the starting point for our analysis.

305. We conclude the Plant Owners are an other party with respect to each of the Producers. Each of the taxpayers is before us in its capacity as a producer. The distinction between an individual producer and a multiparty processor is central to the processing fee that the plant owners charge and collect under Exhibit F to the C&O Agreement, the Wahsatch Gathering System Agreement, the Merit Agreement, and the 1995 Chevron Agreement. The plant owners are not distinct just from the individual producers who are party of Exhibit F to the C&O Agreement. The multiparty ownership established by the C&O Agreement is central to the structure of all contract relationships by which the Whitney Canyon plant processes natural gas for producers. The plant owners, acting through the plant operator, enforce the collection of the processing fee and rigorously account for its disposition. The disposition of the fee has a substantial redistributive effect. Findings, ¶¶90-96.

306. Chevron’s longstanding practice of using the netback method to report production under the 1995 Chevron Agreement reinforces our conclusion that the plant owners are an other party with respect to each producer. Findings, ¶¶30-31. No Petitioner objected to this method of reporting. No Petitioner objected to Chevron’s reliance on the 25% processing fee as the measure of its processing allowance under the 1995 Chevron Agreement. Chevron could only report using the netback method if it complied with the statutory requirement that has been in place since 1990:

307. To report using the statutory netback method, Chevron deducted expenses it incurred, as a producer, for “third party processing fees.” Chevron treated the plant owners – itself among their number since 1985 – as a third party. If the plant owners are a third party for purposes of the statutory netback method, we must conclude that they are other parties for purposes of the comparable value method.

308. Chevron’s netback reporting is also significant because the netback method is not available to determine the value of natural gas “which is processed by the producer of the natural gas.” Wyo. Stat. Ann. §39-14-203(b)(vi)(C). By its actions, Chevron conceded that under the 1995 Chevron Agreement, Chevron did not process the natural gas. Chevron’s reporting could only be lawful if the plant owners – Chevron among their number since 1985 – were viewed as distinct from Chevron in its capacity as a producer. Chevron’s netback reporting is consistent with the Department’s view that the plant owners are other parties for purposes of the comparable value method.

309. We conclude that there is no distinction between Chevron in its capacity as a producer under its two different sets of interests. As we have seen, where Chevron reported the two different sets of interests in the same well, it reported a single taxable value. Findings, ¶30. The Chevron that produced gas acquired through its Gulf interests, and the Chevron that produced gas under the 1995 Chevron agreement, was one and the same.

310. Chevron’s netback reporting cannot be squared with the Department’s stated position that the netback method was not available to the Petitioners because they are producer-processors. Findings, ¶46. As we indicated in Whitney Canyon 2000, the better view is that none of the Petitioners are producer processors, because the plant owners are the processor and the individual taxpayers are producers. Whitney Canyon 2000, ¶¶155. Based on the extensive information developed in this case and the statutory changes enacted in 1990, we conclude that any Board decisions decided under those prior statute are no longer precedent. [See Taxpayers Revised Proposed Conclusions of Law, ¶220, footnote 1.]

311. In this case, the taxable value determined by the comparable value and netback methods was the same, because processing cost was measured by the same contractual processing fee of 25%. Because two of the four valuation methods reached the same result, we are confident that neither result is an anomaly. In passing we note that the results contradict the view that the legislature necessarily intended a positive rate of return on investment. The third party processing fee in the statutory netback method is not disaggregated into current operating costs, depreciation, and return on investment, and therefore differs from the pre-1990 netback method. Findings, ¶138.

312. Under our view of the producer processor limitation in the statutory netback method, the netback method would not be available where the producer and processor are one and the same, as with Exxon Mobil’s LaBarge facility. Appeal of Sublette County Board of County Commissioners, Docket Nos. 2000-142, et. al., 2004 WL 1174651 (Wy. St. Bd. of Eq. 2004). Further, we see little reason to fear the undesired consequences of the netback method that has been a policy concern of the parties, i.e., a method that returns no value. [E.g., Grenvik Direct, p. 23]. The Department, not the taxpayer, controls the selection of method. The use of sham processing fees can be detected on audit. Excessive processing fees would be discouraged by other practical considerations, including the adverse effect of processing fees on the value of reserves. Findings, ¶122.

313. Of course, the Department has revalued all of Chevron’s production using the comparable value method, including production under the 1995 Chevron Agreement. Findings, ¶¶32-34. Our interest in the producer processor limitation is at issue principally due to the divergent wording of the comparable value and netback methods, which must be read in harmony. Parker Land & Cattle Company, 845 P.2d at 1042. Specifically, we must make sense of the distinction between “other parties” in the comparable value method, and “third parties” in the netback method. See Whitney Canyon 2000, ¶159.

314. The Petitioners have presented testimony intended to establish that the processing contracts do not reflect an arms-length relationship between third parties. E.g., Findings, ¶166. From its plain language, the comparable value statute does not require the Department to concern itself with either an arms-length or a third party standard, despite the fact that both phrases are used elsewhere in Wyo. Stat. Ann. §39-14-203(b)(vi). Parker Land & Cattle Company, 845 P.2d at 1042. We conclude that there is no reason to read either an arms-length test or a third party test into the comparable value method.

