Court Opinion

ID: 6655215
Source: CourtListenerOpinion
Date Created: 2022-07-20 20:57:16.04465+00
Date Added: 2024-06-11T15:59:52.279923
License: Public Domain

*631OPINION
HEWITT, Judge.
I. Background
A. Overview of Claims and Trial
This case is before the court following trial on the allegations raised by plaintiff Osage Tribe of Indians of Oklahoma1 (Osage Nation or Osage Tribe) that the United States violated its duty as trustee of the Osage mineral estate by failing to collect all moneys due from Osage oil leases and to deposit and invest those moneys as required by statute and according to the fiduciary duty owed to the Osage Tribe. Plaintiffs claims were divided into two tranches with the first tranche (Tranche One) encompassing trust fund mismanagement claims within the parameters described by the United States Court of Appeals for the Federal Circuit in Shoshone Indian Tribe of the Wind River Reservation v. United States, 364 F.3d 1339, 1350-51 (Fed.Cir.2004) (Shoshone). The second tranche (Tranche Two) encompasses all other claims. See Order of April 15, 2005 at 1 (filed in The Osage Nation and/or Tribe of Indians of Okla. v. United States, case no. 00-169L). Tranche One of the ease is further limited to consideration of four oil and gas leases2 for the following five months: January 1976, May 1979, November 1980, February 1986, and July 1989. Id.
The Osage Nation identified two trust fund mismanagement claims that it considered to be within the parameters set in Shoshone. First, plaintiff claims that “the United States, as trustee, has failed to collect payments due under the Tranche One [l]eases for the [T]ranche [0]ne months, including but not limited to, royalties on crude oil or natural gas that was produced by those leases during those months and late payment fees.” Osage Nation’s Statement of Trust Fund Mismanagement Claims for Tranche One (T1 Statement of Claims) 4-5. Plaintiff further claims that “[i]n the ease of royalty payments, the United States, as trustee, failed to compute the royalty in the manner prescribed by the applicable lease provisions and regulations” and “failed to collect these [royalty] payments in a timely manner.” Id. at 5. Plaintiff also claims that, by failing to collect the royalty payments due under the Tranche One leases, the United States deprived the Osage Nation of “late payment fees that are due under the Tranche One [l]eases and regulations for payments that were not collected in a timely manner.” Id.
The second claim identified by plaintiff under Tranche One is that “[t]he United States, as trustee, failed to invest the income that it did collect ... in the manner prescribed by law.” Id. Plaintiff further alleges that the United States “failed to deposit funds in an interest bearing account within a reasonable time after it received the funds ... [,] failed to invest to funds as required by law ... [,][and] failed to credit the Osage Nation with the full amount of investment income that the funds earned prior to the time the funds were disbursed to the beneficiaries of the trust.”3 Id. at 6.
*632This action is founded on the alleged breach of duties assumed by the United States under the terms of an agreement between the Osage Tribe and the United States enacted into law in 1906.4 See Act of June 28, 1906, ch. 3527, 34 Stat. 539 (1906 Act). The 1906 Act, titled “An act for the division of the lands and funds of the Osage Indians in Oklahoma Territory, and for other purposes,” provides, by section 2, “[t]hat all lands belonging to the Osage tribe ... shall be divided among the members of said tribe” with minor exceptions for retaining small tracts primarily for administrative and educational facilities. 34 Stat. at 540. Section 3 of the 1906 Act reserved oil, gas, coal and other minerals to the Tribe for a period of twenty-five years and provides that “leases for all oil, gas, and other minerals ... may be made by the Osage tribe of Indians through its tribal council, and with the approval of the Secretary of the Interior, and under such rules and regulations as he may prescribe.” 34 Stat. at 543. This reservation of the mineral interests to the Tribe has been routinely extended over time,5 and it was made a reservation in perpetuity by the Act of October 21, 1978, Pub.L. No. 95-496, 92 Stat. 1660. Section 4 of the 1906 Act provides:
That all funds belonging to the Osage tribe, and all moneys due, and all moneys that may become due, or may hereafter be found to be due the said Osage tribe of Indians, shall be held in trust by the United States....
Second. That the royalty received from oil, gas, coal, and other mineral leases upon the lands for which selection and division are herein provided ... shall be placed in the Treasury of the United States to the credit of the members of the Osage tribe of Indians as other moneys of said tribe are to be deposited under the provisions of this Act, and the same shall be distributed to the individual members of said Osage tribe according to the roll provided for herein, in the manner and at the same time that payments are made of interest or other moneys held in trust for the Osages by the United States....
34 Stat. at 544 (emphasis added).
The court, in Osage Tribe of Indians of Okla. v. United States, 68 Fed.Cl. 322 (2005) (Osage I), found that “the plain language of section 4 of the 1906 Act establishes fiduciary duties that include both the proper management of Osage funds on deposit with the Treasury and the proper accounting of ‘all moneys due, and all moneys that may become due,’ 34 Stat. at 544, in accordance with the terms of the oil and gas leases.” Osage I, 68 Fed.Cl. at 327. The proper accounting of royalty payments necessarily encompasses “verification that the royalty paid is the amount contractually owed under the terms of the lease.” Id. at 328. The court declined at that time to determine the standard to which government should be held in carrying out its duty to invest Osage moneys under the 1906 Act and relevant investment statutes and ordered subsequent briefing “clarifying the specific legal grounds for [plaintiffs] investment claim against defendant.” Id. at 335-36. The parties’ briefs6 informed *633the preparation of their respective pretrial memoranda. The issues raised in briefing are resolved in this Opinion in the light of the testimony presented and evidence admitted at trial.
The government’s responsibility for management of the Osage mineral estate is implemented by the Bureau of Indian Affairs (the BIA) of the Department of the Interior (DOI) through the Osage Agency located in Pawhuska, Oklahoma. See Stipulations of Fact (Stip. of Fact) ¶ 1. The Osage Reservation encompasses all of present-day Osage County, located in northern Oklahoma, and covers approximately 1.47 million acres. Id. ¶ 2. The first oil and gas lease on the Osage Reservation was entered into in 1896 and the first completed well was drilled in 1897.7 Osage County ranks among the top two oil-producing counties in the United States. Trial Transcript (Tr.) 84:13-21 (Reineke). The regulations that guide the Osage Agency in managing oil and gas leasing and operations on Osage Reservation lands and the leases negotiated by the Tribe and approved by the Secretary of the Interior (the Secretary), provide, respectively, the regulatory and contractual framework within which plaintiffs challenges to defendant’s execution of its fiduciary duty to collect “all moneys due” plaintiff as royalty payments arise. See T1 Statement of Claims 3-4.
Plaintiffs royalty collection and investment claims were the focus of a ten-day trial during which the court heard testimony from seventeen witnesses8 and admitted 168 ex-*635Mbits were admitted into evidence. The depositions of fourteen witnesses, including six Rule 30(b)(6) witnesses, were also admitted into evidence.9 The parties filed both pretrial and post-trial briefing.
B. Royalty Calculation and Collection-Overview of Regulatory History
The government’s duty to collect oil and gas royalty payments and to verify that the proper amounts have been paid is set out in the 1906 Act, as amended, the regulations established to implement its requirements, and in the terms of Osage oil and gas leases. See 1906 Act, §§ 3, 4, 12, 34 Stat. at 543-45; Osage I, 68 Fed.Cl. at 327; 25 C.F.R. § 226 (2005); see also Def.’s Post-Trial Brief (Def.’s Br. or Brief) 3; Def.’s Pretrial Memorandum of Contentions of Fact and Law (Def.’s Pretrial Mem.) 4; Plaintiff Osage Nation’s Post-Trial Brief (Pl.’s Br. or Brief) 2. The 1906 Act assigns to DOI the responsibility for managing oil, gas and other mineral leases “under such rules and regulations as [the Secretary] may prescribe.” 1906 Act § 3. DOI has issued regulations governing gas and oil leasing specific to the Osage Reservation10 that have remained substan*636tially consistent from those first issued to implement the 1906 Act to the present day. See Osage I, 68 Fed.Cl. at 332 & nn. 11-12. Because the leases incorporate by reference the regulations, Joint Exhibits (JXs) 6, 7, 8, 10,11,12,15, the regulations are the focus of the court’s analysis of the collection duties of defendant as trustee.11 The parties urge sharply differing legal interpretations of several of the regulations governing the calculation of oil royalty payments.
Oil royalty payments are based on three factors: royalty rate, volume of oil, and royalty value, and may be expressed by the formula:
Royalty Due = Royalty Rate x Volume x Royalty Value.
See Pl.’s Br. 2; Tr. 80:24-81:20 (Reineke); Def.’s Br. 3; Tr. 1390:9-15 (Martin). In briefing, the parties use different words to express the last element of the formula: plaintiff uses the term “royalty value” while defendant uses the term “royalty price.” See Pl.’s Br. 2; Def.’s Br. 3. Because this element is itself the product of a calculation rather than an independent price term, the court uses the term “royalty value.”
Royalty rate is usually expressed as a fraction, such as 1/8 or 1/6, or as a percentage, 12 1/2% or 16 2/3%, respectively, of the value of production. See Stip. of Facts ¶ 8. Royalty rates were determined by the President of the United States until 1950. See 1906 Act § 3. After 1950, rates could be set by the Osage Tribal Council, subject to approval by the Secretary, Pub.L. No. 548, 64 Stat. 215 (1950). The method for determining royalty value is provided in the regulations and leases, with the value expressed in United States dollars and cents per barrel. See Stip. of Fact ¶ 8.
In order to set the parties’ arguments in context, the court provides an overview of the regulatory history.
1. 1912 Regulations and 1915 Regulations
The first set of regulations issued after enactment of the 1906 Act calculated royalty payments by applying a fixed royalty rate to the gross proceeds from all oil sold from a given lease, with payment based on the higher of the actual market value (or selling price) or a minimum value established under the regulations. See Regulations to Govern the Leasing of Lands in the Osage Reservation, Okla., for Oil and Gas Mining Purposes, Department of the Interior, July 3, 1912 (1912 Regulations). The 1912 Regulations provided, in pertinent part, that
(a) On oil the rate of royalty shall be sixteen and two-thirds percent (16 2/3%) of the gross proceeds of all oil produced from the leased premises and such royalty shall be paid in money, based on the actual market value, not less than the guaranteed minimum value of sixty (60) cents per barrel....
1912 Regulations ¶ 20. All oil and gas lease payments, including royalties, were to be paid to the superintendent at the Osage Indian School at Pawhuska, Oklahoma (then the administrative site of the BIA’s Osage Agency), id. ¶21, with payment of oil and gas royalties produced in one month to be made “on or before the twenty-fifth (25th) day of the month next succeeding,” id. ¶22, the month of production. The lease forms used for all Osage oil and gas leasing repeated these provisions, see 1912 Regulations, Form B. Oil and Gas Mining Lease, Osage Reservation, Oklahoma ¶2, and also incorporated as terms of the lease all current and future Osage regulations, id. ¶ 9 (“This lease shall *637be subject to the regulations of the Secretary of the Interior, now or hereafter in force, relative to such leases, all of which regulations are made a part and condition of this lease____”).
The royalty calculation provisions in the 1912 Regulations had two notable shortcomings: first, “actual market value” was not a defined term and therefore raised the prospect of conflict should the price reported by the lessee fall below what the lessor or the Osage Agency might consider to be the market value at the time; and, second, by setting the floor price at a fixed value, the “guaranteed minimum” could not respond to market fluctuations over time without a formal change in the regulations. In 1915, DOI published new regulations that addressed these deficiencies by replacing the vague term “actual market price” with the term “actual selling price” received for oil from a lease, and by incorporating an objective market-based value tied to the regional oil market as a flexible mechanism for setting the floor price. See Regulations to Govern the Leasing of Lands in the Osage Reservation, Okla., for Oil and Gas Mining Purposes, Department of the Interior, August 26, 1915 (1915 Regulations). These changes were incorporated into Form B, the standard oil and gas lease form for the Osage Reservation, as follows:
The lessee agrees to pay or cause to be paid to the superintendent of the Osage Indian Agency, at Pawhuska, Okla., for the lessor, as royalty, the sum of 16$ per cent of the gross proceeds from sales after deducting the oil used for fuel in operating the lease, unless the Osage tribal council, with the approval of the Secretary of the Interior, shall elect to take the royalty in oil; payment to be made at time of sale or removal of the oil, except where payments are made on division orders,12 and settlement shall be based on the actual selling price, but at not less than the highest posted market price in the Mid-Continent oilfield on the day of sale or removal ....
1915 Regulations, Form B. ¶ 2 (emphasis and footnote added). The 1915 Regulations furthered the objective of capturing the highest royalty for the Osage Tribe from the gross proceeds from sales, offset by the value of oil consumed in the process of production, by adding the refinement that payment would be based on the higher of either the selling price reported by the lessee or the highest price posted anywhere in the Mid-Continent oil field13 on that day. Id. “Posted price” is a term of art with a specific meaning with deep historical roots in the oil industry. See Stip. of Fact ¶ 5 (“ ‘Posted prices’ are so named because in former times a prospective purchaser (usually a refiner) would tack a sheet to a post in a producing field stating how much it might be willing to pay for a crude oil or blend of oils of standardized quality (e.g. Oklahoma Sweet, West Texas Intermediate, Louisiana Light).”); Howard R. William & Charles J. Meyers, Manual of Oil and Gas Terms 856 (12th ed. 2003) (Williams & Meyers) (stating that, in the oil industry, posted price is “a written statement of crude petroleum prices circulated publicly among sellers and buyers of crude petroleum in a particular field in accordance with historic practices, and generally known by sellers and buyers within the field”). By selecting the Mid-Continent oil field as the geographic reference area, the BIA expressed an apparent intent to establish a broad regional basis for determining the market price of Osage oil.
2. 1974 Regulations
In April 1974, the BIA “proposed to completely revise Part 183 of ... Title 25 of the *638Code of Federal Regulations.” 39 Fed.Reg. 12,755 (April 8, 1974). The final regulations were published on June 21, 1974 with only minor changes and became effective on July 22, 1974. 39 Fed.Reg. 22,254 (June 21, 1974); 25 C.F.R. Part 183 (1975) (1974 Regulations). Of particular significance to the issues raised at trial are changes in the method of determining royalty value and the addition of measures to verify the amount of royalty owed against the payment received by the Osage Agency. See 25 C.F.R. §§ 183.1, 183.11, 183.14. Under the 1974 Regulations, royalty payments are based on a new formula that retained the earlier provisions for calculating royalty on the higher of the posted price or actual selling price, but added a third term price that is “offered” — that would capture the value of any premiums or bonuses offered for crude oil over the highest posted price in the geographic area of reference. See 25 C.F.R § 183.11(a)(2). The revised portion of the 1974 Regulations regarding the calculation of royalty due provided, in part, that
[u]nless the Osage Tribal Council, with the approval of the Secretary, shall elect to take the royalty in kind, payment shall be made at the time of sale or removal of the oil, except where payments are made on division orders, and settlement shall be based on the actual selling price, or the highest posted or offered price by a major purchaser in the Kansas-Oklahoma area whichever is higher on the day of sale or removal. Where different prices are paid simultaneously for oil from a lease and the highest such price exceeds the higher of the aforementioned prices, then that price shall be the basis of royalty on all oil from said lease.
Id. (emphasis added). Neither the notice of proposed rule change, 39 Fed.Reg. 12,755, nor the notice and publication of the final regulations, 39 Fed.Reg. 22,254, provided an explanation of the changes in the formula for royalty value or in the geographic reference area, or the addition of a sentence setting royalty value in the ease of simultaneous sales at different prices from the same lease. The only purpose noted by the BIA in making the rule change was “to improve the management of the Osage oil and gas mineral estate.” 39 Fed.Reg. at 22,254.
The BIA also re-defined the geographic reference area as Kansas-Oklahoma. See 25 C.F.R. § 183.11(a)(2). The 1974 Regulations also restricted the highest posted price and offered price terms used to determine royalty value to those posted or offered by a “major purchaser” in the Kansas-Oklahoma area. See 25 C.F.R. § 183.11(a)(2). The 1974 Regulations defined major purchaser as “any one of the minimum number of purchasers taking 80 percent of the oil in the Kansas-Oklahoma area.” 25 C.F.R. § 183.1(h). This change limited the number of purchasers the Osage Agency was required to monitor to determine the highest posted and offered price in the region and identified the principal parties who would influence crude oil market prices and the resulting royalty value to be used in calculating royalties for the Osage Tribe.
The 1974 Regulations also established a reporting mechanism that provided the means for the Osage Agency to cross-check lessee reports of crude oil sales with purchasers’ records of crude oil purchases from the same lease. See 25 C.F.R. §§ 183.13(b), 183.14(b). As to lessees, the 1974 Regulations required lessees “to furnish certified monthly reports by the 25th of each following month covering all operations, whether there has been production or not, indicating therein the total amount of oil, natural gas, casing-head gas, and other products subject to royalty payment.” Id. As to purchasers, the BIA required purchasers for the first time to submit monthly statements for all oil and gas purchases made from an Osage lessee. Compare 25 C.F.R. § 183.14(b) (“Lessee shall require the purchaser of oil and/or gas ... to furnish the Superintendent with a monthly statement of the gross barrels and/or gross Mcf14 sold not later than the 15th day of each month which shall cover the preceding month.”) (emphasis added), with 25 C.F.R. § 183.88(b) (1962) (“The lessee *639shall also authorize the pipeline company or the purchaser of oil to furnish the Superintendent with a monthly statement, not later than the 20th day of the following calendar month, of the gross barrels run as a common-carrier shipment or purchased from his lease or leases.”) (emphasis added). Lessees could enter into division orders or sales contracts with a purchaser that called for the latter to make the royalty payment to the Osage Agency. See 25 C.F.R. § 183.14(a). The division order or sales contract, in that case, would “provide for the purchaser to make payment of royalty in accordance with [the lessee’s] lease.” Id. (emphasis added). Purchasers who entered into such agreements were, therefore, necessarily aware of the formula for establishing royalty value and calculating royalty payments, including the incorporation of “offered price” as a third term in the formula, along with “actual selling price” and “highest posted price.”
From the foregoing regulatory history, the court concludes that the BIA understood the regulations it promulgated in 1974 and that remained in effect until 1990 to require royalty payments to be based on the higher of (1) the actual selling price received by a lessee, or (2) the highest posted or offered price in the Kansas-Oklahoma area made by a major purchaser — even where that highest price was posted or offered by a purchaser who did not also buy crude oil from Osage lessees. 39 Fed.Reg. 22,254, 22,256. This regulatory framework was in effect for all of the five Tranche One months: January 1976, May 1979, November 1980, February 1986, and July 1989.
3. Regulations After the Tranche One Period
The government attempted to support its arguments about the interpretation of the regulations in effect during the Tranche One period by invoking regulations adopted and a regulatory interpretation issued by the DOI Board of Indian Appeals (IBIA) after the Tranche One period. Therefore, the court reviews these developments in this overview.
a. 1990 Regulations
The regulations15 were further modified in 1990, see 55 Fed.Reg. 33,112 (Aug. 14, 1990) (1990 Regulations). The proposed revisions to 25 C.F.R. § 226 were published in the Federal Register for public comment on October 16, 1987. See 52 Fed.Reg. 38,608 (October 16, 1987). The stated purpose of the proposed rule change was “to strengthen the management of the Osage Mineral Estate by the Bureau of Indian Affairs and the Osage Tribal Council and to provide economic relief to oil lessees imposed by 25 C.F.R. § 226.11(a)(2).” Id. The BIA explained that the proposed changes “will alleviate the necessity for many of the oil lessees to pay the Osage Tribe more for its royalty oil than paid by crude oil purchasers” and that, while the change “may reduce the tribal income[,]” it could also “curtail the plugging of marginal wells” and “be cost effective to the Tribe.” Id.
The 1990 Regulations reduced the geographic reference area from “the Kansas-Oklahoma area” to Osage County Oklahoma. See 25 C.F.R. §§ 226.1(h), 226.11(a)(2) (1991). The 1990 Regulations also changed somewhat the wording of the formula for royalty value but retained the three elements in the 1974 Regulations for establishing royalty value: selling price, offered price, and posted price. The new regulations stated, in part, that
[ujnless the Osage Tribal Council, with approval of the Secretary, shall elect to take the royalty in kind, payment is owing at the time of sale or removal of the oil, except where payments are made on division orders, and settlement shall be based on the highest of the bona fide selling price, posted or offered price by a major purchaser (as defined in s 226.1(h)) in Osage County, Oklahoma, who purchases production from Osage oil leases.
25 C.F.R. § 226.11(a)(2) (emphasis added). Under the new definition, “[mjajor purchas*640er means any one of the minimum number of purchasers taking 95% of the oil in Osage County, Oklahoma.” 25 C.F.R. § 226.1(h). The new definition of major purchaser also included a provision that removed crude oil transfers or sales between affiliates and other forms of related businesses from the calculation of who was considered a major purchaser. Id. (“Any oil purchased by a purchaser from itself, its subsidiaries, partnerships, associations, or other corporations in which it has a financial or management interest shall be excluded from the determination of a major purchaser.”).16
When the 1990 Regulations were proposed in 1987, the BIA stated that
[cjurrently over 95 percent of the purchase of oil in Osage County, Oklahoma, is by three companies, each of which qualifies as a “major purchaser” as defined under the [1974] regulations; therefore, any price increase they would contemplate would increase the “highest posted price” under either the [ 1974 Regulations] or proposed section.
55 Fed.Reg. 33,112. By “chang[ing] the definition of ‘major purchaser’ to include only those companies purchasing oil in Osage County,” the BIA maintained that lessees would be “relieved] ... from paying a higher price for royalty oil than they could receive.” Id. This would occur, for example, if a purchaser qualified as one of the major purchasers based on its regional purchases offered a higher posted price or bonus for oil purchased outside of Osage County than was offered by any major purchaser for oil sold by Osage County lessees. 55 Fed.Reg. 33,-113 (explaining that current regulations use the highest price posted in the region, even if the purchaser does not buy oil in Osage County). While the BIA acknowledged that 95% of Osage oil was purchased by only three companies, the BIA explained the increase under the 1990 regulations in percentage of purchases required to constitute the major purchaser group from 80% to 95% as “providing] a vehicle to increase the number of purchasers to qualify as ‘major purchasers.’” Id. at 33,112.
The change of the geographic reference area from the Kansas-Oklahoma area in the 1974 regulations to Osage County, Oklahoma in the 1990 Regulations generated a high degree of opposition when it was proposed. Ninety-three comments were received on the changes proposed to 25 C.F.R. § 226.11(a)(2)17 alone, all but one objecting to the change; the next highest number of comments generated about a specific regulation was three. 55 Fed.Reg. 33,113. The narrative provided by the BIA in its review of the comments and its statement of the purpose and meaning of the proposed changes states why the BIA disregarded the unfavorable comments.
Ninety-three comments were received on this section. The commenters objected to basing the highest posted price by a major purchaser (as defined in § 226.1(h)) in Osage County, Oklahoma, rather than Kansas-Oklahoma area, stating that such change would reduce the Osage tribal income. One eommenter thought that the change would be beneficial. Under the current regulations, if the “major purchaser” setting the highest posted price does business in the Kansas-Oklahoma area but does not purchase oil in Osage County, Oklahoma, the Osage County, Oklahoma, lessees would be required to pay royalty based on a price higher than the highest price the lessees could possibly receive. The revision of this section can prevent this from happening. This could have a beneficial effect on the exploration and de*641velopment of oil leases. The comments are, therefore, not accepted.
55 Fed.Reg. 33,113. Despite the opposition, the BIA thus believed the rule change could have a beneficial effect. The BIA acknowledged that the change could result in decreased royalty payments to the Tribe, see 52 Fed.Reg. 38,608 (“This may reduce the tribal income; however, such action may curtail the plugging of marginal wells.”), but asserted that the change was justified by the need to “alleviate the economic hardship placed on the oil lessees,” 52 Fed.Reg. 38,-608, and by the potential for future exploration and development of oil leases, 55 Fed. Reg. 33113.
b. 1993 Regulations and Okie Crude Co.
The Bureau of Indian Affairs proposed a further regulatory change in November 1993 that would remove the “offered price” term from the calculation of royalty value. See 58 Fed.Reg. 59,142 (Nov. 5,1993) (“The purpose of this proposed rule is to amend 25 C.F.R. [§ ] 226.11(a)(2) to eliminate premium, bonus, or other like payments from consideration in the calculation of the royalty price or crude oil in Osage County.”). The proposed § 226.11(a)(2), as amended, provided that
(2) Unless the Osage Tribal Council, with approval of the Secretary, shall elect to take the royalty in kind, payment is owing at the time of sale or removal of the oil, except where payments are made on division orders, and settlement shall be based on the actual selling price, but at not less than the highest posted price by a major purchaser (as defined in [25 C.F.R.] § 226.1(h)) in Osage County, Oklahoma, who purchases production from Osage oil leases.
58 Fed.Reg. 59,142. The BIA acknowledged that its long-standing interpretation of the royalty value formula in 25 C.F.R. § 226.11(a)(2) was that an offered price made and paid to a lessee anywhere in the mandated geographic reference area was to be used for calculating royalty value for all lessees on the Osage Reservation. See 58 Fed.Reg. 59, 142. In its explanation of the proposed change, the BIA indicated that it was motivated by complaints made by some lessees that the rule as applied was discouraging some purchasers from paying bonuses:
The existing regulation was the subject of administrative appeals by numerous oil producers over the meaning of: “and settlement shall be based on the highest of the bona fide selling price, posted or offered price by a major purchaser (as defined in Sec. 226.1(h)) in Osage County, Oklahoma, who purchases production from Osage oil leases.” The Bureau of Indian Affairs has interpreted that language to mean that when a higher pnce is offered and paid for crude oil in Osage County, that price shall he used for royalty computation for all oil of the same quality sold in the County. However, there is reason to believe that this interpretation has discouraged purchasers from offering bonus prices.
58 Fed.Reg. 59,142 (emphasis added). The explanation of the proposed rule change also cites the conclusion of the Interior Board of Indian Appeals (IBIA) in Okie Crude Co. v. Muscogee Area Director, Bureau of Indian Affairs, 23 IBIA 174 (1993) that “the current regulations require a producer to pay royalty on the highest price available to it, whether or not it actually receives that price. Prices not available to a producer would not be used to calculate royalties due from that producer.” 58 Fed.Reg. 59,142. The rule change would therefore “eliminate the language that caused the differences in interpretation that led to the appeals to the IBIA.” Id. The BIA acknowledged that oil producers sought the rule change and stated that the BIA had determined that the proposed change “would remove the existing disincentive to purchasers to remain in Osage County resulting from bonus payments paid to some producers but not all.” Id. The BIA concluded that the ability of producers to receive bonuses without paying royalty to the Osage Tribe on the bonus payment “would increase mineral activity in the Osage mineral estate.” Id. The final 1993 Regulations were published on April 28, 1994 in the form proposed. See 59 Fed.Reg. 22,104 (Apr. 28,1994) (amending 25 C.F.R. § 226.11(a)(2)).
*642C. Price Controls
An additional source of disagreement between the parties is the price control regime implemented following the embargo by the Organization of Oil Producing Countries on oil sales to countries that had supported Israel in the Arab-Israeli war of October 1973. As a result of the embargo, oil prices that had earlier been in decline quadrupled, with economic ramifications for both the oil industry and the national economy. See Energy Reserves Group, Inc. v. Dep’t of Energy, 690 F.2d 1375, 1380 (Temp.Emer.Ct.App.1982) (DOE Stripper Well Litigation); Energy Information Administration, Dep’t of Energy, Petroleum Chronology of Events 1970-2000, May 2002, http//www.eia.doe.gov/pub/oil—gas/petroleum/analysis—publications/chronology/petroleum chronology2000.htm (last visited September 21, 2006).
The United States responded in part by enacting the Emergency Petroleum Allocation Act (EPAA) and subsequent amendments. EPAA, Pub.L. No. 93-159, 87 Stat. 627 (1973) (codified at 15 U.S.C. §§ 751-760(h)), repealed by Pub.L. No. 94-163, tit. IV § 461 (Dec. 22,1975). Through a national emergency program of price and supply regulations, Congress sought to reduce the adverse economic effects of disruptions of domestic oil and petroleum supplies and to provide incentives for expanded production under price controls. EPÁA § 2(a)-(b), 15 U.S.C. § 751(a)-(b)(1976); see also Def.’s Pretrial Mem. 59-62; Air Transp. Ass’n of America v. Fed. Energy Office, 382 F.Supp. 437, 440-41 (D.D.C.1974) (noting that Congress explained the necessity for the EPAA as based on “[f]indings of an impending energy crisis and possibly deleterious effects resulting therefrom”). Section four of the EPAA required the President to promulgate regulations within fifteen days of the enactment of the EPAA governing the allocation and pricing of petroleum products, including crude oil, residual fuel oil, and refined petroleum products. EPAA § 4(a). The regulations were to become effective no later than fifteen days following their promulgation by the President and were to apply “to all crude oil, residual fuel oil, and refined petroleum products produced in or imported into the United States.” Id. The regulations were to “specify (or prescribe a manner for determining) prices of crude oil at the producer level” unless the President found — and reported the basis of the finding to Congress — that allocation at a given level was not necessary to accomplish the EPAA’s objectives. EPAA § 4(e)(1) (emphasis added).
Congress made an exception from the mandatory price controls for crude oil from stripper well leases, that is, leases whose average daily production of crude oil during the preceding year was under ten barrels per well. EPAA § 4(e)(2)(a); see also DOE Stripper Well Litig., 690 F.2d at 1380-81 (reviewing the history of the stripper well exemption and legislative history of the EPAA definition of stripper well). Specifically, the EPAA provided that “[t]he regulations promulgated under subsection (a) of this section shall not apply to the first sale of crude oil produced in the United States from any lease whose average daily production of crude oil for the preceding calendar year does not exceed ten barrels per well.” EPAA § 4(e)(2)(a).
II. Alleged Failures to Collect Moneys Due Under Leases
A. Standard of Care Applicable to the Government as Fiduciary in the Collection of Royalties
In Osage I, the court concluded that under the 1906 Act, “the defendant, as trustee, has a specific duty to verify that ‘all moneys due’ under the terms of the mineral leases were in fact paid to the government and deposited to the account of the trust beneficiary.” 68 Fed.Cl. at 328. In discharging its trust duty, the United States is held to a strict fiduciary standard and is to take “all appropriate measures for protecting and advancing” the Tribe’s interests. United States v. Creek Nation, 295 U.S. 103, 109-10, 55 S.Ct. 681, 79 L.Ed. 1331 (1935); see Shoshone Indian Tribe v. United States, 364 F.3d 1339, 1348 (2004) (“Because of its treaty and statutory obligations to tribal nations, the United States must be held to the ‘most exacting fiduciary standards’ in its relationship with the Indian beneficiaries” (quoting Coast Indian Cmty. v. United States, 213 Ct.Cl. 129, *643550 F.2d 639, 652 (1977))). In United States v. Mason, 412 U.S. 391, 93 S.Ct. 2202, 37 L.Ed.2d 22 (1973), the Supreme Court states that when “the United States serves in a fiduciary capacity with respect to ... Indians ..., it is duty bound to exercise great care in administering its trust.” 412 U.S. at 398, 93 S.Ct. 2202 (citing Seminole Nation v. United States, 316 U.S. 286, 296-97, 62 S.Ct. 1049, 86 L.Ed. 1480 (1942)).
Plaintiff argues that, “[i]n construing the applicable statutes and regulations, the [c]ourt must adhere to ‘[t]he canons of construction applicable in Indian law,’ ” Pl.’s Br. 3 (quoting County of Oneida v. Oneida Indian Nation, 470 U.S. 226, 247,105 S.Ct. 1245, 84 L.Ed.2d 169 (1985)), which hold that “‘statutes are to be construed liberally in favor of the Indians, with ambiguous provisions interpreted to their benefit,’ ” id. (quoting Montana v. Blackfeet Tribe of Indians, 471 U.S. 759, 766, 105 S.Ct. 2399, 85 L.Ed.2d 753 (1985)), and that the “trust relationship and its application to all federal agencies that may deal with Indians necessarily requires the application of a similar canon of construction to the interpretation of federal regulations,” id. (quoting HRI, Inc. v. EPA, 198 F.3d 1224, 1245 (10th Cir.2000)). The United States proposes that, “[t]o the extent the statutory and regulatory language is silent ..., the [c]ourt should apply a reasonableness standard to determine whether there has been a breach.” Def.’s Br. 4. For plaintiff, “[t]he ‘standard of duty for the United States ... is not mere “reasonableness” but the highest fiduciary standards.’ ” Pl.’s Br. 4 (quoting Minn. Chippewa Tribe v. United States, 14 Cl.Ct. 116, 130 (1987)) (emphasis omitted).
In Osage I, the court found that “[i]t is clear that the government has taken on not only the principal, but the sole, responsibility for managing lease revenues.” 68 Fed.Cl. at 332-33. The unique trust responsibility involved in defendant’s management of the Osage mineral estate and the Osage royalty income requires the trustee to exercise a standard of care beyond “mere reasonableness.” See Minn. Chippewa Tribe, 14 Cl.Ct. at 130 (finding the reasonableness standard, judged by the “arbitrary and capricious” test, was not applicable in a case involving the management of Indian funds raised from land sales). The United States established a comprehensive regulatory structure for managing oil and gas leases and “is to consider its strict fiduciary obligation when interpreting regulations” that it developed for that purpose. HRI, Inc., 198 F.3d at 1246.
Defendant has the responsibility properly to construe the legal framework that sets out its trust duties. Defendant’s failure to interpret accurately its trust duties, when such failure results in a loss of revenue to the Osage Tribe, is deemed a breach of defendant’s trust duties. In carrying out its trust duties, in accordance with law properly interpreted, defendant will be held responsible for exercising the care and skill that a trustee would exercise in the discharge of its responsibilities under exacting fiduciary standards. Shoshone, 364 F.3d at 1348. In cases where defendant, in discharging its responsibilities properly construed, put in place procedures to carry out those responsibilities, the court evaluates whether the procedures were reasonably calculated to result in compliance with the 1974 Regulations.
B. Whether the Osage Agency Properly Interpreted the Regulations Establishing Royalty Value
1. Offered Price
Defendant argues that, because the term “offered price” is not defined in the regulations, it should be “deemed to have its ordinarily understood meaning.” Def.’s Br. 7 (citing, inter alia, Perrin v. United States, 444 U.S. 37, 42, 100 S.Ct. 311, 62 L.Ed.2d 199 (1979); Demko v. United States, 44 Fed. Cl. 83, 87 (1999)). The court agrees that this well-established canon of statutory construction is applicable here. See, e.g., Fed. Deposit Ins. Corp. v. Meyer, 510 U.S. 471, 476, 114 S.Ct. 996, 127 L.Ed.2d 308 (1994) (FDIC v. Meyer) (citing Smith v. United States, 508 U.S. 223, 228, 113 S.Ct. 2050, 124 L.Ed.2d 138 (1993) (noting that in the absence of a statutory definition, “we construe a statutory term in accordance with its ordinary or natural meaning”)). The court also agrees with defendant that “[i]n contrast to a ‘posted price,’ an ‘offered price’ need not be made in *644writing or to all producers.” Def.’s Br. 7. Under the 1974 Regulations, the term “offered price” was introduced as a means of capturing the market value represented by bonus or premium payments that were offered to some but not all producers by a major purchaser over the posted price. This interpretation was fully supported in the evidence at trial. See Defendant’s Exhibit (DX) 2334-1 (letter from the Osage Agency notifying purchasers that, under the 1974 Regulations, “[i]f your company hasn’t met the highest offered price for stripper oil, the oil lessees ... are liable for additional royalty due on the difference between the price paid by your company and that paid by the major purchasers ... who have offered a higher price in the Kansas-Oklahoma area”); Tr. 1296:23-1297:18 (Barker).18
Defendant attempted to jettison its own line of argument (supporting the ordinarily understood meaning of the term) and sought to impose a narrow definition of “offered price” by focusing solely on the meaning of the word “offer” within the context of mutual assent in contract law. See Def.’s Br. 7. According to defendant, “an ‘offered price’ is the price presented to a producer by a willing buyer for a given quantity and quality of crude oil. It sets the basis for royalty only as to those lessees to whom the offer was extended.” Id. (citing Black’s Law Dictionary 746 (6th ed.1991); Restatement (Second) of Contracts, §§ 24, 52, 29 cmt. a (1981)) (emphasis added). Defendant does not explain any logical connection between its restrictive understanding of an offer under contract law and the use of an offered price, paid to a producer by a purchaser, as an indicator of market price in the calculation of royalty value; defendant simply asserts the existence of such a relationship. Id. (asserting that an offer “sets the basis for royalty”). Defendant’s argument is based on the reasoning in Okie Crude Co. v. Muscogee Area Director, Bureau of Indian Affairs, 23 IBIA 174 (1993).