315. Petitioners lay the rationale for a third party test at the feet of the Board. We concluded long ago that the Department may “reasonably infer or estimate a just and fair processing fee…that would have been paid by Petitioner had it been in a ‘third party’ producer position vis-à-vis the processing plant.” Appeal of Amoco Production Company, 1992 WL 126533 (Wyo. St. Bd. Eq. 1992); quoted in Amoco Production Company, 882 P.2d at 870 (Wyo. 1994); Whitney Canyon 2000, ¶134. Under this principle, the Department must only concern itself with the position of the Petitioner and the fees paid by the producers on which the estimated fee is based, not on whether the Petitioner or comparable producers are in fact third parties with respect to the processing plant. Each of the Petitioners in this case is at least in a third party producer position vis-a-vis the processing plant. See Whitney Canyon 2000, ¶159. The more restrictive third party test is confined to the netback method. Our conclusion resolves an issue that had concerned us in the previous case. See Whitney Canyon 2000, ¶159.

316. Questions of third party status aside, the Petitioners remain free to question whether the inferences that the Department drew were sound. They have done so in this case.

317. Petitioners assert, based on cross-examination of the Administrator of the Mineral Tax Division rather than any affirmative testimony of their own witnesses, that the C&O Agreement is “essentially a joint operating agreement.” [Taxpayers Revised Proposed Findings of Fact and Conclusions of Law, ¶¶ 157, 158, 222], see Findings, ¶173. From this premise, they note that the Department commonly treats a take in kind owner who is party to joint operating agreement as a taxpayer. [Taxpayers Revised Proposed Conclusions of Law, ¶222]. Proceeding from this fact, Petitioners would have us conclude that none of them were in the position of a third party producer. [Taxpayers Revised Proposed Conclusions of Law, ¶224]. In addition to the reasons we have already given for rejecting this conclusion, we would add (1) each of the Petitioner/producers is indeed being treated as an individual taxpayer, and (2) the plant owners do not pay mineral taxes in their capacity as plant owners – only as producers.

318. Finally, by a plain reading of the language of the comparable value method, we reject Petitioners’ view that “other parties” means “entities other than the taxpayers or plants in which they have an interest.” [Taxpayers Revised Proposed Conclusions of Law, ¶184]. If the legislature had intended the “other parties” standard to include the words “plants in which they have an interest,” or plants owned only in part by the producer, those words would appear in the statute. Those words do not. Perhaps as important, the Whitney Canyon plant presents the further problem that it processes gas for three producers who were, for all intents and purposes, customers of a merchant plant – the Wahsatch producer, Merit, and Chevron under the 1995 Chevron Agreement.

319. The phrase, “processing fees…charged to other parties for minerals of like quantity” is a broad test which must be used by the Department when the Department selects the comparable value methodology to determine fair market value. Whitney Canyon 2000, ¶¶130-135. The taxpayers disagree with our conclusion regarding this principle, but have made no arguments that would cause us to reconsider our prior ruling.

320. Taxpayers urge us to conclude that the words “like quantity” are ambiguous, [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶202, 203, 207], although the Department believes that the statute is clear. Findings, ¶28. We considered and rejected a similar general argument for production year 2000. Whitney Canyon 2000, ¶136. In this case, we note further that our conclusion regarding the words “like quantity” takes those words in the context of the complete phrase, “processing fees . . . charged to other parties for minerals of like quantity.” Whitney Canyon 2000, ¶¶131-134. There is no merit in reading the words in isolation.

321. Based upon a 1990 Mineral Taxation Report prepared by the Chairman of the Joint Revenue Interim Committee, the taxpayers urge us to direct our attention to unspecified professional valuation standards. [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶205-207]. Petitioners contend that reference to professional valuation standards should lead us to the conclusion that the statute is ambiguous. [Taxpayers’ Revised Proposed Conclusions of Law, ¶207]. The 1990 Mineral Taxation Report is not a proper source of legislative history. Independent Producers Marketing Corp., 721 P.2d at 1108 (Wyo. 1986). However, even if we accept the guidance of the 1990 Mineral Taxation Report, it merely declared that each of the four statutory valuation methods meets professional valuation standards – nothing more. Findings, ¶¶224-225. Indeed, the 1990 Mineral Taxation Report is entirely consistent with conclusions we have previously reached regarding the applicability of appraisal principles in the context of Wyo. Stat. Ann. §39-14-203(b)(vi). Whitney Canyon 2000, ¶¶173-182. If each of the valuation methods already meet professional valuation standards, there is no reason to shoehorn any of the four valuation methods into an unspecified valuation framework. Likewise, we reject Petitioners’ argument that use of any of the four valuation methods requires specific appraisal expertise on the part of the Department.

322. The taxpayers independently urge us to view the words “like quantity” as a technical appraisal term. [Taxpayers’ Revised Proposed Findings of Fact and Conclusions of Law, ¶¶ 7, 144, 204]; Wyo. Stat. Ann. §8-1-103(a)(i). We have rejected this proposition as a matter of law. Whitney Canyon 2000, ¶¶173-182. As a proposition of fact they have merely presented us the industry perspective of their witnesses, which we found to be unpersuasive. Findings, ¶227. Petitioners have failed to carry their burden of persuasion on this point.