Plaintiff argues that defendant’s construction of offered price as personal to the offeree, like that advanced by the IBIA in Okie Crude, 23 IBIA at 181, “would render the term ‘actual selling price’ surplusage ... [bjecause no rational seller would refuse the highest offered price.” Pl.’s Br. 10. Defendant’s expert on royalty calculation provided testimony that supports plaintiffs conclusion:
The Court: As a practical matter, Mr. Martin, would it ever be the case that the offered price would be higher than actual price?
Mr. Martin: Practically, no.
The Court: A rational lessee—
Mr. Martin: I can’t imagine a situation in which a lessee would turn down a higher price.
Tr. 1413:14-20 (Martin).
As plaintiff correctly points out in opposition to defendant’s construction, “it does not follow from the law of offer and acceptance that an offer to a third party is unable to serve as a measure of market value.” Pl.’s Br. 10. While an offer under contract law may be personal to the offeree, see Restatement (Second) of Contracts § 52 cmt. a; Def.’s Br. 7; but cf. Restatement (Second) of Contracts § 29 cmt. b (noting that “general offers” may “create separate powers of acceptance in an unlimited number of persons” depending on the interpretation of the offer), in the context of the oil industry, an offered price also represents a price above the posted price that a purchaser is willing to pay to secure its needed oil supply, see Tr. 1297:5-9 (Barker) (explaining that “[ajnytime [purchasers] paid a bonus it would have exceeded the highest posted price”). An offered price represents what a willing buyer is prepared to pay a willing seller for crude oil in the field “on the day of sale or removal.” See 25 C.F.R. § 226.11(a)(2).
*645Once the bonus or premium offered by a major purchaser is paid to a producer (that is, once the offer is accepted), the offered price becomes a “realized” offer or actual selling price which, if higher than the highest posted price by any other major purchaser in the field “on the day of sale or removal,” 25 C.F.R. § 226.11(a)(2), is used to calculate royalty value and determine royalty payments under the Osage Regulations during the Tranche One months. See Tr.l071:5-25 (Hurlburt) (testimony by Osage Agency supervisory petroleum engineer confirming that “the agency’s policy under the 1974 regulations regarding bonuses is that if a bonus were paid by a major purchaser, and [if] that ... posted price plus the bonus were higher than the highest posted price, that that would set the ... royalty value floor for all Osage leases” and acknowledging that the Osage Agency was told to use this interpretation by the agency’s solicitor from the Department of the Interior). Once accepted, the bonus or premium above the posted price becomes a valid indicator of the actual market price for crude oil. Tr. 1297:15-18 (Barker) (explaining that “[i]f [the bonus payment] was on the top 80 percent of the purchases,19 it would have been considered an actual price and the additional royalty would be obtained from all the lessees a[s] a floor price”).
Defendant nevertheless argues that its “interpretation of ‘offered price,’ as applying to those lessees who could have taken advantage of the offer, [i]s contemporaneous with the addition of the term ‘offered price’ to the Osage regulations in 1974[,]” and that, “[a]s such, it should be granted deference.” Def.’s Br. 8 (citing Advanta USA, Inc. v. Chao, 350 F.3d 726, 728 (8th Cir.2003); cf. Linda Newman Construction Co. v. United States, 48 Fed.Cl. 231, 235 (2000) (“Contemporaneous statements construing a contract, made before the dispute arose, are entitled to great weight.”)). Defendant supports its interpretation with the correspondence found in DX2334 concerning additional royalty owed by lessees due to a $0.15 per barrel bonus for stripper oil offered by Sun Oil over its posted price of $14.15, making its offered price of $14.30 the floor price upon which royalty would be calculated for stripper oil sold by all lessees. Id.; DX2334-1. Defendant presents its argument in the following terms:
[I]n 1976, the [Osage] Agency notified purchasers of Osage oil that “Sun Oil Company, along with several other major oil purchasers, offered fifteen cents per barrel over their posting for ‘stripper oil’ making the price being paid for ‘stripper oil,’ $14.30 per barrel based on 40 degree gravity oil.” DX2334-1. These offers were not in writing or broadly circulated, so they were not posted prices but, rather, were “offered prices.” Id. Oil classified as “stripper” is oil from wells producing less than ten barrels per day; thus, any of the “majority” of oil producers on the Osage mineral estate that produced “stripper oil” could have received this offered price, and would have been required to pay royalty based on that available price if it was higher than the actual price they received. RT 1228:1-1230:11. This interpretation of “offered price,” as applying to those lessees who could have taken advantage of the offer, was contemporaneous with the addition of the term “offered price” to the Osage regulations in 1974.
Def.’s Br. 8 (emphasis added). Plaintiff reads the facts presented in defendant’s exhibit DX2334 quite differently. See Pl.’s Br. 3-4 (emphasis added). Plaintiff argues that
[i]n an attempt to project into the past its Okie Crude interpretation of “offered price,” the United States misconstrues a 1976 form letter to purchasers, DX23340001 (cited in Def.’s Br. 8). But DX23340001 does not state, or even hint at, the Okie Crude interpretation of “offered price.” To the contrary, DX2334 contains a number of other letters that show that the Osage Agency rejected that view. One company wrote to the Osage Agency to object to paying royalty based on Sun’s offered price because “such a price is not being generally offered.” DX2334-0014. After speaking with Newell Barker at the *646Osage Agency, however, the company agreed to pay additional royalty nonetheless: “Where we are the lessee of record, we will pay the additional 15 cents because we understand that our lease and government regulations require that we do so.” DX2334-0015.
Plaintiff Osage Nation’s Response to Defendant’s Posh-Trial Brief (PL’s Resp.) 3-4 (emphasis omitted). The court concurs with plaintiffs review of the evidence on the point. Plaintiff went on to note that defense counsel, “after a series of leading or nearly leading questions at trial,” was unable on direct to get its witness to unambiguously endorse defendant’s position that the fifteen cent bonus was generally available to all lessees who produced oil of that quality. Id. at 4 (citing Tr. 1230:1-5 (Barker)). In fact, defendant’s witness underscored both the likelihood that the bonus was not offered to all producers as defendant contends, and that, regardless of who was or was not offered the bonus, Sun Oil’s offered price would set the floor for royalty value and all lessees who had not yet paid on the higher amount would be assessed additional royalty. Tr. 1227:9-16, 1229:5-1230:5 (Barker).
Defendant’s Counsel: Now based on your experience in the industry, as well as the years you were the Chief of the Minerals Branch, remember, we talked about the market value concept a little earlier? Do you believe that a price of $14.30 would be indicative of the market value of stripper oil?
Mr. Barker: Well, I have to say it was, because that’s what was offered.
Defendant’s Counsel: Do you have any reason to believe that any lessee that possessed stripper oil on October 27, 1976 would not get this price for stripper oil?
Mr. Barker: In Osage County, it’s possible that someone may not offer that additional amount.
Defendant’s Counsel: Do you believe that the price reflected in this document was generally offered to anyone that possessed stripper oil at the time?
Mr. Barker: I’d say it should be, yes; and if it wasn’t, we would assess an additional amount.
Tr. 1229:5-17, 1230:1-5 (Barker) (emphasis added).
Mr. Barker’s testimony is fully borne out by the documentary evidence. Contrary to defendant’s argument that Sun Oil’s offered price was generally available to all producers of stripper oil, the letters and notes included in DX2334 confirm that other purchasers were reluctant to match Sun Oil’s bonus. The letter sent by the Superintendent of the Osage Agency, see DX2334-0001, to a list of twenty-one purchasers, see DX2334-0006, is dated October 27, 1976. In the letter, the Superintendent first explains the change in the royalty provisions under 25 C.F.R. § 183.11 to include the “highest posted or offered price by a major purchaser in the Kansas-Oklahoma area” and then announces the Sun Oil bonus and its implications:
Effective September 1,1976, Sun Oil Company, along with several other major oil purchasers, offered fifteen cents per barrel over their posting for “stripper oil” making the price being paid for “stripper oil”, $14.30 per barrel based on 40° gravity oil. Under the regulations, Osage oil lessees are required to pay royalty on oil based on the highest [posted] or offered price as explained above. If your company hasn’t met the highest offered price for stripper oil, the oil lessees from whom you purchase “stripper oil”, are liable for additional royalty due on the difference between the price paid by your company and that paid by the major purchasers, who have offered a higher price for “stripper oil” in the Kansas-Oklahoma area.
DX2334-0001.
It is clear that when it was first made, Sun Oil’s bonus offer was limited to the sales contract cited in DX2334-0013. Other major purchasers, including Phillips Petroleum, Atlantic Richfield, ARCO, Bigheart Pipe Line Co. and Osage Oil & Transportation Inc. were reluctant to meet the bonus amount. DX2334-0008. Over a month after Sun Oil’s fifteen cent bonus offer was known to the Osage Agency, Atlantic Richfield continued to maintain its position that it would not offer *647the bonus to producers from whom it purchased oil. In a letter to the Osage Agency, James E. Woolley acknowledges receipt of the letter from the Osage Agency (DX23340001), but refuses to adopt the Sun Oil bonus, stating, in pertinent part:
Atlantic Ritchfield’s policy is to be competitive with the highest prices being paid for stripper crude and we believe our posted price of $14.15 per barrel for 40° gravity Oklahoma Sweet crude is a competitive price.
We do not dispute your statement that Sun may be paying fifteen cents per barrel above its posted price, however, we do suspect that such price is not being generally offered and, thus, will not be considered as sufficient grounds for increasing our posted price at this time.
DX2334-0014 (Letter from James E. Woolley). Atlantic Richfield did not consider the Sun Oil bonus to be “generally offered” and did not make that offered price available to the lessees from which it purchased stripper oil.
Defendant simply fails to acknowledge the fact, amply supported by the evidence, that the bonus offered initially by Sun Oil to its producers and only later offered by a number of other purchasers, was not available to all producers. See Def. Br. 8 (asserting that “any of the majority of oil producers on the Osage mineral estate that produced stripper oil could have received this offered price, and would have been required to pay royalty based on that available price if it was higher than the actual price they received”) (internal quotations omitted). Defendant concludes its argument for its interpretation of the offered price term by stating that “royalty payments to the Osage Tribe were based on the higher of either (1) the price the lessee actually received for its oil, or (2) the price(s) offered and available to the lessee from major purchasers located in the Kansas-Oklahoma area.” Def.’s Br. 8 (emphasis added). As plaintiff correctly notes, “the United States is compelled to add language to its regulations ... to even state its position.” Pl.’s Resp. 3.
Defendant’s own evidence and the testimony of its witnesses on direct defeat its attempt to distinguish a “generally available” offered price from a “limited availability” offered price as a means of salvaging its restricted interpretation of the offered price term for calculating royalty value. Def.’s Br. 7-8, 12 n. 9. Atlantic Richfield did not accept Sun Oil’s offered price and did not offer a bonus to producers from whom it bought oil. DX2334-0014. In a subsequent clarification, Atlantic Richfield’s Woolsey explained that “[m]y letter of November 4 relates only to those leases where Atlantic Richfield is the purchaser and not the lessee or record. Where we are the lessee of record, we will pay the additional 15 cents because we understand that our lease and government regulations require that we do so.” DX23340015 (emphasis added). Atlantic Richfield clearly refused to offer the bonus or pay the additional royalty on the bonus for producers from whom it purchased oil. It would pay the additional royalty only on the oil it produced in its own right as a lessee, because, it acknowledged, “we understand that our lease and government regulations require that we do so.” Id.
From the testimony presented at trial, trial exhibits, and deposition testimony, it is clear that neither the Osage Agency nor the parties engaged in the buying and selling of Osage oil understood the offered price term in the royalty value formula in the restricted sense advocated by defendant and later adopted by DOI. Defendant would have breached its trust duty properly to interpret the law if it had followed the interpretation of “offered price” now urged by the government.
Perhaps in an attempt to find some coherence between its narrow reading of the offered price term as limiting the payment of royalty only to offered prices available to the lessee, and the other parts of the royalty value formula provided in 25 C.F.R. § 226.11, defendant also advances a new interpretation of the geographic region of reference for setting market prices. See Def.’s Br. 8, 11 & nn. 7-8. According to defendant’s proposed reading of 25 C.F.R. § 226.11 (1974), “[t]he phrase ‘in the Kansas-Oklahoma area’ should be read to modify the term ‘major purchaser,’ and not ‘posted or offered price.’ ” Def.’s Br. 11. Defendant characterizes its new in*648terpretation as a “workable ‘plain language’ interpretation of 25 C.F.R. section 226.11(a),” id., while acknowledging that its new interpretation is in conflict with the position it had advanced earlier in litigating this case when “the United States suggested that the phrase ‘in the Kansas-Oklahoma area’ modified the posted and offered price terms,” Def.’s Br. 11 n. 7. Defendant explains that “[t]he revised and more appropriate interpretation set forth herein resolves the impossibilities inherent in the alternative interpretation of the regulation, and takes into account the plain language and practical application of the terms.” Id. “Such an interpretation,” defendant argues, “avoids the factual and legal ‘impossibility’ problems that arise if the Osage Agency had to seek all offered and actual prices in the Kansas-Oklahoma area.” Def.’s Br. 11.
The court disagrees. Defendant offers no support for an interpretation that is inconsistent with the testimony regarding long-established agency practice by Osage Agency officials who were personally involved in identifying major purchasers and determining highest posted and offered prices in the Kansas-Oklahoma area. See, e.g. Tr.l204:51205:11 (Barker) (confirming that the highest posted price determination was based on prices posted by major purchasers anywhere in the Kansas-Oklahoma area and that this was the agency’s practice during the entire time period covered by Tranche One); Tr. 1024:19-1027:25 (Hurlburt) (explaining the procedure for determining major purchasers and highest posted prices); Tr. 1053:21-25 (Hurlburt); see also DX886 (memorandum detailing the procedure to follow in selecting the highest posted price). The plain meaning of the terms in 25 C.F.R. § 226.11(a)(2) as understood by the BIA and the parties was stated succinctly in the 1976 letter from the Superintendent of the Osage Agency to purchasers informing them of the new royalty value formula and its implications for the calculation of royalty due the Osage Tribe for stripper oil sales. The letter, written two years after the addition of the offered price term and the revised major purchaser definition to the regulation, stated, in pertinent part, that “[i]f your company hasn’t met the highest offered price for stripper oil, the oil lessees from whom you purchase ‘stripper oil,’ are liable for additional royalty due on the difference between the price paid by your company and that paid by the major purchasers, who have offered a higher price for ‘stripper oil’ in the Kansas-Oklahoma area. ” DX2334-0001 (emphasis added). Defendant’s self-styled “revised and more appropriate interpretation” of the major purchaser term in the royalty value formula, Def.’s Br. 11 n. 7, raises the question of why the BIA would choose to require a monthly major purchaser analysis based on all purchases in the Kansas-Oklahoma area if only posted and offered prices available to each lessee in Osage County could be used for setting royalty value. Defendant provides this answer: “By looking to major purchasers in the broader area, the regulations ensured that prices on which royalties were to be based were those from purchasers with the resources to acquire the oil available from the Osage County lessees at the offered or posted prices.” Def.’s Br. 11 n. 8. As presented in defendant’s exhibit DX2334, major purchasers in Osage County included Texaco, Atlantic Richfield, Sun Oil Company, Phillips Petroleum, Koch Oil, Kerr-McKee, Gulf Oil, and Bigheart Pipe Line Corporation. Osage County was one of the largest oil producing counties in the United States. Tr. 84:13-21 (Reineke). Defendant provides no support of any kind for its explanation, nor does it provide any evidence that the Osage Agency ever used or contemplated the use of the data generated by the major purchaser analysis to disqualify purchasers from buying oil in Osage County or to bar them from submitting posted price bulletins for the use of Osage producers.
Defendant suggests that the elaborate monthly major purchaser analysis undertaken by the Osage Agency was done somehow to protect Osage lessees or perhaps the Osage Tribe as lessor from unscrupulous purchasers who would post prices beyond what they could afford to pay. Def.’s Br. 11 n. 8. The court does not accept defendant’s contrived “credit check” theory of the Osage Agency’s monthly analysis of regional crude oil purchases and posted price data. An agency can depart from established practices and a previous interpretation of regulatory *649language if it explains adequately why it is doing so. See British Steel PLC v. United States, 127 F.3d 1471, 1475 (Fed.Cir.1997). Here, however, the court is presented not with a change in interpretation of an agency’s regulations made by the agency itself in the course of executing its mandate, but with a wholly novel re-interpretation of the regulations that was never formally adopted by the agency or made part of its practice while the regulations in question were in effect. The court follows the interpretation of the regulations that is consistent with their plain meaning.
As to “offered price,” the 1974 Regulations mean what they say. Plaintiff is entitled to royalties for the Tranche One leases in the Tranche One months based on the higher of “the actual selling price, or the highest posted or offered price by a major purchaser in the Kansas-Oklahoma area ... on the day of sale or removal.” 1974 Regulations (emphasis added).
2. Application of Gravity Adjustments
The parties agree about the history of the term “posted price,” see Stip. of Fact ¶ 5, but disagree as to whether the Osage Regulations allow downward adjustment of posted prices based on the gravity of oil or other quality considerations in the calculation of royalty. Compare Pl.’s Br. 26 (“Nothing in the language of the Osage Regulations requires that Royalty Value be adjusted based on the gravity of the oil.”) with Def.’s Br. 13 (“By its very nature, a posted price bulletin is an instrument that communicates to producers in a given field the pricing information that an oil company will pay for particular grades of crude oil.”). The gravity of crude oil is a measurement of its specific gravity expressed in degrees on a scale developed by the American Petroleum Institute (API). PX751-0011; Williams & Meyers 53 (“On the API scale, oil with the least specific gravity has the highest API gravity. Other things being equal, the higher the API gravity, the greater the value of the oil.”).
Plaintiff argues that the Osage Regulations, which do not expressly use language to tie royalty value to the quality of the oil being sold from the leases, are unique as compared to other “royalty schemes” that include provisions linking royalty value to “oil of like quality.” Pl.’s Br. 27 (citing Tr. 103:17-25 (Reineke)). Plaintiff contends that “[t]he absence of limiting language such as ‘oil of like quality’ in the Osage Regulations indicates that Royalty Value is not a function of quality but rather [of] the prices being paid, offered, and posted for all the different types and qualities of oil being produced in Kansas and Oklahoma.” Pl.’s Br. 27. Plaintiff concludes from this that “[ijndustry practice is not relevant here given the uniqueness of the Osage regulations.” Id.