323. Petitioners premise arguments concerning “like quantity” on material that was not included in the record. [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶199, 201]. We refuse to consider those arguments.

324. The phrase “taking into consideration the quality, terms and conditions under which the minerals are being processed or transported” is a test under which the Department must reasonably assure itself of the reliability of any comparison upon which it bases inferences regarding processing fees. Whitney Canyon 2000, ¶140. The taxpayers disagree with our conclusion regarding this principle, but have made no arguments that would cause us to reconsider our prior ruling.

325. Petitioners urge us to focus on several practical aspects of the service provided to the Wahsatch Gathering System, and conclude that the Department could not have reasonably assured itself of the reliability of the Wahsatch agreement as a source of comparable value. [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶ 208-213]. First, they direct our attention to services not provided to the Wahsatch producer, due to the location at which Wahsatch gas enters the plant. The fact is correct, but Petitioners overstate the conclusion. We have found that a portion of services provided by the plant are in fact gathering services that should not be included in processing costs for tax purposes. We found that the Wahsatch Agreement was still a source of comparable value in spite of the location at which Wahsatch gas enters the plant. Findings, ¶¶183-186.

326. Second, we have considered, as a fact issue, whether the reduced service provided the Wahsatch producer precluded a finding of like quality, and found to the contrary. Findings, ¶187.

327. Third, we have considered, as a fact issue, whether curtailments of Wahsatch gas precluded a finding of like quality, and found to the contrary. Findings, ¶188.

328. Fourth, we have considered, as a fact issue, whether the additional expense associated with transport of Wahsatch gas to the Whitney Canyon plant precluded a finding of like quality, and found to the contrary. Findings, ¶¶185-186. Having considered these points, we conclude that the Department reasonably assured itself of the reliability of the Wahsatch gas agreement as a source of information upon which it based inferences regarding processing fees.

329. In the context of the statutory requirement for the Department to take into account the quality, terms and conditions under which the minerals are being processed or transported, the taxpayers argued – largely by repetition in a variety of contexts – the significance of supposed professional valuation standards; the parties’ expectations in 1982; and the importance of relying on contracts negotiated in 2001 to establish a market based rate. [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶ 210, 213, 215, 216, 217]. We considered, and rejected, the factual premises of these arguments, and accordingly reject the related conclusions of law. We similarly rejected taxpayers’ argument that the Jumping Pound calculation of Joseph Wilkinson established that an appropriate processing fee should be in excess of 50%. [Taxpayers’ Revised Proposed Conclusions of Law, ¶ 217]; Findings, ¶240.

330. Taxpayers raised one issue that prompts us to recant the words of a conclusion stated in Whitney Canyon 2000. We concluded the Department considered the terms and conditions under which the minerals were being processed, and went on to conclude that “the terms and conditions to which the taxpayers have directed our attention are not commercially significant.” Whitney Canyon 2000, ¶141. “Commercially significant” was a poor choice of words, entirely our own. We were referring then to a fact also established in this case: a high processing priority was more desirable than a low processing priority, but contractual priority had no discernible effect on the processing fee. Further, for production from the Whitney Canyon field, contract priority seemed to have no role in field operation decisions. Findings, ¶204. Similarly, curtailment was undesirable, and did have an effect on processed volumes of the Wahsatch producer in 2001, but vulnerability to curtailments had no discernible effect on the processing fee. Findings, ¶¶188, 204.

331. The taxpayers argue that the Department has failed to consider a large number of pertinent distinctions between and among various gas processing contracts, and hence has failed to consider “terms and conditions” as required by the statute. We conclude that this is a dispute between the parties regarding the significance of those distinctions for applying the comparable value method. As such, we view the resolution of that dispute as a question of fact. We have made various findings in this regard. E.g., Findings of Fact, ¶¶162-222. We conclude that the Department has met the requirements of the statute with respect to considering the terms and conditions under which the minerals are being processed. The taxpayers have failed to carry their burden of persuasion. We likewise conclude that the Department has met the requirements of the statute with respect to considering quality. The taxpayers have failed to carry their burden of persuasion on that point as well.

332. Under our reading of the plain language of the statute, the Department correctly applied the comparable value method, subtracting an inferred processing fee from a known sales price to reach a value. For BP, the fees charged to other parties include:

● Processing fees charged by the Plant Owners to Producers Chevron, RME, and Forest Oil under the Exhibit F Gas Processing Agreements;

● Processing fees charged by the Plant Owners to Anschutz under the Wahsatch Gathering System Agreement;

● Processing fees charged by the Plant Owners to Merit under the Merit Agreement;

●Processing fees charged by the Plant Owners to Chevron under the 1995 Chevron Agreement.

● Processing fees charged by the Plant Owners to Producers BP, RME, and Forest Oil under the Exhibit F Gas Processing Agreements;

● Processing fees charged by the Plant Owners to Anschutz under the Wahsatch Gathering System Agreement;

● Processing fees charged by the Plant Owners to Merit under the Merit Agreement.

Chevron is not an “other party” to itself as a producer even though it has two separate gas processing agreements with the Plant Owners. Conclusions, ¶309.

● Processing fees charged by the Plant Owners to Producers Chevron, BP, and Forest Oil under the Exhibit F Gas Processing Agreements;

● Processing fees charged by the Plant Owners to Anschutz under the Wahsatch Gathering System Agreement;

● Processing fees charged by the Plant Owners to Merit under the Merit Agreement;

●Processing fees charged by the Plant Owners to Chevron under the 1995 Chevron Agreement.

335. We conclude that, with respect to the 25% in-kind processing fee charged under all of the agreements referenced in, Conclusions ¶¶332-334, the Department correctly determined by comparison of processing rates in the context of suitably measured volumes that there was a constant rate applied against any and all volumes processed under the referenced agreements during 2001. Findings, ¶¶214-222. As a further and separate ground for our decision in this regard, we find that the taxpayers failed to carry their burden of persuasion.

336. We conclude that, in the course of satisfying itself that the inferences being drawn from the agreements referenced above were based on valid comparisons, the Department adequately considered both the quality of the gas being processed, and the terms and conditions under which the gas was being processed. In all instances, similarity of quality was assured by virtue of the fact that all gas was commingled before becoming available at the tailgate of the plant. In all instances, the terms and conditions were sufficiently similar to conclude that the comparison was valid. Findings of Fact, ¶¶217-222. We conclude that Department met the requirements of the statute. As a further and separate ground for our decision in this regard, we find that the taxpayers failed to carry their burden of persuasion.

337. As an independent basis for contesting the Department’s use of the comparable value method, the taxpayers claim that the 25% processing allowance is invalid because it did not allow RME and Chevron to recover their actual costs of processing, without taking into consideration a return of or a return on investment. [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶247, 248]. This claim was not supported by the evidence. Findings of Fact, ¶¶51-161. We conclude that the claim is therefore groundless as a matter of law. We reserve for another time the question of whether, as a matter of law, the fair market value determination authorized by use of the methods stated in Wyo. Stat. Ann. §39-14-203(b)(vi) must always cover the actual processing costs incurred by an individual taxpayer, and/or all of the plant owners.

338. We conclude that the Petitioners did not correctly apply the proportionate profits method when they reported taxable value. Findings, ¶¶29, 125-128; In the Matter of the Appeals of Chevron U.S.A., Inc., Docket Nos. 2002-50, et al., 2004 WL 1294512.

339. The taxpayers have not disputed the mathematical calculation performed by the Department and reflected in the Notices of Valuation.

Did the Department violate prescribed requirements by the procedures it used to determine each Petitioner’s production?

340. As in Whitney Canyon 2000, Petitioners introduced evidence of the Department’s efforts, more than ten years ago, to determine comparable value by an entirely different approach. [Exhibit 933]. We previously considered the significance of the litigation surrounding that failed approach, and find neither new evidence or new argument that would cause us to change our prior assessment of Amoco Production Company v. Wyoming State Board of Equalization, 882 P.2d 866 (Wyo. 1994), or this Board’s related opinion, Appeal of Amoco Production Company, SBOE Docket 91-174, 1992 WL 126533 (Wyo. St. Bd. Eq. 1992). We accordingly reaffirm that discussion and its related rulings. Whitney Canyon 2000, ¶¶161-168. In doing so, we generally reject Petitioners’ characterization of those cases. It remains to supplement our prior discussion with a number of specific points.

341. Petitioners argue that if the taxpayer could not participate in the selection of a specific comparable, the Department cannot require the taxpayer to use the comparable value method, citing Amoco Production Company, 882 P.2d at 872. [Taxpayers’ Revised Proposed Conclusions of Law, ¶182]. We reject the argument. Under the method proposed by the Department in 1992, the Department was to select sources of comparable value without disclosing confidential information to the taxpayer; since all of the Department’s sources were to be confidential, the result was to force the taxpayer to defend against an unknown. Id., at 871-872. For production year 2001, the Department relied on sources that were fully disclosed, and the Petitioners have had every “opportunity to ‘respond and present evidence and argument’ on all issues involved.” Id., at 872; Wyo. Stat. Ann. §16-3-107(j).

342. The Petitioners’ demand for a study of third party fees likewise arises from the Department’s failed 1992 approach to comparable value. [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶186-188]. We conclude that no such study is required, beyond the investigation already reflected in the Department’s reasoned basis for applying the comparable value method to Petitioners’ 2001 production. Findings, ¶¶37-44, 46-50, 217-222.

343. As in Whitney Canyon 2000, the taxpayers criticized the Department’s refusal to pursue rule making to more fully define the comparable value method. [Taxpayers’ Revised Proposed Conclusions of Law, ¶ 183]. They again rely on a suggestion made by the Court in Amoco Production Company v. State Board of Equalization, 882 P.2d 866, 871 (Wyo. 1994), which the Court itself characterized as being “in the nature of an aside.” This suggestion was made in the context of different facts than those presented in this case. See Whitney Canyon 2000, ¶¶165-166.

344. Rule making is not required “so long as statutory and constitutional rights to protest and contest are afforded the taxpayer.” Pathfinder Mines v. State Board of Equalization, 766 P.2d 531, 535 (Wyo. 1988); Amoco Production Company v. Wyoming State Board of Equalization, 899 P.2d 855, 860 (Wyo. 1995). We have afforded taxpayers those rights.