Plaintiffs argument appears to the court inconsistent with the stipulations of fact agreed to by the parties. Stip. of Fact ¶ 5 (“ ‘Posted prices’ are so named because in former times a prospective purchaser (usually a refiner) would tack a sheet to a post in a producing field stating how much it might be willing to pay for a crude oil or blend of oils of standardized quality (e.g., Oklahoma Sweet, West Texas Intermediate, Louisiana Light).”). The stipulation of fact attests to a long-established practice in the industry of offering different prices according to the quality of the crude oil produced. Id. Plaintiff does not contest the fact that gravity adjustments are a standard practice used by purchasers to set market value for different quality of oil, Tr. 221:11-19, 223:11-224:4 (Reineke), but instead argues that the common understanding of posted price as including price adjustments for gravity may be followed in setting the payment owed the producer for its oil, but should be ignored when calculating the royalty owed the Tribe for that same oil. See Pl.’s Br. 27.
Plaintiffs construction of the posted price term in the regulation is at odds with both the historic practice of the industry and with the long-standing construction of the regulations by the Bureau of Indian Affairs, whereby royalty was based on the higher of the “actual market value” of the oil or a floor price based on a guaranteed minimum, see 1912 Regulations ¶ 20(a), or posted price, see 1915 Regulations Form B ¶ 2, or the higher of either the posted or offered price, see 1974 Regulations 25 C.F.R. § 183.11(a)(2), made by a qualified purchaser. The language em*650ployed in the regulations should be “construe[d] in its natural and obvious sense.” United States v. Shreveport Grain & Elevator Co., 287 U.S. 77, 84, 53 S.Ct. 42, 77 L.Ed. 175 (1932) (citation omitted). The laws of construction applied to statutes are applicable here as well. See also 1A Norman J. Singer, [Sutherland] Statutes and Statutory Construction 722-23, § 31:6 (6th ed. 2002) (“It is obvious, that inasmuch as a regulation is a written instrument the general rules of interpretation apply.”). It is precisely in circumstances such as found here, where long-continued practices specific to a highly specialized trade or industry are at issue, that widely shared and understood industry usage is most readily incorporated into the terms of an agreement. Robinson v. United States, 13 Wall. 363, 80 U.S. 363, 366, 20 L.Ed. 653 (1871) (“Parties who contract on a subject-matter concerning which known usages prevail, by implication incorporate them into their agreements, if nothing is said to the contrary.”). Plaintiffs argument turns this basic principle on its head: because the ordinary practice of adjusting posted prices according to the gravity of the oil was not expressly stated, it should not be followed. Plaintiff produces no authority for its argument and cites only to the trial testimony of its expert on royalty calculation for support. PL’s Br. 27 (citing Tr. 99:10-100:13 (Reineke)).
Defendant’s evidence demonstrates that the posted price bulletin prepared by purchasers during the Tranche One period typically included tables showing the price adjustment by gradation of gravity of the oil. Tr. 1391:21-1392:24 (Martin) (explaining that “[a]ll of the ... [posted] price bulletins ... as well as the Platt’s publication that has the prices in it give a gravity scale that goes along with that reference posted price of 40 degrees API”); Tr. 1201:6-1202:12 (Barker) (explaining the 40-degree API benchmark for crude oil and the lower market value of lower gravity oil); Tr. 1312:1-5 (Barker) (“The regulations say that you have to get your income based on the highest posted price. And not only that, but that’s general throughout the industry. I mean, this has been going on [for] years, and the price of the oil was always valued on the gravity.”); DX2360 (posted price bulletin prepared by Osage Agency informing purchasers and lessees of highest posted price by major purchasers by time period, with attached gravity scale showing highest posted price at different levels of gravity). Even plaintiffs expert concedes that adjusting posted prices according to the gravity of the oil purchased is a standard industry practice recognized and facilitated by the American Petroleum Institute through the establishment of a standard for gravity measurement. Tr. 220:22-221:22 (Reineke) (“A gravity adjustment is on price bulletins that a purchaser publishes and says that if the gravity is, for instance, less than 35 degrees, they will deduct 10 cents per tenth of a degree or 10 cents per degree or something.... The American Petroleum Institute devised a gravity scale and ... the median or the good stuff is at 40 degrees____”).
The court agrees with defendant’s conclusion that “the [Osage] Agency, in construing ‘posted price’ in the regulations, properly allowed price adjustments to reflect degrees of gravity.” Def.’s Br. 13. Plaintiff has not demonstrated that the Osage Agency’s construction was not in accordance with the regulations. Defendant did not breach its trust duty to collect royalties under the leases by allowing price adjustments to reflect degrees of gravity.
3. Simultaneous Sales from Same Lease
Plaintiff also claims that the United States failed to collect royalty from lessees based on the highest selling price from a lease when there were simultaneous sales from the same lease that yielded different prices for the oil. Pl.’s Br. 20. The royalty value formula included a special provision for calculating royalty on “simultaneous sales” of oil from the same lease:
[Settlement shall be based on the actual selling price, or the highest posted or offered price by a major purchaser in the Kansas-Oklahoma area whichever is higher on the day of sale or removal. Where different prices are paid simultaneously for oil from a lease and the highest such price exceeds the higher of the aforementioned prices, then that price shall be the basis of royalty on all oil from said lease.
*65125 C.F.R. § 226.11(a)(2) (emphasis added). Plaintiffs expert testified that he had found evidence of simultaneous sales on two leases for two Tranche One months. Tr. 237:1-9 (Reineke); see PX751-0029 to 30. The analysis of the simultaneous sales issue is presented in the section headed “Failure to Apply Unregulated Prices” in its expert report on royalty calculation. PX751-028. The prices reported by plaintiff appear to differ most significantly between the relatively low prices for sales from non-waterflood portions of a lease and the substantially higher prices from the waterflood portion of a lease. Pl.’s Br. 21. The term “waterflood” refers to a “method of recovering additional quantities of oil by injecting water underground for the purpose of ‘washing’ the oil out of the reservoir rock and into the bore of a producing well.” Stip. of Fact ¶ 6. The use of water injection wells is a common recovery practice associated with stripper wells. See, e.g., DOE Stripper Well Litigation, 690 F.2d at 1382 (noting that the Federal Energy Administration (FEA) interpreted the stripper well regulations to exclude water injection wells from the well count in calculating “average daily production” per well). This supports defendant’s contention that “[sjimultaneous sales on the same lease at different prices occurred only during the price-control era.” Def.’s Resp. 7 n. 14.
Plaintiffs evidence of its liability claim regarding royalty collections from simultaneous sales of oil from the same lease appears to the court to depend on the use of unregulated prices for oil in setting royalty value for oil sales subject to regulation. The court agrees that plaintiff is entitled to have royalties calculated on unregulated prices. See infra Part III. However, plaintiff has failed to demonstrate that defendant breached its trust obligations to plaintiff by failing to collect royalties on simultaneous sales in violation of law except with respect to violations related to price controls.
C. Whether the Osage Agency Verification Procedures Were Reasonably Calculated to Result in Compliance With the Regulations
Royalty value during the Tranche One months was defined in the regulations as “the actual selling price, or the highest posted or offered price by a major purchaser in the Kansas-Oklahoma area whichever is higher on the day of sale or removal.” 25 C.F.R. § 226.11(a)(2). A “major purchaser” under the 1974 Regulations was defined as “any one of the minimum number of purchasers taking 80 percent of the oil in the Kansas-Oklahoma area.” 25 C.F.R. § 226.1(h). There is little disagreement between the parties regarding the meaning of the term “actual selling price,” although there is disagreement regarding whether the sale price reported by the lessee or purchaser faithfully reflected the full value given in exchange for the oil sold. Def.’s Br. 5 (“An actual selling price is the price received by the lessee for the sale of its oil to a producer.”); Tr. 1220:25-1221:3, 1402:22-23 (Barker); Pl.’s Br. 22 (noting that the “actual selling price” must reflect “the full consideration for the oil,” including any payments from “side arrangements” to producers that would be in addition to the reported sale price); Tr. 139:12-20 (Reineke) (distinguishing actual sales price from the reported sales price and claiming that “there was no information to verify that the reported sales price was the entire consideration that was given for the sale”).
1. Verification of Actual Price Paid and the Use of Sales Contracts
Plaintiff claims that the United States failed to collect the full value of royalties due the Osage Tribe because it failed to determine the “actual selling price” provided to lessees by purchasers. Pl.’s Br. 22. Plaintiff argues that “the actual selling price can be determined only by examining the underlying sales contract ... because buyers and sellers often agree to enter side arrangements or to characterize portions of the sales price as something other than consideration for the oil itself.” Id. (citations omitted). Plaintiff divides its argument into three points. Pl.’s Br. 22. First, plaintiff asserts that “the lessee’s report and the purchaser’s statement may not tell the full story,” id., because “parties [may] have agreed to pay *652some portion of the consideration by ‘separate check,’ ” id. (citation omitted). Second, plaintiff states that “the ‘opposing economic interests’ may be absent if the transaction is between corporate affiliates.” Id. Third, plaintiff claims that “even where the lessee and the purchaser are unrelated, they can mutually benefit by structuring the transaction to depress royalty and severance tax liability and to share in the savings.” Id. at 23 (citation omitted).
While the possibility of collusion between seller and purchaser certainly exists at a theoretical level, the evidence presented at trial does not support plaintiffs argument. Plaintiff did not offer any evidence that would have suggested payment by a “separate check.” Nor did plaintiff offer any evidence regarding clandestine agreements between the lessees and purchasers.
Neither the lease forms nor the regulations restrict purchasers in the manner in which they make payment to the lessee. The regulations do, however, impose heavy sanctions should either party fail to make the proper royalty payment to the Osage Agency. See 25 C.F.R. §§ 226.13, 226.42. The regulations provide that “[rjoyalty payments due may be paid by either purchaser or Lessee----Failure to make such payments shall subject Lessee or purchaser, whoever is responsible for royalty payment, to a late charge at the rate of not less than 1 1/2 percent for each month or fraction thereof until paid.” 25 C.F.R. § 226.13(a). In addition to the late charge, failure to remit the royalty payment would “subject the division order to cancellation,” 25 C.F.R. § 226.13(c), and “subject the lease to cancellation by the Superintendent, or Lessee to a fine of not more than $500 per day for each day of such violation or noncompliance,” 25 C.F.R. § 226.42.
Because royalty payments were usually made each month by the purchasers on behalf of lessees, Def.’s Br. 28; Tr. 1225:23-1226:4, the purchaser would court the greater risk from knowingly underreporting the actual selling price paid for the oil and upon which royalty was due, while the benefit from such a scheme would redound to the lessee as the party from whom royalty is due. See 25 C.F.R. § 226.14 (providing that while lessees may enter into division orders and contracts that authorize purchasers to make royalty payments, the division orders or contracts “[do] not reheve Lessee from responsibility for the payment of the royalty should the purchaser fail to pay”).
The court cannot find injury to the Osage Tribe based on plaintiffs allegation of loss of royalties due to the unproven possibility of collusion in reporting the full value of payments made for crude oil. Plaintiff failed to present evidence of such alleged wrongdoing. The verification procedures and incentives for compliance appear to the court to have been reasonably calculated to result in compliance with the 1974 Regulations as to the “actual price paid.”
2. Procedures for Determining Major Purchasers
Plaintiffs expert challenged the major purchaser analysis conducted by the Osage Agency for February 1986 and July 1989, alleging that data from the wrong months were used in the February 1986 calculations, Tr. 154:7-24 (Reineke) (noting that December 1985 data were used in determination of February 1986 major purchasers); PX7510018 ¶ 56, and that the volume of oil sales upon which the Osage Agency major purchaser determinations were made did not reflect the actual volume of oil purchased as shown by other data sources, Tr. 156:15-19, 157:20-158:1 (Reineke); PX751-0018 to 0019 ¶¶ 57-58. Similar data were presented for July 1980. Tr. 162:1-24 (Reineke); PX7510020 to 21 ¶¶ 61-63. Defendant’s expert on royalty calculation explained that the Osage Agency obtained Oklahoma and Kansas Corporation Commission data “for the most contemporaneous date that they had the data available” to do the major purchaser calculations. Tr. 1436:17-25 (Martin). Defendant’s expert also testified that oil purchasers were required to report production volumes to state agencies by the end of the month following production, Tr. 1437:20-23 (Martin) (stating as an example that February sales data would be submitted by the end of March), and that the state agencies then combined the data from various sources to *653generate oil production reports, resulting in a delay of two to three months, Tr. 1438:10-24 (Martin). Defendant’s expert concluded:
So that is why ..., for example, a report for February ... 1986, which is one of the Tr[a]nche One months, ... might have volumes from the Corporation Commission that are two or three months old. In fact, what we see in the files is that they [the Osage Agency] were using December of 1985 data, and they still didn’t have all the data in there. Some columns still appear to be estimated because the Corporation Commission had not even received all of it by then.
Tr. 1438:24-1439:8 (Martin).
Plaintiff argued that the “missing volume” of oil, that is, the difference between the volume reported by the Osage Agency in the major purchaser analysis conducted at the time and the volume figures produced by plaintiff using data later or now available, was evidence that the Osage Agency’s major purchaser analysis was flawed, and that it was therefore impossible to determine all of the purchasers who were major purchasers. Tr. 160:4-9 (Reineke); PX751-0022 ¶ 66-68. If a given percentage of the “missing volume” of oil were attributed to a purchaser not on the Osage Agency’s list of major purchasers for the month, plaintiff alleged, it would change the composition of the major purchaser list. Tr. 159:24-160:3 (Reineke) (noting, by way of example, that if 25% of the missing volume were attributed to Amoco, the company would move from twenty-fourth in the list to ninth in terms of volume of sales). The import of plaintiffs analysis, at least impliedly, is that the highest posted and offered prices used to calculate royalty value by the Osage Agency may have been inaccurate, resulting in lower royalties than would otherwise have been obtained. See Pl.’s Br. 26.
Defendant argued that the data used in plaintiffs calculations were not contemporaneously available to the Osage Agency. Def.’s Resp. 8. Further, defendant underscored the point that the actual distribution of any “missing volume” of oil sales was unknown and that plaintiffs assignment of 25% of the missing volume to one purchaser could as easily have been 1% or any other figure. Tr. 266:7-267:7 (Reineke) (acknowledging on cross-examination that the assignment of missing volume to Amoco could as easily have been 1% or none of the missing volume). The United States provided credible and persuasive testimony that the procedures adopted to perform the major purchaser analysis were appropriate to the task and applied systematically, using the best available data at the time. See Tr. 1009:8-1020:18 (Hurlburt) (explanation of procedure for collection of major purchaser data, creation of spreadsheets, and entry into computer database during period of 1983-1989); Tr. 1199:14-1200:24 (Barker) (testifying that the Osage Agency performed a monthly major purchaser determination during the Tranche One years, using data provided by the Oklahoma and Kansas Corporation Commissions); Tr. 1436:17-1439:8 (Martin).
The court agrees with defendant that plaintiffs conclusions regarding the effect of allegedly missing data on the major purchaser analysis is speculative. The evidence and testimony presented by plaintiff is insufficient to demonstrate that the procedures used by the Osage Agency to determine the identity of major purchasers were not reasonably calculated to comply with the 1974 Regulations.
3. Procedures for Determining Highest Offered Prices of Major Purchasers
The testimony made clear that reliable data on the highest offered price from major purchasers in the Kansas-Oklahoma area outside of Osage County were difficult to acquire for the reasons identified by the United States, see Def.’s Br. 9, and confirmed by Osage Agency staff, Tr. 1221:2-17 (Barker). The Osage Agency could determine that a major purchaser had paid a bonus above its posted price only when the Osage Agency learned of the bonus from a purchaser or producer or similar source, or by comparing the actual selling price data provided by purchasers and lessees with the highest posted price for the period in question. By cheeking reported actual selling prices against posted prices, the Osage Agency was able to determine when a bonus had been paid to a *654producer in Osage County. Tr. 1223:22-1224:1 (Barker). If the bonus had been paid by a buyer qualified as a major purchaser under 25 C.F.R. § 226.1(h), the bonus reflected in that major purchaser’s offered price became the floor for determining all royalties owed the Tribe. Tr. 1055:16-1056:3 (Hurlburt) (explaining that an actual selling price paid by a purchaser who was not a major purchaser would not be considered a bonus and would not affect the calculation of royalty value for all lessees).
The method used by the Osage Agency to identify relevant bonus prices from actual selling price data provided by Osage County lessees and purchasers, however, could not be used to detect bonuses offered and paid to producers outside Osage County. Tr. 1224:2-25 (Barker) (explaining that purchasers would consider bonus offers made to producers outside the Osage Reservation as privileged information). Plaintiff argues that the Osage Agency was required under the regulations to collect offered prices throughout the Kansas-Oklahoma area, Tr. 254:12-17, and could have used actual prices paid for oil by major purchasers as a proxy, Tr. 253:11-19. The court agrees that the Osage Agency was required under its regulations to determine royalties based on “the highest posted or offered price by a major purchaser in the Kansas-Oklahoma area.” 25 C.F.R. § 183.11(a)(2). In this respect, defendant failed to employ procedures reasonably calculated to result in compliance with the 1974 Regulations.
Defendant argues that the Osage Agency lacked the authority to require purchasers to provide actual sales or offered price data for sales outside Osage County. Def.’s Br. 9; Tr. 254:24-255:5 (Defendant’s Counsel) (asking on what authority the Osage Agency could collect such price data). Plaintiffs expert acknowledged that purchasers may not be willing to provide such data, Tr. 108:5-8 (Reineke), and proposed other possible sources, such as data from the Mineral Management Service (MMS) and the Oklahoma Tax Commission, Tr. 108:24-109:16 (Reineke). While proxies advanced by plaintiff that depended on collection of data from tax commissions and other government sources in Oklahoma and Kansas would have imposed substantial delay in determining the royalty owed by lessees, Tr. 1411:3-16 (Martin) (observing that there is typically a three month delay to obtain Oklahoma Tax Commission data), and while state tax commissions reported prices on a monthly basis whereas the Osage Agency required daily price data for setting royalty value, Tr. 1222:1-9 (Barker), government records appear to the court to be a satisfactory proxy at this juncture.20 Plaintiff is entitled to have its royalties calculated, as nearly as may now reasonably be determined, in accordance with the requirements of the 1974 Regulations that bonus prices offered by major purchasers throughout the Kansas-Oklahoma area be used in determining royalty value.