345. We have also rejected the factual premises of taxpayers’ demand for rule making. On the record made in this case, we found no reason to believe the taxpayers were in need of guidance regarding the Department’s requirements. Findings, ¶¶ 26-28. Our conclusion is buttressed by the ease and consistency with which Chevron has used the 25% processing fee to report using the netback method. Findings, ¶¶30-31.

346. Petitioners argue that the Department’s Memorandum of November 30, 1995 [Exhibit 938] obligated the Department to accept Petitioners’ attestations of the absence of sources of comparable value, and obligated the Department to authorize use of the proportionate profits method. [Taxpayers’ Revised Proposed Conclusions of Law, ¶183]. We reject this argument for two main reasons. First, we did not find that the Memorandum was either of indefinite duration, or the basis of the Department’s decision to allow reporting under the proportionate profits method after 1996. The Memorandum was supplanted by memoranda memorializing the Department’s selection of method for the cycles beginning in 1997 and 2000. Findings, ¶¶242-246. Second, the Petitioners have not referred to any authority that supports their view of the Memorandum. The Memorandum is not a statute; it is not a rule, regulation, or order of the Department. Wyo. Stat. Ann. §39-11-102.1(c)(iv). At most, the Memorandum was a superceded instruction. Findings, ¶246.

347. More generally, Petitioners ask that we censure the Department for changes in policy since 1992. Petitioners argue that the Department’s policy has been characterized by abrupt departures; by an unreasonable refusal to accept Petitioners’ attestations to the absence of comparables; by inadequate response to the Petitioners’ correspondence; by a failure to provide meaningful guidance; by mercurial positions and interpretations; by idiosyncratic definitions based on new interpretations caused by faulty memory. [Taxpayers’ Revised Proposed Conclusions of Law, ¶189-193, 257-258]. Our findings are contrary to all of these claims. Findings, ¶¶ 241-248.

348. In substantial measure, the Department’s changing policy was a product of Petitioners’ ill-founded attestations to the absence of comparables. The Department relied on these attestations to accept Petitioners’ proportionate profits reporting. Findings, ¶248. When the Department learned of the doubtful quality of these attestations, it found further support for use of the comparable value method in the form of the Wahsatch Gathering System Agreement, the Merit Agreement, and the 1995 Chevron Agreement. See Findings, ¶¶19-25. With new information in hand, the Department was obliged to change its view of the availability of the comparable value method for Petitioners, and to vigorously pursue enforcement of the tax laws.

349. Petitioners make four different constitutional claims. Two claims arise from the Department’s inability to apply the comparable value method to Burlington Resources and Marathon, due to the absence of sources of comparable value. Findings, ¶¶249-261. Two claims arise from the procedures used by the Department to determine Petitioners’ taxable value. Findings, ¶¶241-248; Conclusions, ¶¶340-348.

350. We address Petitioners’ equal protection claim first. Petitioners claim that Department deprived them of a right to fair and uniform treatment under the Equal Protection Clauses of the United States and Wyoming Constitutions. U. S. Const. amend. XIV, § 1, second sentence; Wyo. Const. art. 1, § 34. The core of this claim is that other similarly situated taxpayers were allowed to use the proportionate profits method, while the Petitioners were not. [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶265, 270-271, 274].

351. From our observation of the witnesses, we believe that this issue is central to the Petitioners’ palpable frustration with the Department. Based on the testimony of two of the Petitioners’ tax representatives, we have gained a sense that their companies have long had an expectation about how the 1990 legislation would be administered. Their expectation is that the value of Whitney Canyon gas production would always be determined by the proportionate profits method.

352. The Petitioners’ frustration is matched, though not in equal measure, by the Department’s dissatisfaction with the proportionate profits method. The Department has articulated its reasons, Findings, ¶¶47-48, for which there is ample support in the record of this case. Nonetheless, the Board has rejected an extreme view of the defects of the proportionate profits method. Whitney Canyon 2000, ¶158.

353. In Whitney Canyon 2000, we disposed of Petitioners’ constitutional claims without having to reach a broad view of Wyo. Stat. Ann. §39-14-203(b)(vi). The Petitioners’ renewed constitutional claims, coupled with the more extensive record made for production year 2001, make it important to do so now. We intend to accomplish three tasks: to explain why we view the heart of this matter as being the structure of the legislation, not the exercise of administrative discretion; to explain why we consider the legislative structure to be sound; to facilitate judicial resolution in the event of appeal.

354. The Wyoming Constitution assigns the role of defining full value, or fair market value, to the Legislature. Wyo. Const. art. 15, § 11. The Legislature has considerable constitutional latitude to prescribe the method by which the Department may determine fair market value. Amoco Production Company, 899 P.2d at 860. For the circumstances of this case, the Legislature has done so through Wyo. Stat. Ann. §39-14-203(b)(vi), which authorizes the Department to choose among four specified methods to determine the value of natural gas sold away from the point of valuation.

355. The four statutory methods cannot be used simultaneously to value any producer’s gas; they are mutually exclusive. Whitney Canyon 2000, ¶¶173-182. We agree with BP’s tax representative that the proportionate profits method, if properly applied, reaches fair market value. Findings, ¶229. The same is true of all four methods.

356. It is also true that all four methods cannot be used for all taxpayers. The Legislature forbade the use of the netback method for gas processed by a producer, thereby generally limiting one of the methods that might be available for producers who do not sell their natural gas production prior to the point of valuation by a bona fide arms-length sale. We note in passing that the Petitioners’ tax representatives tend to assume that Wyo. Stat. Ann. §39-14-203(b)(vi) was enacted to address valuation problems associated with large natural gas processing plants, but this assumption is not supported by the language of the statute. The language of the statute is of broader application.

357. The Legislature also implicitly recognized that one or more of the methods might not be available to the Department because the information necessary to apply that method was unavailable. In this case, no one disputes that the comparable sales method cannot be applied because there is no information that would enable to Department to do so. Findings, ¶46. The Legislature went further, and recognized that there may be circumstances in which none of the four methods reaches a representative fair market value. For those circumstances, the Legislature authorized the Department and an affected taxpayer to employ a mutually acceptable alternative method. Wyo. Stat. Ann. §39-14-203(b)(vii); see generally Appeal of Sublette County Board of County Commissioners, Docket Nos. 2000-142, 2003-02, May 20, 2004, 2004 WL 1174651 (Wy. St. Bd. of Eq.).

358. The Department has testified that no sources of comparable value were available to determine the value of gas processed for Burlington Resources and Marathon at the Lost Cabin plant and other facilities. Findings, ¶¶253, 261. The Petitioners have produced no evidence to the contrary. Like the comparable sales method, the Department could not apply the comparable value method to Burlington Resources and Marathon 2001 production because there was no information that would enable to Department to do so. Findings, ¶¶253-261. Faced with this situation, the Department authorized Burlington Resources and Marathon to use the proportionate profits method.

359. The Petitioners argue that if sources of comparable value are not available for two taxpayers whose gas must be processed, the Department loses control over the method to be applied to other taxpayers whose gas must be processed. The argument is contrary to law.

360. By statute, the Legislature has given the Department exclusive authority to select a method. The Department’s authority is constrained by a requirement that the method be selected for three-year periods. The taxpayer can only force a change of method by successful appeal during the year when the method is first selected. Wyo. Stat. Ann. §39-14-203(b)(viii).

361. Nothing in the statute vests the taxpayer with the discretion to select a method when one or more of the methods are unavailable due to lack of information. We presume that the Petitioners agree. They request here, as they did in Whitney Canyon 2000, that we require the Department to accept their proportionate profits reporting by default.

362. Under the Wyoming Constitution, if the Department or this Board were to allow these taxpayers the right to select the method of their choice, the proportionate profits method, the result would be constitutionally impermissible. They would enjoy a lower tax than other operators subject to the comparable value method, due to an “excessive deduction.” Wyodak Resources Development Corporation, 2002 WY 181, ¶34, 60 P.3d at142. We conclude that the Department’s designated method is the key to determining whether the Department has complied with the Wyoming Constitution, and to determining what other taxpayers are similarly situated to the Petitioners. The factual enquiry must be directed to whether the Department has applied its designated method to every taxpayer for whom the designated method is available.

363. As a corollary, we conclude that Department is constitutionally required to apply the comparable value method to the Petitioners’ production if information is available to do so. We do not start by asking whether other taxpayers who process gas are allowed to use the proportionate profits method. Instead, we start by asking whether the Department has applied its designated method to every taxpayer for whom the method is available.

364. Although the Petitioners have no valid equal protection claim based on the Department’s inability to apply its selected method to another taxpayer, it remains open to the Petitioners to question whether the Department has correctly determined that sources of comparable value information are available for them, just as they have done in this case.

365. We have reached a different conclusion than the taxpayers about what it means to be similarly situated as a matter of law. We also found that the Petitioners did not demonstrate that the other taxpayers were similarly situated under Petitioners’ own view. Findings, ¶¶249-261.

366. Petitioners also argue that the “Department never articulated any cogent basis for distinguishing between” Petitioners and the other two taxpayers, Burlington Resources and Marathon. [Taxpayers’ Revised Proposed Conclusions of Law, ¶274]. The Petitioners did not demonstrate the truth of this factual allegation. Findings, ¶¶253, 261. We have, in any event, articulated what we conclude is a cogent basis for the Department’s distinction.

367. Finally, Petitioners object that the Department relies on future audits of Burlington Resources and Marathon to assure that the comparable value method cannot be used to determine the value of their gas. [Taxpayers’ Revised Proposed Conclusions of Law, ¶275]. The Department stated its intention to investigate the existence of sources of comparable value when Burlington Resources and Marathon are audited, and if such sources are found, to require a redetermination of value under the comparable value method. Findings,¶261. The taxpayers protest that confidential future audit records of other taxpayers will be unavailable to vindicate their present right to uniform treatment.

368. The taxpayers misunderstand the significance of future audits. The Department’s intention to apply the comparable value method assures us that the Department has done its best to use comparable value to determine the value of production of all taxpayers for which the method is available. This is consistent with what the Department elected to do for all oil and gas taxpayers, including Petitioners. Findings, ¶19.