4. Osage Agency Staffing, Verification Procedures, and Audit Procedures
Plaintiff alleges that the Osage Agency failed to employ sufficient staff to conduct physical inspections of oil tanks to detect leaks, to verify the volume of oil sold as reported in lessee and purchaser reports, and to check the accuracy of gauging reports provided by purchasers that include measurements of physical indicators. Pl.’s Br. 28-29. Physical indicators include temperature, BS & W (basic sediments and water), and storage tank levels that are used in determining volume of oil. Tr. 696:11-699:24 (Big Horse). Plaintiff also claims that the United States failed to verify whether the correct royalty rate was paid on oil produced from specific formations on which higher royalty rates applied. Pl.’s Br. 29. Finally, plaintiff argues that the United States failed to conduct routine audits on lessees and pur*655chasers of Osage oil. Id. at 30-31. Plaintiff concludes that, “by relying only on information that the parties chose to report, and by failing to subject that information to any independent verification or confirmation, the United States breached its duty to verify that full royalties were paid based on the correct Royalty Value, Royalty Volume, and Royalty Rate.” Id. at 33.
Regarding plaintiffs claim that the Osage Agency failed to employ sufficient staff to verify the volume of oil and to check its accuracy, the court finds plaintiffs arguments unpersuasive. During trial, plaintiff did not present any evidence of harm suffered from defendant’s staffing. Plaintiff could not point towards any evidence of leaks or other, similar problems to demonstrate that defendant’s staff was insufficient.21
Plaintiff asserts that defendant failed to verify the royalty rates paid on the oil produced. Plaintiff argues that “[tjhere was no indication that the [Osage] Agency had any process to verify the pool, sand, or formation from which the oil was produced, or to verify monthly production rates,” which plaintiff believes led to a failure in “ensuring] collection of all moneys due the Osage Nation” and a breach by the United States of its trust duties. Pl.’s Br. 30. Plaintiff presented this *656argument at trial through the testimony of Jim Parris, who testified that, while he was tribal auditor for the Osage Tribe, he had been notified by an Osage Agency employee, Mary Lou Drywater, of a possible royalty rate violation. Tr. 321:19-322:17 (Parris). The lease in question involved a waterflood lease amendment that provided a royalty rate reduction from 16 2/3% to 12 1/2% for the first 100,000 barrels of production as a means of compensating the lessee for investment costs in enhanced recovery technology. Tr. 320:8-321:13 (Parris); Stip. of Fact ¶ 6 (describing waterflooding as an enhanced oil recovery method). On investigation, Parris determined that the lessee had not increased the royalty rate applied to his oil sales after reaching the 100,000 barrel threshold. Tr. 321:3-13. The matter was reported to the Chief of the Osage Tribe and, through the Chief, to the Osage Agency, who “put in a claim against the company.” Tr. 321:10-13 (Parris).
The court does not find Mr. Parris’ testimony probative of a pattern or practice of disregarding the verification of royalty rates. Mr. Parris himself acknowledged on cross-examination that he had then reviewed other waterflood leases and found no other instances where companies had failed to pay the higher rate after attaining the volume threshold. Tr. 395:2-11 (Parris). Additionally, defendant presented testimony that the Osage Agency staff followed a procedure for verifying royalty rate requirements for each lease. See Tr. 863:16-864:20, 953:13-954:13 (Branstetter). That procedure comprised completing a form that designated the identities of the purchasers, the amount purchased, and “post[ed] royalty barrels and ... amounts to the contracts for the different leases.” Tr. 861:14-19 (Branstetter). These forms were then verified with the oil lessee via a report that the lessee sent to the Osage Agency. Tr. 862:7-11 (Branstetter). Ms. Branstetter, a former accountant technician, testified that the royalty rates applied to the leases in the Osage mineral state comprised either one-sixth or one-eighth, depending on the underlying contract. Tr. 861:5, 863:20-24 (Branstetter). Those underlying contracts listed the “number of the lease, the description of where it was located[,] ... what amount of royalty was paid, whether it was a sixth or an eighth.” Tr. 864:7-11 (Branstetter). Osage Agency staff had access to the lease contracts in case of a need to verify the royalty rate. Tr. 864:16-20. Mr. Hurlburt, a supervisory petroleum engineer at the Osage Agency, testified that all volume thresholds related to royalty rate reductions had been met before the Tranche One period. Tr. 985:8-14 (Hurlburt). The court agrees with defendant that plaintiff has failed to meet its burden of proving that the United States did not apply the proper rates to royalty production. See Def.’s Resp. 9.
In support of its claim that the United States failed to conduct routine audits on lessees and purchasers, plaintiff presented testimony by a witness responsible for managing a private trust created in or about 1998 that includes oil and gas wells on approximately 51,000 acres in two Texas counties. Tr. 2319:12-2321:14, 2323:6 (Morrison). The witness, Lucian Morrison, testified to practices implemented on the private trust to verify the accuracy of oil production, royalty value, and royalty payments, Tr. 2329:6-2332:24, from 178 producing wells, Tr. 2327:16, that pump oil into over 100 tanks, Tr. 2349:6-7. According to Mr. Morrison’s testimony, the private trust hired engineers to review the trust database of well-specific data, producer reports and Texas Railroad Commission data as a means of verifying royalty volume and accuracy of payment. Tr. 2329:6-2331:8. Mr. Morrison referred to these assessments conducted by the engineers as “audits.” Tr. 2335:19-22.
The court assumes that plaintiff presented Mr. Morrison’s testimony in order that the court may draw an analogy to the current case and find the Osage Agency procedures wanting in comparison. However, the court declines to draw such a connection. A substantial difference exists in the scale of operations between the Osage Reservation mineral estate, which covers roughly 1.47 million acres, Stip. of Facts ¶ 2, and had about 10,-000 active wells in 1979,22 and that described *657by Mr. Morrison. The circumstances of oil leasing and the reporting requirements on the parties to oil sales and purchases are also dissimilar. The private trust has a single lessee, Tr. 2347:6-8 (Morrison), compared to the roughly 2,000 leases on the Osage Reservation, Def.’s Resp. 9 n. 18, and receives oil sales reports only from producers, Tr. 2346:19-24, not from both lessees and purchasers as is the case on the Osage Reservation, see Tr. 879:24-880-8 (Branstetter). The private trust produced “about 5,000 barrels [of oil] a month,” Tr. 2321:6-7 (Morrison), while the Osage Agency received “almost 1,000 purchasers!’] statements ... in a month,” Pl.’s Br. 29. Unlike the Osage Agency, the private trust does not inform producers of posted prices and gravity adjustments prior to payment, Tr. 2346:14-18 (Morrison), and verifies the volume of oil reported as sold by producers with Texas Railroad Commission data that the witness acknowledged “certainly [are] not contemporaneous” and are available with a delay of “several months” following the sale of the oil, Tr. 2347:25-2348:5 (Morrison).
Even if the court were to accept plaintiffs evidence as analogous to the present ease, the court still would not agree that Mr. Morrison’s testimony supports the conclusion that the Osage Agency failed in its trust duties because the court does not find the “audit” procedure described by Mr. Morrison to be qualitatively dissimilar to the Osage Agency’s extensive system of internal safeguards. Four components comprised Mr. Morrison’s audit procedure: 1) tracking the monthly production of oil wells in a database; 2) checking the volumes reported to a state oil management authority against the volumes reported on the check stubs; 3) hiring engineers to review the previous two items; and 4) hiring contract pumpers to measure the amount of oil in the tanks. Tr. 2329:6-2332:24 (Morrison). Contrary to plaintiff’s assertions, the Osage Agency implemented a similarly thorough system of verification. According to Ms. Branstetter, the Osage Agency regularly received pricing reports that listed the highest posted price, which all of the oil companies were required by the Osage Regulations to pay to the Osage Agency. Tr. 862:12-868:20 (Branstetter). When the purchasing oil companies submitted their checks to the Osage Agency, they simultaneously sent a document summarizing the location of the lease, the number of the barrels sold, the gross value, and other pertinent information. Tr. 872:5-874:22 (Branstetter). The Osage Agency then verified those statements by comparing them to the lessee reports, which informed the Osage Agency whether a particular lease produced oil that month and in what quantity. Tr. 880:1-21 (Branstetter). At the end of each month, the Osage Agency prepared a production report, Tr. 892:14-20, which listed “all the activity of oil that was produced and the royalty amounts that were paid by all the oil companies for that particular month.” Tr. 893:1-3 (Branstetter). The Osage Agency relied on schedules to track monthly royalty payments. Tr. 894:25-895:24 (Branstetter).
The Osage Agency employed other safeguards to ensure that the royalty values were accurate. As described by Mr. Barker, the agency engaged in “spot gauging,” a practice by which an oil gauger would gauge the tank and measure the oil levels before and after a party purchased the oil in order to ensure that “the Tribe was being paid correctly for the amount of oil that was removed.” Tr. 1118:18-19 (Barker). Another means of ensuring proper royalty payments was conducted via run tickets: Osage Agency personnel would compare the lessees’ tickets with those belonging to the purchasers. Tr. 1138:14-16 (Barker). The Osage Agency also relied on “locking and sealing devices” in order to prevent theft, see Tr. 1125:25-1133:19 (Barker), and made “periodic spot checks on the gauging of oil sold from the lease[s].” Tr. 1180:3-5 (Barker). Additionally, the Osage Agency implemented regulations governing the registration of tank trucking operators and their trucks, which included gaugers’ routinely surveying and spot checking tanks. Tr. 1182:2-24; see also Tr. 995:1-1009:7 (Hurlburt) (describing monitoring and in*658spection practices). In particular, the monitoring and inspection practices described by Mr. Hurlburt do not compare unfavorably with the audit procedure described by Mr. Morrison.
Based on all of the credible evidence, the court finds that defendant’s staffing, and its verification, audit and related procedures— except as otherwise specifically indicated in this Opinion — were reasonably calculated to result in compliance with the 1974 Regulations.
D. Collection of Late Payment Penalties
Plaintiff argues that, because “[t]he uncollected royalties for Tranche One leases are still due and owing ..., the United States continues in breach for failing to collect the late fees that are due on those unpaid royalties.” PL’s Br. 48. Under the Osage Regulations, royalty payments are due on the twenty-fifth day of each month following the month of production, and failure to make royalty payments “shall subject Lessee or purchaser, whoever is responsible for royalty payment, to a late charge at the rate of not less than 11/2 percent for each month or fraction thereof until paid.” 25 C.F.R. § 226.13(a). The Osage Regulations also provide for penalties for violation of lease terms and regulations, with cancellation of the lease or “a fine of not more than $500 per day for each day of such violation or noncompliance ... or to both such fine and cancellation.” 25 C.F.R. § 226.42. Under the latter regulation, the lessee is to receive a 30-day notice of the lease terms or regulations violated and has the right to a hearing upon request. § 226.42. Neither regulation expressly requires the imposition of a penalty for partial payment in eases where some or most of the royalty owed is paid. While there was no direct testimony on this specific point, Osage Agency personnel did report instances where additional royalty was demanded of lessees due to the determination of a royalty value higher than the actual selling price or highest posted price. See DX2334-0001 (letter to purchasers informing them of additional royalty owed due to Sun Oil bonus); Tr. 1054:17-23 (Hurlburt); Tr. 1297:5-18 (Barker).
Plaintiff seeks damages for late payment penalties on eight royalty payments received by the Osage Agency. See PX750-0044; Tr. 547:7-13(Jay). Plaintiffs expert, Stephen Jay, acknowledged that the late fee penalties presented in his expert report, PX750-0044, represent “the present value of the amount of late fees that I don’t know have been collected in regard to payments received by the Osage Nation on oil and gas remittances for Tranche [One] months.” Tr. 547:9-13(Jay) (emphasis added). On cross-examination, Mr. Jay further acknowledged that he did not know if any attempts had been made to collect late payment fees or if the fees in question were ever collected. Tr. 601:22-602:2. Defendant challenges plaintiffs conclusion that late penalties were owed on the receipts in question and observes that “even if some of the royalty payments ... were late, Plaintiff failed to present any evidence at trial that penalties were not imposed on or collected from lessees for these alleged late payments.” Def.’s Resp. 18.
In support of its theory of liability, plaintiff cites Liss v. Smith, 991 F.Supp. 278, 291 (S.D.N.Y.1998). The facts and circumstances in that ease are inapposite to the situation here. The defendants in that case, fund administrators and trustees, knowingly waived interest on delinquent contributions to a union health plan and pension plan and failed to take measures to collect known delinquent contributions. Liss, 991 F.Supp. at 290-91. The court in Liss found that “the record is clear that the trustees ... regularly waived interest and failed to collect overdue principal.” Id. at 291. No such evidence was presented here by plaintiff. The court believes that a conclusion that late fees were not collected would be speculative based on evidence before it and, therefore, declines to find a breach by defendant of its duty to collect late fees.
III. Royalty Value Under Price Controls
During the first three Tranche One months (January 1976, May 1979, and November 1980), prices for crude oil were subject to price and allocation controls promulgated initially by the Cost of Living Council (CLC), acting pursuant to the Economic Sta*659bilization Act of 1970, Pub.L. No. 91-379, 84 Stat. 796, and later under the Emergency Petroleum Allocation Act (EPAA) and subsequent amendments, Pub.L. No. 93-159, 87 Stat. 627 (1973) (codified at 15 U.S.C. §§ 751-760(h)), repealed by Pub.L. No. 94— 163, tit. IV § 461 (Dec. 22,1975); see supra Part I.C. Section 2(b) of the EPAA states that “[t]he purpose of this act is to grant to the President of the United States and to direct him to exercise specific temporary authority to deal with shortages of crude oil, residual fuel oil, and refined petroleum products or dislocations in their national distribution system.” EPAA § 2(b), 15 U.S.C. § 751(b). The authority to implement the EPAA was delegated by the President in accordance with § 4(e)(2)(C) of the EPAA, to the Federal Energy Office, later the Federal Energy Administration (FEA), which in turn became the Department of Energy. See Air Transp. Ass’n, 382 F.Supp. at 440.
Mandatory petroleum allocation regulations governing crude oil that became effective December 27, 1973, 10 C.F.R. Part 211 (1975), “provide[d] for the mandatory allocation of all crude oil produced in or imported into the United States,” id. at § 211.61, and applied to “all producers, refiners, and others who purchase crude oil from producers directly or indirectly for resale or transfer to refineries,” id. Mandatory petroleum price regulations (MPPR) were also promulgated, 10 C.F.R. Part 212 (1975), and applied to “each sale, lease or purchase of a covered product in the United States,” 10 C.F.R. § 212.2, including “each sale of crude oil made pursuant to the provisions of [the mandatory crude allocation program],” 10 C.F.R. § 212.94. The regulations established “a two-tier pricing system which placed a ceiling on ‘old’ oil but exempted ‘new' oil from price controls.” Tenneco Oil Co. v. Fed. Energy Admin., 613 F.2d 298, 299 (Temp.Emer.Ct.App.1979). Simply stated, “new oil represented the amount of increase in production from a well since 1972. Old oil was that portion of production that was equal to what was produced from the well in 1972.” Id. Oil from stripper well leases, which represented “probably a majority” of the production on the Osage Reservation, Tr. 1228:21-1229:4 (Barker), was exempt from price controls under § 4(e)(2) of the EPAA. See also 10 C.F.R. § 212.54. From February 1, 1976 to September 1, 1976, stripper well crude oil was subject to the upper tier price ceiling, 10 C.F.R. § 212.74 (1977), before being returned to its exempt status under amendments to the EPAA, see Energy Conservation and Production Act, Pub.L. No. 94-385, 90 Stat. 1125, 1133 (1975). “In sum, during the federal price-control program, crude oil was generally sold at one of three price levels: lower tier (old oil), upper tier (new oil), and exempt (stripper well and other specified types of oil). Thus, on the same day, oil produced from the same region, county, lease, or even the same well could be sold at different prices depending on its regulatory classification.” Pi’s Br. 13. Price controls on crude oil were terminated by executive order on January 28, 1981. 46 Fed.Reg. 9,909 (1981).
Plaintiff argues that federal price controls applied to the sale of crude oil but did not discharge the duty of the United States to collect royalty according to the terms laid down in the Osage Regulations. Pi’s Br. 12-13. Plaintiff contends that “[t]he EPAA. authorized the issuance of federal regulations governing crude oil selling prices. It said nothing about modifying lease or regulatory terms establishing royalty-calculation methodologies.” Id. at 14. Plaintiff claims that by fading to apply the highest posted price or offered price paid to producers of unregulated stripper oil to the calculation of royalty payments on regulated oil, the United States violated the regulations it had established to manage the Osage mineral estate, thereby resulting in loss of royalty income to the Osage Tribe. See Pl.’s Br. 20.
Defendant acknowledges that “[w]hile MPPR did not specifically indicate whether the price controls applied to royalty interest owners,” decisions by the agency charged with their implementation consistently distinguished between working interest and royalty interest owners in providing exemptions from price controls. Def.’s Br. 14-15. Incentives in the form of exemption from price controls were granted to the producer but not to the royalty interest owner except where the latter also bore some of the cost of *660measures justifying relief. Id. at 15 (citing, inter alia, M.J. Mitchell, 3 FEA ¶ 83,146, 83,553 (Case No. FEA-2199, April 2, 1976); United States Geological Survey, 5 FEA ¶ 80,537, 80,675 (Case No. FEA-0850, January 26, 1977)). Defendant argues that “[the Department of] Interior did not have the authority to decide whether or not royalty interests were subject to the price controls imposed under the Emergency Petroleum Allocation Act ... [,] that authority resided exclusively with the Federal Energy Administration ... and Department of Energy.” Def.’s Resp. 3.
In the court’s view, the language of the EPAA, in particular its silence regarding royalty calculations, favors plaintiffs position. When interpreting a statute, the court first looks to the language of the statute itself because “[t]he canons of statutory interpretation require the court to consider first the plain language of the statute.” Skillo v. United States, 68 Fed.Cl. 734, 744 (2005); see also Consumer Prod. Safety Comm’n v. GTE Sylvania, Inc., 447 U.S. 102, 108, 100 S.Ct. 2051, 64 L.Ed.2d 766 (1980) (“[T]he starting point for interpreting a statute is the language of the statute itself.”). As plaintiff points out, the EPAA “said nothing about modifying lease or regulatory terms establishing royalty-calculation methodologies.” Pl.’s Br. 14. Finding in favor of defendant on this point would require the court to extend the reach of the statute beyond its plain language. As between accepting statutory language on its face or stretching the statute to reach a particular meaning not expressed, the court prefers a plain language interpretation.