369. Petitioners claim that the valuation statute, as applied by the Department, violates Article 15, §3, of the Wyoming Constitution, requiring ad valorem taxes on gas to be imposed “in proportion to the value thereof.” Petitioners reason that the results of the comparable value method consistently and dramatically vary from the results of the proportionate profits and netback methods. [Taxpayers’ Revised Proposed Conclusions of Law, ¶249]. Petitioners further argue that Wyo. Stat. Ann. §39-14-203(b)(vi) thereby “vests the Department with complete and arbitrary discretion to pick the result that gives the highest value,” and therefore cannot be said to impose tax in proportion to value. [Taxpayers’ Revised Proposed Conclusions of Law, ¶249]. The argument rests entirely on the language of Article 15, §3, without reference to related constitutional provisions, and without reference to any other authority.

370. We found no credible evidence that the Department selected the comparable value method solely and exclusively because it generated the highest taxable value. Findings, ¶50. We also disagree that the Department’s discretion is unfettered, for reasons stated in our discussion of Petitioners’ equal protection claim. Conclusions, ¶¶355-358, 360, 363.

371. For their factual predicate, Petitioners rely principally on RME’s comparison of the results of the comparable value, proportionate profits, and netback methods over a twelve year period. [Taxpayers’ Revised Proposed Conclusions of Law, ¶249]. We generally did not accept RME’s calculations. Findings, ¶¶230-236.

372. We specifically found that the statutory netback method yields the same result as the comparable value method under the facts of this case. Findings, ¶232; Conclusions, ¶311. The RME study did not demonstrate the alleged variance between the comparable value and netback methods.

373. We agree that results of the comparable value and proportionate profits methods diverge, but Petitioners have not adequately described the problem. There is also a substantial divergence of results between and among taxpayers who used the proportionate profits method. The Petitioners reported processing allowances ranging from 32.94% to 67.52% for the same gas from the same Mineral Group. Findings, ¶¶87-88. If consistency is a concern, surely the single processing allowance of 25% for gas from the same well is more consistent.

374. We reject the principle that divergence of valuation results is the correct test of compliance with Article 15, §3, of the Wyoming Constitution. At a minimum, it is up to the Legislature to define fair value. Conclusions, ¶354. The Legislature authorized the Department to determine fair market value by use of methods that yield divergent results. There is no constitutional offense in divergence as long as the Department consistently applies a selected method. In re Monolith Portland Midwest Company, Inc., 574 P.2d at 761.

375. Petitioners’ divergence argument also fails because, under the circumstances of this case, their articulation of constitutional principle conflicts with other constitutional principles. Petitioners ignore the divergence generated principally by Petitioners’ individual behaviors, and provide no constitutional bedrock to gauge the integrity of such individual behaviors. From our scrutiny of the taxpayers’ cost information, we discovered some of the reasons that the reported allowances varied: disparate reporting of operating cost information from a common accounting source; widely disparate depreciation policies; disparate policies on turnaround accounting. This adds up to great risk of “a lower tax for operators [with an excessive deduction] than that paid by other operators.” Wyodak Resources Development Corporation, 2002 WY 181, ¶34, 60 P.3d at 142.

376. We otherwise conclude that RME’s study provided an unpersuasive policy perspective because it ignored the likely results of the comparable value method over the remaining life of the Whitney Canyon plant. Findings, ¶236.

377. Petitioners make a somewhat different constitutional claim under Article 15, §3, based on the principle that the Legislature cannot give the Department the authority to arbitrarily select a valuation method that generates the highest taxable value, citing Kelsey v. Taft, 263 P.2d 125, 136 (Wyo. 1953) and Chevron U. S. A., Inc., v. State, 918 P.2d 980, 984-985 (Wyo. 1996). [Taxpayers’ Revised Proposed Conclusions of Law, ¶249]. Neither case is directly on point. Kelsey held that the Wyoming could not collect inheritance taxes on property transferred in contemplation of death, because the statute failed to say so directly and positively. Chevron U. S. A., Inc., held that the expense of compressing gas was not a taxable production expense, but rather was a deductible processing expense. We take Petitioner’s claim to generally relate to the issues that we address in the context of their other constitutional claims. We conclude that the claim is baseless.

378. Petitioners claim that their rights to procedural due process were violated because they were not afforded an opportunity to be heard in a meaningful time and a meaningful manner. U. S. Const. amend. XIV, § 1, second sentence; Wyo. Const. art. 1, §6. In the main, this argument is merely a constitutional extension of complaints about the Department’s procedures: the absence of regulations or other guidance, the absence of a comparable value study, etc. [Taxpayers’ Revised Proposed Conclusions of Law, ¶¶254, 255, 257-259]. We have already concluded that those complaints are baseless. Conclusions, ¶¶341-345. As a related argument, Petitioners assert that they were denied adequate notice of what they would be required to prove, due to the Department’s “mercurial positions and interpretations” and the Department’s “idiosyncratic definitions based on new interpretations caused by faulty memory.” [Taxpayers’ Revised Proposed Conclusions of Law, ¶253, 257-258]. This argument is baseless as well. Conclusions, ¶¶347-348.