Two additional factors persuade the court that plaintiffs argument is the better view. First, defendant itself argued for plaintiffs position in a previous case when it was advantageous for it to do so. In Pennzoil Exploration and Production Co. v. Lujan, 928 F.2d 1139 (Temp.Emer.Ct.App.1991) (Pennzoil), defendant agreed that “neither EPAA policy or any EPAA regulation was sufficiently compelling to overrule the Secretary of the Interior’s statutory authority to determine the value of production for royalty purposes.” Id. at 1144. Second, persuasive case law supports the conclusion that defendant should have collected royalty according to the terms of the Osage Regulations. See Sowell v. Natural Gas Pipeline Co., 789 F.2d 1151 (5th Cir.1986) (Sowell).
In Pennzoil, the plaintiff was allowed to sell crude oil from the outer continental shelf at unregulated prices in order to recover expenses it incurred elsewhere by participating in EPAA-approved tertiary enhanced recovery projects. 928 F.2d at 1145. Pennzoil paid its royalty, however, on the regulated price, rather than on the gross proceeds it had received from the sale of the oil. Id. at 1143. DOI ordered Pennzoil to pay royalty based on its actual selling price of the oil, in keeping with DOI’s royalty formula that based payment on not less that the “gross proceeds accruing to the lessee from the disposition of the produced substances.” Id. at 1140 (citing 30 C.F.R. § 206.150 (2005)). Contrary to its position in this case, defendant argued that Pennzoil must pay royalty according to the predetermined royalty formula, Pennzoil, 928 F.2d at 1140, and the courts found in its favor. The court of appeals upheld the district court’s finding in support of the application of DOI’s gross proceeds rule and concluded that “neither the EPAA and its regulations, nor any policy considerations arising therefrom, precluded acceptance of the DOI’s interpretation and application of its gross proceeds rule.” Id. at 1144. In this case, however, defendant argues that DOI may not exercise the very authority that it supported DOI’s exercising in Pennzoil. See Def.’s Br. 14-15. Under the doctrine of judicial estoppel, which “has been applied in this circuit to bar a party from adopting a position inconsistent with another position argued in a prior proceeding,” First Commerce Corp. v. United States, 60 Fed.Cl. 570, 576 (2004) (citing San Carlos Irrigation & Drainage Dist. v. United States, 111 F.3d 1557, 1568 (Fed.Cir.1997)), the court could bar defendant from presenting an argument opposite to an argument it presented previously. Whether or not it is barred by judicial estoppel, the court regards defendant’s argument as one of convenience and inconsistent with the plain language of the statute.
*661Defendant attempts to dismiss the authority of Pennzoil by interpreting narrowly its holding: “The Court ruled that the EPAA and its regulations did not preclude Interi- or’s application of its gross proceeds rule____It did not rule, however, that Interi- or could assess royalties based on prices exceeding those received by Pennzoil____” Def.’s Resp. 6 n. 11. The Pennzoil court actually held “that neither the EPAA and its regulations, nor any policy considerations arising therefrom, precluded acceptance of DOI’s interpretation and application of its gross proceeds rule.” Pennzoil, 928 F.2d at 1144 (emphasis added). The significance of Pennzoil is that it demonstrates that the DOI does indeed have the authority to set royalty values in accordance with prices other than prices received under regulations set by the EPAA, a position that defendant currently argues against despite having supported it in Pennzoil. See Def.’s Resp. 3. Thus, the court does not find defendant’s dismissal of Pennzoil persuasive.
Additional ease law supports by analogy plaintiffs claim that price controls on sales of crude oil did not extend to the calculation of royalty owed to the lessor. See Sowell, 789 F.2d at 1154-55. In Sowell, the court construed the terms of a general division order for the sale of natural gas under the Natural Gas Policy Act (NGPA), 15 U.S.C. §§ 3301-3432, that called for royalty to be based on the average market price for all gas in a six-county area. 789 F.2d at 1154-55. The natural gas producer argued that, by paying royalties based on the maximum ceiling price for comparable gas in interstate commerce, it had met its royalty obligations. Id. at 1154. The Fifth Circuit Court of Appeals upheld the district court’s determination that the contract required that the market price of all gas sold in the six-county area be used to set royalty payments because the contract term was not based on market value of the oh at the well. Id.
Plaintiff argues that the lease language in Sowell “is indistinguishable” from the 1997 Osage royalty value definition. Pl.’s Br. 15. As in Sowell, where the lease terms setting royalty payments applied a county average price for natural gas, the Osage royalty value definition was based on the higher of actual selling price or the highest posted or offered price in the Kansas-Oklahoma region. See Pl.’s Br. 15-16. Defendant distinguishes the ruling in Sowell on the ground that the regulatory regimes established for natural gas did not apply to all natural gas, but only to natural gas sold in interstate commerce. Def.’s Resp. 4. Defendant also cites a separate case to “rejeet[ ] [plaintiffs] analogy between EPAA and Natural Gas Act.” Def.’s Resp. 4 (citing Air Transp. Ass’n of America v. FEO, 382 F.Supp. 437, 448 (D.D.C.1974)).
The court does not find defendant’s distinctions persuasive. The method of royalty calculation in Sowell follows closely the Osage royalty value calculation in that both formulas required the royalty to be based on market prices in specified geographic areas. See Pl.’s Br. 15. Contrary to defendant’s assertion, the court in Air Transport Association did not wholly reject an analogy between EPAA and the Natural Gas Act; rather, it compared and contrasted a single provision of each act that is irrelevant to the case at hand. See Air Transp. Ass’n, 382 F.Supp. at 448. Sowell supports the conclusion that the price controls on the sales of crude oil did not extend to the calculation of royalty owed to the Osage Tribe under the 1974 Regulations. The Osage Agency incorrectly applied the royalty value formula under 25 C.F.R. § 226.11 to the maximum legal price for the first three Tranche One months, rather than to the “actual selling price, or the highest posted or offered price by a major purchaser in the Kansas-Oklahoma area.” 25 C.F.R § 226.11(2). Plaintiff is entitled to royalties determined under the 1974 Regulations for the first three Tranche One months.
IV. Alleged Failures Properly to Deal with Royalties Collected
A. Standard of Care Applicable to the Government as Fiduciary in the Investment of Royalties
Plaintiff alleges that the United States breached its duty as a trustee to invest Osage royalty revenue by (1) failing to designate a federal depositary at Pawhuska, Oklahoma until 1990, thereby unreasonably *662delaying the deposit of funds; (2) retaining unreasonably large amounts of cash in the Tribe’s royalty trust account; and (3) failing to achieve the investment yield appropriate for a prudent investor. Pl.’s Br. 33. The court agrees with the parties that the discharge by the government of its duties as trustee to invest royalties should be measured by a standard of prudence, “a prudent investor” standard. See supra II. B; Pl.’s Br. 33 (alleging that the United States breached its “duty to invest prudently”); Def.’s Br. 42 (“In investing trust funds, a trustee should exercise the care, skill, and caution that a prudent person would exercise under the circumstances.”). Defendant, in carrying out its investment duties, had the further responsibility to comply with the legal requirements applicable to those duties, including the federal statute governing the investment of Indian trust funds, 25 U.S.C. §§ 161a, 161b, 162a, applicable regulations, and applicable ease law and common law. A failure to act as a prudent investor or a failure to comply with applicable legal requirements-when any such failure results in a loss of investment income to the Osage Tribe-is a breach of defendant’s trust duties.
B. Whether the Government Properly Discharged Its Fiduciary Obligation to Invest Royalties
The court now addresses the legal arguments and evidence in the areas of dispute about defendant’s discharge of its duties to invest royalties.
1. Deposit Lag
Prior to 1990, all checks deposited with the Osage Agency were sent by certified U.S. mail to the BIA Area Office in Muskogee Oklahoma for deposit. Stip. of Fact ¶ 14; Tr. 1663:14-20 (Hill). In January 1990, the Department of the Treasury designated a local bank in Pawhuska, Oklahoma as a federal depositary. Stip. of Fact ¶ 16. Plaintiff alleges that the United States acted imprudently in failing to establish a local federal depositary in Pawhuska prior to 1990. Pl.’s Resp. 19 (“The duty of prudence required the United States to design a system that ensured that royalty revenues were deposited and began earning interest promptly. That meant designating a depository in Pawhuska.”). Defendant contends that because “there are no directly applicable statutory or regulatory prescriptions related to the timing of deposits of Osage royalty receipts, Interior followed Government-wide guidelines as well as its own, and thus acted reasonably.” Def.’s Br. 35. BIA policy during the Tranche One period was to deposit funds in an authorized depositary within 24 hours of receipt or by the next workday. The policy, as stated in 42 BIAM Supplement 3, provided:
All funds shall be deposited in an authorized Federal depositary with[in] 24 hours of receipt or by the next work day after receipt if the funds were received too late in the day to meet the depository’s and/or cognizant Collection Officer’s cutoff requirements.
42 BIAM Supplement 33.91(1) (copy of 42 BIAM Supplement 3); see DX923-0020; Tr. 1707:17-22 (Hill). Because there was no designated local depositary in Pawhuska, the Osage Agency was required to mail checks to the Muskogee Area Office for deposit at the federal depositary located there. Tr. 1663:14-20 (Hill). The Muskogee Area Office is approximately 90 miles from Pawhuska. Tr. 1727:18-20 (Hill). The BIA Area Office received the checks, entered each onto a log, completed a bill for collection for each check describing the purpose of the cheek, filled out a deposit slip for the bank, and made the physical deposit of the checks with the First National Bank, the local federal depositary. Beach Dep. 19:19-20:11.23 Royalty checks were typically processed on the day of receipt at the Muskogee Area Office or within 24 hours for late-arriving mail. Beach Dep. 35:21-36:17. The only function of the Muskogee Area Office was to deposit the funds in the federal depositary; it played no part in the accounting or investing of the funds. Id. at 30:12-31:8.
The failure to establish a federal depositary at Pawhuska prior to 1990 is not ade*663quately justified by defendant. Defendant suggests that a local depositary in Pawhuska was not required, in part because of the rapid adoption of the Electronic Funds Transfer (EFT) payment option by purchasers after EFT was first made available in 1979. Def.’s Br. 36 (noting that “all of the royalties owed for the Tranche One leases were paid by EFT during the 1980, 1986 and 1989 Tranche One months”); Tr. 1789:11-1790:5 (Bratcher). While EFT payments reduced the volume of local cash payments once widely adopted, that circumstance does not remove the economic advantage and increased security that a local depositary offered prior to 1979 and for all later cash payments not made electronically. In a letter to the Department of the Treasury (Treasury) dated June 26, 1990, Mr. Parris, then Chief of the Branch of Trust Fund Accounting, explained a request to designate local commercial banks as federal depositaries for BIA field agencies as follows:
As indicated in our previous letter, our system now requires an agency to mail daily receipts which could take anywhere from 1-3 days to reach an area office where it is finally deposited to the Federal Depositary at the area location. This present system (1) inherently places the trust funds belonging to our Indian clientele at risk; and (2) condones the significant amount of lost interest during the mail process.
Obviously, the present system is no longer adequate or acceptable.
DX986-0001 (Letter to Ann Cook, U.S. Department of the Treasury) (emphasis added). The inadequacies of the system identified by Mr. Parris in his 1990 letter certainly existed throughout the Tranche One period. The fact that a local depositary was designated in Pawhuska in 1990 (even though fewer payments were then made in cash or cheek) merely confirms the advisability of the practice.
According to the testimony of Rita Bratcher, a Treasury official who has been delegated the authority to designate commercial banks as general depositaries, Tr. 1771:17-23 (Bratcher), a local agency could request to have a local depositary designated by Treasury, Tr. 1791:21-1792:10 (Bratcher). Treasury would designate a commercial bank as a general depositary, according to Ms. Bratcher, unless the amount of deposits to be made indicated that “it wasn’t cost beneficial to set up a local bank.” Tr. 1792:22-25 (Bratcher). Ms. Bratcher explained:
[T]he purpose of using a local depositary is to get the monies into the Treasury’s account as quick as possible, and local depositaries were to deposit funds the day after a deposit____ So ... we would look at what that interest savings would be on getting the monies the next day versus mailing it, which could be two, three days to the Federal Reserve. We compensated the local depositaries for providing this service, so we would pay them for processing the checks and collecting the checks, and transferring those funds to the Treasury. So, if the interest savings on receiving the money faster in the Treasury’s account offset the cost that we would have to pay to the bank for processing those transactions, then we would establish that local depositary.
Tr. 1796:13-1797:6 (Bratcher). Ms. Bratcher concluded that, “in following good cash management, we want to get the monies into our account as quickly as possible so they can begin to start earning interest; and then also to have that money available to meet our daily disbursing needs.” Tr. 1797:13-17. The Treasury reimbursed the local bank “two or three cents per check to process” on a per item basis. Tr. 1798:1-5.
The volume of funds and number of checks for a two-day period of one of the Tranch One months was illustrated by DX451-001 and DX 479-001, exhibits identified by Judi Hill, an account technician at the Osage Agency, as Osage Agency schedules of collections. See 1683:16-17; 1658:25-1659:25. The schedule of collections “list[s] all the items that are going to be deposited that day.” Tr. 1655:11-14 (Hill). The first schedule of collections, dated February 24, 1976, lists twenty-six checks with a total value of $666,398.72. DX451-0001. The second schedule of collections, dated February 25, 1976, lists twelve checks with a total value of $323,716.57. DX479-0001. Both forms are *664signed by Pearl Kennedy, Collector Agent, for the Osage Agency. DX451-0001; DXC479-0001. For this two-day period in February 1976, then, the schedules of collections prepared by the Osage Agency show that thirty-eight checks were prepared for deposit totaling $990,115.29. The court notes that, with few exceptions, the name listed as that of the remitter of each check is clearly recognizable as the name of an oil company and that, under the Osage Regulations, royalty payments were to be made by the 25th of the month following the month of production. See id.; 25 C.F.R. § 226.13(a). The cost to the Treasury to compensate a local depositary for processing the thirty-eight checks would be, at the rate of three cents per check, $1.14. See Tr. 1798:1-2 (Bratcher) (explaining that Treasury would compensate a local depositary bank two to three cents per check for processing). At the minimum statutory interest rate of 4%, the funds prepared for deposit on February 24th would have earned interest of over $73 per day and the funds prepared for deposit the following day would have earned interest of $35.47 per day. It would appear from this illustration that the designation of a local depositary in Pawhuska would have been made by the Treasury, had BIA made the request. See Tr. 1797:2-6 (Bratcher) (“[I]f the interest savings on receiving the money faster in the Treasury’s account offset the cost that we would have to pay to the bank for processing those transactions, then we would establish that local depositary.”).
The general principle under the law of trusts is that “[w]hile the trustee has a reasonable time in which to make the initial investment or to reinvest, he becomes liable for a breach of trust if that reasonable time is exceeded.” Cheyenne-Arapaho Tribes v. United States, 206 Ct.Cl. 340, 512 F.2d 1390, 1394 (1975) (Cheyenne-Arapaho Tribes) (citing Restatement (Second) of Trusts §§ 231 and cmt. b, 181 and cmt. c (1959)). Here, the government’s own regulations require deposit within one business day of the receipt of funds. Tr. 1707:17-22 (Hill); DX923-0020 (42 BIAM Supp. 3). At the very least, the presence of a local depositary would have reduced the delay by one day by avoiding the time lost while the payments were in transit to Muskogee. From the earliest days of BIA management of the Osage mineral estate to the present, royalty payments made in cash or by check were to be deposited at the Osage Agency office in Pawhuska. The 1912 Osage Regulations required that “[a]ll rentals, royalties, damages, or other amounts which may become due under leases approved in accordance with these regulations shall be paid to the superintendent of the Osage Indian School at Pawhuska, Okla.” 1912 Regulations § 21. Under the 1974 Regulations, “[s]ums due under a lease contract and/or the regulations in this part shall be paid by cash or check made payable to the Bureau of Indian Affairs and delivered to the Osage Agency, Pawhuska, Oklahoma.” 25 C.F.R. § 226.4 (emphasis added). The court finds that defendant breached its trust duty by failing to request designation of a local depositary prior to the Tranche One months.
The steps to be taken by Osage Agency staff in processing incoming checks during the Tranche One period are set out in Title 42 of the Bureau of Indian Affairs Manual, Tr. 1629:2-4 (Hill), and included preparation of a mail room schedule of collections listing all cash payments received, Tr. 1640:18-1641:2; completion of a bill of collections for each payee, Tr. 1645:23-1650:5; determination of the purpose of the payment, generally by staff in the Minerals Branch of the Osage Agency, Tr. 1650:16-1651:15; preparation of a schedule of collections by the collections officer listing all items to be deposited that day, Tr. 1655:9-21; completion of a certificate of deposit reflecting the total amount to be deposited, Tr. 1651:16-1652:13; and preparation of an encoding sheet for entry of the payment data into the BIA computer system, Tr. 1663:8-11; see also Def.’s Br. 36-37.
Defendant’s expert proposed a three-day grace period from the time of collection to the date of deposit and posting as “a reasonable amount of time to collect, process and deposit funds.” DX2676-0005 (Expert Report-Revised of Gregory J. Chavarria, March 13, 2006). The three-day period included an allowance for mailing the deposit to Muskogee and the deposit there of the funds. Tr. 1854:10-18 (Chavarria). Plaintiffs expert, in contrast, based his calculations of deposit lag *665time on the principle that “a prudent trustee should deposit trust funds on the same day they are received ... if possible, and within one business day in any event.” PX750-0010 ¶ 28 (Revised Expert Report of Stephen A. Jay, March 13, 2006). Notwithstanding the fact that there is some complexity in the tasks required to insure the proper attribution of payments and the correct allocation of funds (for instance, where a check may include multiple payments, Tr. 1730:23-25 (Hill)), the policy objective stated in 42 BIAM Supplement 3 of depositing payments within 24 hours or no later than the next business day following receipt of the payment, Tr. 1707:17-22 (Hill), sets out a reasonable standard for defendant’s discharge of its duties as trustee. If a depositary had been established in Pawhuska, defendant could have complied with its own policy objective. Defendant is liable for investment income lost owing to its failure to meet the policy objective stated in 42 BIAM Supplement 3.
2. Whether Defendant Carried Out Its Investment Duties in Accordance With Law
a. Whether Defendant Permitted Excessive Cash Balances
Plaintiff argues that “the United States lost a substantial amount of interest income by keeping unreasonably large balances in the cash account.” Pl.’s Br. 35 (noting that plaintiffs expert, Stephen Jay, shows lost interest income from under-investment of cash balances in all five years containing Tranche One months) (citing PX750-0023 to 25, 0048). Plaintiff contends that these “[ljarge amounts of cash could have been put in T[reasury]-bills at higher rates” and cites reported cash balances “as high as $2,531,196.92 for June to Sept. 1979 [and] cash balances as high as $18,269,986.53 for Dec. 1980 to Mar. 1981.” Pl.’s Resp. at 16-17 (citing JX035-0039 to 0060 and JX048-0015 to 42). By failing to invest cash balances in higher-yielding instruments, plaintiff argues, the United States breached its duty to invest prudently. Pl.’s Br. 33.