379. In support of their procedural due process claim, Petitioners also argue that the Department’s valuation has lost its presumption of validity because the valuation was determined without the benefit of clear statutory authority, citing Basin Electric Power Cooperative, Inc., v. Department of Revenue, 970 P.2d 841, 851 (Wyo. 1998). We have concluded, to the contrary, that the Department acted under clear statutory authority. Conclusions, ¶¶ 303, 319, 324. We also conclude that Basin Electric Power Cooperative does not apply. We have decided this case principally based upon the Petitioners’ failure to carry its burden of persuasion, i.e., to demonstrate that the Department has violated constitutional and statutory requirements for valuing state-assessed property. Our decision does not generally rest on the presumption of validity.

380. Petitioners claim that their rights to substantive due process were violated because the Department’s actions were arbitrary, relying principally on Mortgage Guaranty Ins. Corp. v. Langdon, 634 P.2d 509 (Wyo. 1981) and White v. State, 784 P.2d 1313 (Wyo. 1989). [Taxpayers’ Revised Proposed Conclusions of Law, ¶260-264]. Neither case is on point. In Mortgage Guaranty Ins. Corp., the Wyoming Supreme Court set aside an order of the Wyoming insurance commissioner because he had failed to consider all pertinent value factors when issuing an order, but the Court found no violation of due process. In White v. State, the Court upheld a provision of the Wyoming Governmental Claims Act that provided immunity from suit for design, construction and maintenance of highways. In doing so, the Court rejected an argument that the statute in question warranted the heightened degree of scrutiny associated with a fundamental interest or an inherently suspect classification. We accordingly conclude that Petitioners’ argument is merely a constitutional extension of the claim that the Department has misapplied the comparable value method, or followed improper procedures. We have already concluded that both sorts of claims are groundless. Conclusions, ¶¶303-348.

381. We conclude that the Petitioners have not carried their burden of persuasion with respect to any of the constitutional claims.

Was the Department barred from use of the comparable value method by collateral estoppel or judicial estoppel?

382. Based upon our ruling in Whitney Canyon 2000 (we refer to Whitney Canyon 2000 because the Petitioners did not advance specific argument on this issue), we understand the core of Petitioners’ claim to be that the same parties, the same property and the same issues were previously decided by the Wyoming Supreme Court, Amoco Production Company v. Wyoming State Board of Equalization, 882 P.2d 866 (Wyo. 1994), or by this Board in Appeal of Amoco Production Company, SBOE Docket 91-174, 1992 WL 126533 (Wyo. St. Bd. Eq. 1992). Whitney Canyon 2000, ¶193. We have concluded to the contrary. Conclusions, ¶340.

383. The principal issue in this case is whether the Department’s valuation is in accordance with constitutional and statutory requirements for valuing state-assessed property for production year 2001. Conclusions, ¶302. This issue was not and could not have been decided in a previous proceeding. Tenorio,, 931 P.2d at 238-239. Neither this Board nor the Court previously had jurisdiction to rule on anything related to the matter of production in 2001. Production year 2001 valuations were not identified as issues by the parties in the previous proceedings. No such issue was decided by the Board as a fact finder. The Board did not purport in earlier proceedings to determine any questions related to production year 2001. The earlier judgments of the Court and the Board were not dependent upon determination of the any issues with regard to production year 2001. On this basis alone, we conclude that the doctrine of collateral estoppel does not apply. We do not deem it necessary to list the many issues that were decided in this case, but were not previously advanced and decided. Any concern for relitigation is groundless.

384. The subject matter of this case is the Department’s application of the comparable value method to value Petitioners’ gas production for production year 2001, and a variety of specific claims regarding application of that method. Findings, ¶¶37-248. This factor alone is enough for us to conclude that the doctrine of res judicata does not apply, although further analysis would show a general failure to meet the criteria for res judicata. Livingston, 861 P.2d at 551-552.

385. Based upon our ruling in Whitney Canyon 2000 (we refer to Whitney Canyon 2000 because the Petitioners did not advance specific argument on this issue), we understand taxpayers to argue that, some ten years ago, the Department took a different position with respect to the application of the phrase “other parties” than it does now, directing our attention to Amoco Production Company, 882 P.2d 866. Since the Department did not succeed in employing the method advanced in 1992, we conclude that judicial estoppel does not apply. Eagle Foundation, Inc., v. Dole, 813 F.2d at 810; Matter of Cassidy, 892 F.2d at 641; 74 Am. Jr. 2d Estoppel and Waiver §73, p. 498. Having reached this conclusion, we find it unnecessary to discuss other defects in the application of judicial estoppel in this case, or the application of the principle that “the initial position taken must be one regarding fact.” Willowbrook Ranch v. Nugget Exploration, 796 P.2d 769, 771 (Wyo. 1995). See generally, Whitney Canyon 2000, ¶¶201-203.

386. The Petitioners did not carry their burden of persuasion. They failed to show that the Department’s valuation was not in accordance with constitutional and statutory requirements for valuing state-assessed property, or to show that the Department’s valuation was contrary to its rules, regulations, orders or instructions.

ORDERIT IS THEREFORE HEREBY ORDERED: The Department’s determination of the value of Petitioners’ 2001 gas production is affirmed.

Pursuant to Wyo. Stat. Ann. §16-3-114 and Rule 12, Wyoming Rules of Appellate Procedure, any person aggrieved or adversely affected in fact by this decision may seek judicial review in the appropriate district court by filing a petition for review within 30 days of the date of this decision.