Defendant did not address the issue of under-investment of cash balances at trial and, in its post-trial briefing, argues that “[p]laintiff should not be permitted to present such new factual assertions now.” Def.’s Resp. 15. Defendant contends that “[i]n its Post-Trial brief, [p]laintiff for the first time offered a different assumption of how the Tranche One royalties should have been allocated between investments in CDs and in cash.” Id. The court does not agree with defendant that the issue of under-investment of cash balances was only addressed after trial. The issue is afforded its own heading in JX113-0001, Expert Report of Stephen A. Jay, dated September 30, 2005 (see Lost Investment Income On Cash Funds, JX1130012 ¶ 34-35), and in Jay’s Revised Expert Report of March 13, 2006, PX750-0024 ¶ 69, and is also the subject of a separate damages table, see PX750-0038. At trial, defendant’s investment calculation expert, Charles Lundelius, read segments of a report prepared for the BIA by Price Waterhouse that reviewed “investment process guidelines” followed by the BIA Branch of Investments.24 Tr.2095:23-2100:25. The report states, “Funds in excess of $25,000 not placed in CDs are invested in U.S. Treasury market bills. Because uninvested cash receipts are on deposit with the U.S. Treasury, the investment transaction can be accomplished by telephone.” DX1668-0134 (Review of Indian Trust Fund Management for Bureau of Indian Affairs, Draft Report, Sept. 26, 1983). When asked to describe the meaning of this passage by defense counsel, Mr. Lundelius replied:
You’ve got an investment process whereby the selection is between Treasury bills and CDs. And the reason that that is the case are those are the investment instruments that are best suited to meeting the quarterly annuity requirement. Then, what you see here is a bid solicitation process whereby the chief of Investments, here at BIA, is soliciting bids from banks for CDs. The ... CD bids are aggregated and then as*666sessed as to, I guess, which ones are appropriate. And by appropriate, I mean that you have to have CDs for the Osage that mature on or before the quarterly annuity date, in order to provide cash to make your payments to the Head Right owners.
Tr. 2101:1-13 (Lundelius) (emphasis added). BIA policy was to invest funds in excess of $25,000 in U.S. Treasury bills (T-bills) if they could not be placed in CDs. DX1668-0134. The retention of large amounts of cash outside of these two instruments would therefore appear to be contrary to BIA policy. Mr. Lundelius acknowledged at trial that the description of BIA policy as read was, to his knowledge, accurate and applicable to the investment of Osage funds during the Tranche One period. Tr. 2101:14-20.
The analysis by defendant’s own expert does not require holding any Osage funds in cash balances and instead provides for all short-term liquidity needs to be covered by investments in T-bills. See DX2695-0013 to 14 ¶¶ 29-31 (Charles R. Lundelius, Jr., Expert Report (Revised), March 13, 2006) (Lundelius Rev. Exp. Rep.) (concluding that the combined short-term liquidity needs for disbursements to beneficiaries, gross production taxes and council costs, and time needed to locate appropriate higher-yielding CDs “together ... indicate investments in Treasuries could be as high as 20%”). Defendant also acknowledges that deposits of Osage funds “started earning four percent simple interest under [25 U.S.C.] Section 161a until they were placed in longer term investments, ” and that, beginning in January 1985, “Interior invested the funds in the Treasury Overnighter until they could be placed in higher-yield bank CDs or Treasury bills.” Def.’s Br. 44-45 & nn. 44-45 (emphasis added). The expectation, then, was that cash balanees-whether invested at the statutory 4% rate or held in overnight accounts-would be quickly converted into higher-yielding investments. Def.’s Br. 45 (stating that the BIA’s Branch of Investments sought to place Osage royalty payments in longer-term investments “[a]s soon as possible after receipt of payment”).
The United States Court of Claims in Cheyenne-Arapaho Tribes addressed issues very similar to those now before the court. In that case, a number of Indian tribes brought suit against the United States to recover damages for the alleged failure of the United States properly to invest funds held in trust for the tribes. 512 F.2d at 1391-92. The plaintiff tribes alleged that defendant breached its fiduciary duties through undue delay in making funds available for investment and by not maximizing the investment yield available under existing statutes governing the investment of Indian trust funds. Id. at 1392. Because there were investment options available for trust funds that offered a higher rate of return than the statutory minimum offered by the Treasury, “the trustee has the burden of proof to justify less than a maximum return.” Id. at 1394 (citations omitted) (noting that the trustee’s fiduciary duty included the “obligation to maximize the trust income by prudent investment”). The Court of Claims addressed the matter of liquidity requirements and observed that “[i]n the absence of a showing by defendant of specific immediate budgetary commitments by the tribes, claimed liquidity needs should be considered in the light of the actual history of the tribes’s funds.” Id. at 1395 n. 9.
The standard articulated by the Court of Claims in Cheyenne-Arapaho Tribes appears to the court to be equally applicable here. Outside of the quarterly annuitant25 disbursements, the liquidity needs of the Osage royalty account were principally for council expenses and gross production taxes. See DX2695-0013 ¶ 29 (Lundelius Rev. Exp. Rep.) The fiduciary requirement to make prudent investments requires that any amount maintained as a cash balance that is in excess of the immediate disbursement *667needs for the period should be invested in a vehicle offering a higher return. See Blankenship v. Boyle, 329 F.Supp. 1089, 1095-96 (D.D.C.1971) (finding that the maintenance of a large accumulation of excess cash where “income and outgo were constant” and government securities could be redeemed at short notice violated the “fiduciary obligation to maximize the trust income by prudent investment”). BIA policy, as presented by defendant at trial, was to invest cash surpluses in excess of $25,000 in CDs or in U.S. T-bills. Tr.2098:ll-25; 2100:14-21 (Lundelius). The court finds that the United States is hable for additional investment income that would have been earned had the United States made prudent investments of any cash balances of royalty income in excess of $25,000.
b. Whether Investments Were Made in Accordance With the Law
Defendant argues that the federal statutes governing the investment of Indian trust funds, specifically 25 U.S.C. §§ 161a and 162a, “expressly vested in Interior the discretion to select among the investment options and vehicles authorized” and that the exercise of this discretion “also warrants measurement against a prudent investor standard.” Def.’s Br. 42. Defendant advances three “requirements” that a prudent trustee must consider in carrying out its duties: the requirement of care, whereby a trustee must investigate the investments available for the funds; the requirement of skill, which requires that the trustee exercise “the reasonable degree of skill of a prudent person;” and the requirement of caution, which requires that the “trustee recognize that his primary purpose ‘should be to preserve the trust estate, while receiving a reasonable amount of income.’” Id. at 42-43 (quoting William F. Fratcher, Scott on Trusts § 227.3 (4th ed. 1988)) (Scott on Trusts). This general statement of the trustee’s prudential obligations is appropriate where common law alone establishes the rule. See Def.’s Pretrial Mem. 84 (noting that the general common law rule related to the investment of trust funds “is that the trustee is under a duty to make such investments as a prudent person would make of his own property” (citation omitted)). Here, however, the general common law principle must be interpreted in harmony with the duties imposed by Congress in the statutes governing the investment of funds held in trust by the United States and applicable case law. Shoshone, 364 F.3d at 1353 (finding that the Federal Circuit “has previously held that 25 U.S.C. §§ 161a, 161b, and 162a mandate payment of interest”) (emphasis added).26 Because, as defendant itself acknowledges, the “permissible investments in which the Osage [Tribe]’s ... trust funds may be placed” have been spelled out by Congress, Def.’s Br. 42; Def.’s Pretrial Mem. 93, and “Congress [has] provided certain security requirements for ... investments,” Def.’s Br. 42, defendant’s prudent discharge of the requirements of care and caution is *668limited to selecting the highest yielding investment instruments of suitable maturity available for trust funds. See also DX26950007 to 11, ¶¶ 14-23 (Lundelius Rev. Exp. Rep.). Having made its election of the appropriate type of investment instruments, the requirement of skill obliges the trustee to obtain the highest rate of return available from the prudent management of the statutorily mandated investment instruments.
The Court of Claims has addressed the statutory obligations under 25 U.S.C. §§ 161a, 161b, and 162a on a number of occasions and has uniformly held the United States responsible for investing Indian trust funds in the highest yielding investment vehicles available to the funds in question. In Mitchell v. United States, 229 Ct.Cl. 1, 664 F.2d 265 (1981), the Court of Claims, in an en banc decision, found that under these statutes “[t]he bank deposits are subject to rigid statutory precautions to assure complete safety.... [Djefendant must as trustee exercise reasonable management zeal to get for the Indians the best rate, the statutory 4% being but a floor, not a ceiling.” 664 F.2d at 274 (emphasis added). Under similar circumstances where the trustee had alternative, higher yielding investments available, the Court of Claims ruled:
[O]n those funds which defendant in effect borrowed from plaintiffs by retaining them in the Treasury, we hold defendant to a strict standard of fiduciary duty — if eligible investments were available at higher yields, defendant will be liable to plaintiffs for the difference between what interest defendant paid for the funds and the maximum the funds could have legally and practically earned if properly invested....
Cheyenne-Arapaho, 512 F.2d at 1396 (emphasis added). The requirement to invest Indian trust funds in the highest yielding investments available is a legal requirement mandated by the applicable statutes — here, 25 U.S.C. §§ 161a and 162a — and not solely a prudential one. The court in Cheyenne-Arapaho also adopted a prudent investor standard in defining the duty owed by the United States and made it clear that a prudent investment under these circumstances is one that maximizes the trust income earned from available investments. Id. at 1394 (finding that “[t]he fiduciary duty which the United States undertook ... includes the ‘obligation to maximize the trust income by prudent investment’ ” (citing Blankenship v. Boyle, 329 F.Supp. at 1096) (emphasis added)).
Defendant’s expert in investment evaluation, Mr. Lundelius, Tr.2083:7-15, proposed “an expected rate that a prudent investor could have achieved during this time period under the constraints imposed by the duties of care and caution.” Def.’s Br. 47. This “prudent investor rate” was accepted by both parties 27 as “an appropriate standard against which to measure whether the United States satisfied its fiduciary duty of investing trust funds prudently.” Pl.’s Resp. 15; see Def.’s Br. 47 — 48 (noting that the quarterly expected rate used by defendant was derived from “a combination of contemporaneous 3-month CD rates (80%) and 3-month Treasury bill rates (20%), to reflect the rates of return on investments available to the Osage funds on a quarterly basis during Tranche One”). Defendant’s expert also compared different mixes of CDs and bills, including a 90% CD and 10% T-bill rate and a 100% CD rate, but found the expected rate of 80% CDs and 20% T-bills, referred to as the 80/20 rate, was the *669most realistic measure under the conditions presented by the Osage Tribe’s particular investment and disbursement needs. Tr. 2140:17-2142:20 (Lundelius). Based on application of the prudent investor rate of 80% CDs and 20% bills, defendant concludes that “the United States met or outperformed the expected rate in four of the five Tranche One periods of investment and, for the fifth, determined that the returns fell just shy of the expected rate.” Def.’s Br. 48-49.28 Plaintiffs expert concluded, however, that the United States breached its duty of prudent investment in three of the five Tranche One months. Pl.’s Br. 33; see PX750-0048 (Jay Rev. Exp. Rep.).
Plaintiff argues that, by treating the “uninvested” cash balances as a component of the 20% of revenues invested in T-bills, defendant’s “actual” rates of return from Tranche One investments are inflated. Pl.’s Br. 36-37. Plaintiff contends that “Tranche One royalties should be allocated between CDs and cash just like any other trust income and, as a result, only 86% of the Tranche One collections should have been allocated to the traced investments (bridging T-bills and CDs) and 14% should have been allocate to maintaining available cash.” Id. at 37 (citation omitted). Plaintiff concludes that, using the “corrected” actual rates provided by defendant in its post-trial brief, “Lundelius’s methodology proves breach in the same three months as [plaintiffs expert].” Id. at 38.
The parties rely on different source data and methodologies to evaluate investment results. Plaintiffs expert used data derived from the Arthur Andersen Trust Fund Reconciliation Project report prepared for the Osage Tribe (Arthur Andersen report). See Pl.’s Br. 35; PX476 (copy of Arthur Andersen report). Plaintiff derives average monthly figures for a particular Tranche One month from annual data provided in the Arthur Andersen report. Pl.’s Br. 35. Mr. Jay explained:
What I tried to do was compare the actual results that Arthur Andersen reported as far as investment income for each of the fiscal years containing Tranche One months with the amount of earnings that would have been earned from the cash and invested cash with the cash computed at an investment rate of four percent and the invested funds computed at Mr. Lundelius’ rate for ... his expected rate.
Tr. 628:21-629:3(Jay); see also Tr. 510:15-511:22(Jay). Mr. Jay acknowledged that his calculations for interest lost on “uninvested” cash balances, that is, cash that was not invested in a CD or T-bill, used only the statutory interest rate of 4% that was applicable in 1985 and did not consider the potentially higher rate available from the “overnighter rate” used after 1985 for cash balances. Tr. 629:4-17(Jay). Plaintiffs expert also conceded that the methodology and data sources he employed were not able to produce results based exclusively on the Tranche One months or Tranche One leases. Tr. 587:22-588:5(Jay) (answering “no” to the question “none of the calculations in your expert reports dealing with deposit lag time, lost investment income, lost investment income on cash funds focus solely on Tranche [One] leases, do they?”); Tr. 611:7-25(Jay) (acknowledging that he used annual data rather than Tranche One-*670specific data and that the investment data was from all sources, not only oil and gas from Tranche One leases).29 Plaintiff contends that the data provided in the “detailed final report,” Pl.’s Br. 35, prepared for the Osage Tribe by Arthur Andersen, provides “a reasonable estimate,” Pl.’s Br. 34, of the data the Osage Tribe would have obtained had data been available from BIA records.
Defendant’s expert testified that he had conducted a “forensic accounting” using data specific to the Tranche One leases and Tranche One months. See Tr. 2143:7-2144:8; Tr. 2249:10-22 (Lundelius); see also Def.’s Br. 48. Mr. Lundelius identified royalty payments from purchasers of Osage oil (using the purchasers identified by defendant’s royalty calculation expert, Ronnie Martin). Def.’s Br. 48. Defendant claims that Mr. Lundelius’s methodology allowed him to “follow[ ] the royalties from the time the checks were deposited into account 7386 [the Osage trust fund for revenue], through the manner and means by which they were invested, to the point they were disbursed as part of a quarterly annuity.” Id. Defendant contends that Mr. Lundelius was able to “caleulate[] the actual return achieved on the investments ... [and] compare[ ] the actual return to the expected return [80% CDs and 20% T-bills] to evaluate the United States’ performance.” Id. Mr. Lundelius concluded that the “the United States met or outperformed the expected rate in four of the five Tranche One periods of investment and, for the fifth, determined that the returns fell just shy of the expected rate.” See id.
In response to Mr. Lundelius’ conclusion, plaintiff argues that the United States never kept any accounting records that purport to identify a particular investment or expense as “flowing” from any particular income. Pl.’s Br. 38.30 A portion of plaintiffs cross-examination of Mr. Lundelius was directed to a demonstration of its argument that the methods used by Mr. Lundelius to calculate actual returns relied on inferences of an entirely speculative nature. In particular, the cross-examination consisted in the identification by plaintiffs counsel of particular deposits into account 7386 of royalty payments and questions to Mr. Lundelius inquiring why, in the so-called tracing analysis in his report, he had associated certain deposits with certain investments. Tr. 2266:15-2290:6. The court concluded, based on Mr. Lundelius’ testimony elicited on cross-examination and the court’s review of DX2695, that his tracing analysis was indeed speculative. Mr. Lundelius simply could not explain how he knew which funds were placed in which investments. Instead, he assigned royalty income into account 7386 to particular investments that could be expected to mature on the date of quarterly annuity payments to Osage Tribe members, Tr. 2287:7-22, notwithstanding the existence of significant pre-existing cash balances, Tr. 2289:7-2290:6, that could also have been used, in whole or in part, to acquire those same instruments. Mr. Lundelius’ so-called tracing analysis was therefore based on inferences that were entirely favorable to the government and not supported by the evidence.
Plaintiffs analysis, by contrast, relies on overall investment results for revenues held in the Osage revenue account, an approach that the court considers to be a more accurate means of determining investment performance in the absence of complete records. The Osage Tribe is entitled to damages reasonably estimated based on existing information. Especially where, as here, proper trust records are missing, doubts about calculations should be “resolved against [the trustee].” Confederated Tribes of the Warm Springs Reservation v. United States, 248 *671F.3d 1365, 1373 (Fed.Cir.2001) (citing William F. Fratcher, Scott on Trusts § 172 (4th ed.1987)). The court will assume that, for each of the Tranche One months, the average daily cash balance was the same as the average daily cash balance for the year (as nearly as such amount may be determined) in which that Tranche One month occurs. The court will also assume that, for each of the Tranche One months, the average daily investments of Osage tribal income from the Tranche One leases in CDs and T-bills was proportional to the average daily investment in CDs and T-bills of all funds in account 7386 for the year (as nearly as such amount may be determined) in which that Tranche One month occurs. The United States is liable for any failure to achieve the expected return of “a combination of contemporaneous 3-month CD rates (80%) and 3-month T-bill rates (20%),” Def.’s Br. 48, on average daily balances in excess of $25,000.
3. Interest on Damages
The parties are not in agreement on the appropriate rate of interest to apply to damage calculations. Plaintiff most recently proposes use of the seven-year T-bill rate, Tr. 595:5-8(Jay), and argues that “[seven]-year Treasury rates are an appropriate measure of the time value of the interest the Osage Nation lost ... because they also generally track the expected rates of return that ... a prudent investor would have realized on funds collected for the Tranche One Months.” PX750-0015 ¶ 42 (Jay Rev. Exp. Rep.). Defendant argues against adopting this rate, explaining that “a seven-year note is not something that falls within the investment parameters for the Osage for the oil and gas royalty account.” Tr. 2243:17-19 (Lundelius). Defendant’s expert proposes that, because the Osage trust fund account into which oil and gas receipts are deposited is set up for disbursements on a quarterly basis, “[a] more appropriate interest rate would be something that reflects the fact that you have quarterly distributions.” Tr. 2243:22-2244:1 (Lundelius). The issue was touched on only fleetingly at trial and will be the subject of further briefing. See infra Part V.
V. Conclusion
For the foregoing reasons, the court finds that the Osage Tribe is entitled to compensation for the following breaches of defendant’s fiduciary duties:
• Failure to Collect Royalties Based on Highest Offered Prices (Part II.C.3)
• Failure to Collect Full Royalties During Price Controls (Part III)
• Failure Promptly to Deposit Funds Because of Unreasonable Failure to Certify a Federal Depositary (Part IV.B.l)
•Failure to Maintain Appropriate Cash Balances (Part IV.B.2.a)
• Failure to Obtain Investment Yields in Accordance With Law (Part IV.B.2.b)
The parties shall, on or before November 2, 2006, jointly calculate and present to the court the amount of damages to which plaintiff is entitled in accordance with the foregoing Opinion. The parties shall also brief the basis for the appropriate rate or rates to apply in determining the current value of the damages for which defendant has been found hable. The briefing on interest shah include citations to any persuasive precedent. The parties shall also consider and brief whether, in lieu of or in addition to interest, plaintiff should be awarded late fees on, and as part of, its damages. If for any reason the parties do not agree on any part of the damages calculations, the parties shall, on or before November 2, 2006, also present to the court such calculations on damages as to which they do not agree accompanied by specific and complete statements explaining their respective positions and the bases therefor.
IT IS SO ORDERED.

. The original complaint in this case was filed on August 2, 1999 by "The Osage Nation 1 and/or Tribe of Indians of Oklahoma” and assigned case no. 99-550L by the court. Two amendments of that complaint were filed under the name “The Osage Tribe of Indians of Oklahoma” in March and August of 2004. A separate suit was brought by "The Osage Nation and/or Tribe of Indians of Oklahoma" on March 31, 2000 and assigned case no. 00-169L. The cases were consolidated by the court on September 14, 2005 and the earlier-filed suit, case no. 99-550L, was designated the lead case. See Order of Sept. 14, 2005 at 1. As does plaintiff in its briefs, the court refers to plaintiff interchangeably as the Osage Tribe or the Osage Nation.

. The Order of April 15, 2005 in case no. 00-169L designated five leases and six months to be included in Tranche One. Those five leases are commonly known as the East Hardy Unit, the North Burbank Unit, the North Avant Unit, the Osage Hominy Unit, and the Stanley Stringer Unit. See Osage Nation’s Statement of Trust Fund Mismanagement Claims for Tranche One (T1 Statement of Claims) 1. As a result of issues that arose during discovery, which the parties addressed in a pre-trial conference on February 16 and 17, 2006, one lease (the Stanley Stringer Unit) and one time period (the month of October 1990) were removed from Tranche One and transferred to Tranche Two. Order of February 22, 2006 at 2. The order of February 22, 2006 (like all orders of the court subsequent to September 14, 2005) was filed in case no. 99-550L.

. The parties agreed, and the court so ordered, to delete from Tranche One the trial of alleged breaches by the government of any fiduciary duty *632in regard to the treatment of Osage trust funds that have been segregated for disbursement. Order of March 22, 2006 at 2. The "disbursement lag issue," as it is referred to by the parties, will be considered under Tranche Two of the case.

. For additional background information, see Osage Tribe of Indians of Okla. v. United States, 68 Fed.Cl. 322, 323-24 (2005) (Osage 1) (finding that the Act of June 28, 1906, ch. 3572, 34 Stat. 539 (1906 Act) created a trust with respect to the management by the government of plaintiff's oil and gas interests).

. The Act of June 28, 1906, ch. 3572, 34 Stat. 539, was subsequently amended and modified. See Act of March 3, 1921, ch. 120, 41 Stat. 1249; Act of February 27, 1925, ch. 359, 43 Stat. 1008; Act of March 2, 1929, ch. 493, 45 Stat. 1478; Act of June 24, 1938, ch. 645, 52 Stat. 1034; Act of July 25, 1947, ch. 334, 61 Stat. 459; Act of June 15, 1950, ch. 248, 64 Stat. 215; Act of October 6, 1964, Pub.L. No. 88-632, 78 Stat. 1008; and Act of October 21, 1978, Pub.L. No. 95-496, 92 Stat. 1660.

. The investment claim briefing included Plaintiff Osage Nation’s Brief Clarifying Legal Bases for its Investment Claims; Defendant’s Motion to Dismiss in Part, Plaintiff's Investment Claims as Set Forth in Plaintiff's Brief Clarifying Legal Bases for its Investment Claim; Plaintiff Osage Nation's Opposition to Defendant's Third Motion to Dismiss (Defendant’s Motion to Dismiss); and Defendant's Brief in Reply to Plaintiff’s Opposi*633tion to Defendant’s Motion to Dismiss, in Part, Plaintiff's Investment Claims as Set Forth in Plaintiff’s Brief Clarifying Legal Bases for its Investment Claims. As a result of the resolution of the issues by trial, Defendant’s Motion to Dismiss is MOOT.

. C.H. Thorman & M.H. Hibpshman, Status of Mineral Resource Information for the Osage Indian Reservation, Oklahoma, BIA Administrative Report 47 at 2 (1979).

. For convenient reference, the name and a description of each witness follows:
Newell Barker (Trial Transcript (Tr.) 1110:5-1352:22) worked for the Osage Indian Agency (Agency) at the Bureau of Indian Affairs (BIA) as the chief of the minerals branch, beginning in 1974. Tr. 1117:3-17. In that capacity, he "was responsible to manage the mineral estate of the Osage Tribe of Indians, which consisted of about 1.5 million acres in Osage County.” Tr. 1117:15-17. Mr. Barker supervised the leasing of the properties, the management of the properties (including lease inspections) the accounting of production, and income. Tr. 1117:18-21. Prior to joining the Osage Agency, Mr. Barker earned a bachelor’s of science degree in petroleum engineering from Texas Tech in Lubbock, Texas in 1961, Tr. 1110:16-20 and attended courses in operation, engineering, and management throughout his career, Tr. 1110:23-1111:1. His employment history comprises the following: mud engineer at Permian Mud Service out of Odessa, Texas from 1961-1965, Tr. 1111:10-15, and at Magcobar in Venezuela from 1965 to 1972, Tr. 1112:11-14; operations manager at Thermodyne, Inc. in Oklahoma from 1972-1973, Tr. 1114:21-24; and senior petroleum engineer at Standard Oil Company in Ohio from 1973-1974, Tr. 1115:19-21. Mr. Barker became a licensed registered professional engineer in 1974, the same year that he joined the Osage Agency. Tr. 1116:15-1117:7.
Jerri Jean Branstetter (Tr. 854:5-968:16) is a member of the Osage Nation and a headright owner, meaning that she receives a quarterly annuity from the mineral estate of Osage County. Tr. 854:18-855:11. From 1974 to 1980, Ms. Branstetter worked as an accountant technician at the Osage Agency. Tr. 860:21-861:9. Prior to that position, she served as a clerk in the credit department at Graves Jewelers in Tulsa, Oklahoma, Tr. 856:20-23, and as a cashier/bookkeeper with Family Loan and Thrift, Tr. 858:7-10. She then held positions with several other finance companies. Tr. 859:4-7. For the past nineteen years, she has worked at the DeConnor Correctional Center in Hominy, Oklahoma. Tr. 855:18-856:2.
Rita Bratcher (Tr. 1764:1-1800:18) works for the Financial Management Service, a bureau of the U.S. Treasury Department. Tr. 1764:9-10. She is the director of the revenue collection group, and she is responsible "for three divisions of people who develop, operate and market various collection systems that the government has in place to move monies that are owed to the government into the Treasury’s account as quickly as possible.” Tr. 1764:13-18. Ms. Bratcher began working for the Treasury Department in 1971 in the Banking and Cash Management division. Tr. 1765:5-15.
Gregory J. Chavarria (Tr. 1802:7-2048:14) was qualified by the court as an expert in accounting, particularly accounting related to tribal funds held in trust by the United States, including funds of the Osage Tribe. Tr. 1828:25-1829:3. He currently works for Chavarria, Dunn and Lamey, LC, an accounting firm located in Albuquerque, New Mexico. Tr. 1802:20-23. Prior to this position, he worked at Arthur Anderson as a staff person, a senior auditor, and a manager. Tr. 1803:17-19. Throughout his time at Anderson, Mr. Chavarria was involved in engagements for BIA, specifically "reconciliation efforts regarding Tribal Trust Accounts.” Tr. 1806:6-13.
*634Melissa Currey (Tr. 2355:2-2430:16) is the superintendent for the Osage Agency. Tr. 2356:3-4. Since attaining this position in November 2004, Ms. Currey is "responsible for the management and oversight of the daily operations in relation to the Osage Mineral Estate[,] ... the restricted land[,] and the daily activities that are involved in taking care of these items.” Tr. 2356:6-14. Ms. Currey has worked for BIA for over twenty-one years, beginning as a clerk typist and continuing as a realty clerk, realty assistant, realty specialist, supervisory realty specialist, permanent supervisor for real estate services, and deputy superintendent for trust services before acquiring her current position. Tr. 2357:16-2362:6.
Judi Hill (Tr. 1623:20-1754:9) was first employed by the Osage Agency in 1978 and served as a primary collection officer from 1981 to 1996. Tr. 1625:2-1626:5. She was transferred to the Pawnee Agency where she worked for five years before returning to the Osage Agency in June 2001 where she is employed as an accounting technician, which is her current title. Tr. 1626:7-1626:23.
Charles Hurlburt (Tr. 972:8-1082:23) works as a supervisory petroleum engineer at the Osage Agency, a position he has held since April 1989. Tr. 972:14-21; Tr. 974:9. He first joined the Osage Agency in 1983. Tr. 972:16-18. He is a licensed professional engineer in Oklahoma. Tr. 972:23. He earned a bachelor of science degree in petroleum engineering from the University of Tulsa in Oklahoma in 1979. Tr. 973:8-14.
Stephen Allen Jay (Tr. 437:25-686:22) was qualified by the court as an expert in auditing, analyzing financial statements and damage calculations. Tr. 465:17-20. He received bachelor’s and master’s degrees in accounting from Oklahoma State University. Tr. 438:9-11. He is a certified public accountant, licensed by Oklahoma, and he is accredited by Oklahoma in business evaluation. Tr. 438:16-19. After earning his master’s degree and serving in the U.S. Army, Mr. Jay worked for Arthur Young & Company, an accounting firm, in Tulsa, Oklahoma, Tr. 439:22-440:10; entered into a partnership and founded an accounting firm, Lohrey & Jay, Tr. 441:17-22; and formed his own accounting firm, Jay & Associates, P.C., Tr. 442:12-15, of which he is currently the managing shareholder.
Charles Reynold Lundelius, Jr. (Tr.2065:21-2297:13) was qualified by the court as an expert "on investment evaluation, including the determination of the prudence of investments and investment practices, financial analysis, including the calculations of rates of return, ... accounting, auditing, and damages.” Tr.2083:7-15. He is currently senior managing director at FTI, where he leads the securities transactions services group. Tr.2066:8-13. He received his bachelor of science degree in commerce from the University of Virginia in 1978 and his master's of business administration from Tulane University in Louisiana in 1980. Tr.2066:18-2067:8. Soon afterwards, Mr. Lundelius, a certified accountant, worked for Arthur Young, an accounting firm in Houston, Texas, and then formed his own investment banking consulting firm. Tr.2067:23-2068:24. After six years, he accepted an offer to serve as chief financial officer and chief investment officer for Unimark, a life and health insurance company based in Dallas, Texas. Tr.2070:2~6. Mr. Lundelius then served in the following positions before his current employment with FTI: as a manager for Coopers & Lybrand, a Washington, D.C.-based accounting firm; as a senior manager for Deloitte & Touche, a national accounting firm; and, lastly, as a partner at Kroll, a Washington, D.C. accounting firm. Tr.2072:8-2076:3.
Stanley Ann Mattingly (Tr. 727:18-758:25) is a co-founder of the Osage Shareholders Association, an organization whose purpose “is to be a watchdog over the Osage Tribal Council and how [it] spend[s] the royalty money,” as well as "to keep track" of the Osage Agency’s activities. Tr. 729:13-20. She is a registered nurse who holds an associate’s degree in nursing from Tulsa Junior College. Tr. 728:18-19.
Ronnie Martin (Tr. 1362:2-1622:12) was qualified by the court as an expert in "oil ..., oil royalty calculation, the verification of oil royalty paid, and oil royalty practices that have been further discussed” during trial. Tr. 1385:16-21. He is senior managing director for FTI Consulting (FTI) in Houston, Texas. Tr. 1362:11-13. He also is the practice leader for FTI’s oil and gas services practice. Tr. 1365:20-22. Previously, he worked for Texaco for thirty-three years; his last position there was vice president of Texaco Exploration Producing, Inc. Tr. 1373:22-1374:7. At both companies, his duties are and were to help clients “analyze the claims relating to oil and gas issues, primarily valuation issues, particularly with respect to royalty and sometimes severance tax issues.” Tr. 1367:17-20. He graduated from Mississippi State University in 1969 with a bachelor of science degree in mechanical engineering and is a member of the National Energy Services Association. Tr. 1364:6-15.
Lucian Morrison (Tr. 2314:3-2351:15) is a consultant in a sole proprietorship, Lucian L. Morrison & Associates, where he consults "in the areas of trusts, estates, probate, trust companies, taxation, and the like.” Tr. 2314:9-15. One of the trusts that he currently manages is the San Pedro Ranch Trust. Tr. 2319:12-14. He holds an accounting and law degree from the University of Texas at Austin, and he has "the industry equivalent of a master’s degree from the Southwestern Graduate School of Banking at [Southern Methodist University] in Dallas[, Texas].” Tr. 2315:21-25.
Jim Parris (Tr. 296:4-423:20) is a licensed accountant who presently works as a consultant for the Osage Tribe. Tr. 297:2; 303:1. After graduating from Oklahoma State University with a bachelor’s degree in accounting in 1977, Tr. 296:6-12, Mr. Parris held the following positions: comptroller for the Osage Tribe, 1978 through 1979; partner at an accounting firm in Ponca City, Oklahoma, 1979 through 1980; auditor for a private company from 1981-1982; tribal audi*635tor for the Osage Tribe from 1983-1985; chief of the branch of Trust Fund Accounting at BIA, 1985-1991; director of Office of Trust Fund Management at BIA, 1991-1995; solo practitioner, 1995-1996; consultant for KPMG, 1996-1998; accountant for REDW, a "large regional CPA firm that did a lot more tribal work," 1998— 2000; consultant for Strategic World Management, 2000-2001; and, his current occupation, as a private consultant with the Tribes, which he began in 2001. Tr. 296:14-301:24.
Daniel Reineke (Tr. 44:6-285:21), qualified by the court as plaintiff's expert on "oil royalty calculation and verification of royalty due,” Tr. 58:24-59:2, is a registered petroleum engineer who manages his own company, Daniel Reineke, P.E., Tr. 44:17-22. He received a bachelor of science degree in petroleum engineering from Colorado School of Mines in 1975 and worked for Conoco in Texas as a drilling engineer immediately afterwards. Tr. 46:14 — 18. Mr. Reineke then became a division engineer for Same Dan, “a large independent oil company in Oklahoma City.” Tr. 47:1-5. He left Same Dan in 1979 and worked as an independent consulting engineer for individual oil companies. Tr. 48:8-10. He is a registered professional engineer in Oklahoma. Tr. 48:22-23.
Eugene Shawn Standing Bear (Tr. 759:18-796:11) worked at the Osage Tribal Museum in Pawhuska, Oklahoma from fall 1992 until summer 1997. Tr. 761:1-4. He began his employment there as a collections manager and then was appointed as director of the museum. Tr. 761:7-18. Mr. Standing Bear holds an associate of arts degree in art from Rogers State College. Tr. 760:6-13.
George Tall Chief (Tr. 34:8-43:9) served as Principal Chief of the Osage Tribe and as President of the Osage Nation from 1982 to 1990. Tr. 36:25-37:8. He earned a bachelor of arts degree in education from Central State University in Edmond, Oklahoma and a master's degree in public school administration from Pacific University in Oregon. Tr. 35:14-18. Currently retired, Mr. Tall Chief’s career comprised public education, specifically sports coach, history teacher, principal, and superintendent. Tr. 35:21-36:21.
Toby Van Big Horse (Tr. 689:16-726:15) began working for the Osage Agency in the mineral department in 1982 as a gauger, officially known as a petroleum engineering technician. Tr. 690:13-23. In 1985, he became a field representative, a title that was classified under "petroleum engineering technician." Tr. 693:17-22. Mr. Big Horse was promoted to the engineering section in 1997, a position that he held until 2005. Tr. 694:24-25; 695:7-8. He is now employed by the "Osage Nation[J working in the Osage language preservation department.” Tr. 690:5-6.

. Rule 30(b)(6) witnesses are designated by a party or non-party organization (public or private corporation, partnership, association, or governmental agency) following notice and subpoena of that organization to testify "as to matters known or reasonably available to the organization.” Rules of the Court of Federal Claims (RCFC) 30(b)(6) (2006).

. The Bureau of Indian Affairs (BIA) established a comprehensive regulatory framework unique to the Osage Reservation for the management of Osage oil and gas leasing, commonly referred to as the Osage Regulations. During the periods covered by Tranche One, the Osage Regulations were codified initially under § 183 of Title 25 of the Code of Federal Regulations (C.F.R.) and redesignated in 1982 as § 226 of the same title. Changes to the wording of specific regulations identified by the parties at trial and in their respective briefs were made in 1974, see 39 Fed. Reg. 22,254 (June 17, 1974), 1990; 55 Fed.Reg. 33,112 (Aug. 14, 1990), and in 1994, see 59 Fed.Reg. 22,104 (April 28, 1994). Unless otherwise specified, references to the Osage Regulations will use the current designation of 25 C.F.R. § 226, with a parenthetical providing the year the regulation went into effect (1974, 1990, or 1994), where relevant.
The United States has also established regulations governing oil and gas leasing of other Indian lands it holds in trust. See, e.g., 25 C.F.R. Part 211: Leasing of Tribal Lands for Mineral *636Development; 25 C.F.R. Part 213: Leasing of Restricted Lands of Members of Five Civilized Tribes, Oklahoma, for Mining; 25 C.F.R. Part 227; Leasing of Certain Lands in Wind River Indian Reservation, Wyoming, for Oil and Gas Mining; see also Indian Mineral Leasing Act, ch. 198, 52 Stat. 347, (May 11, 1938) (exempting, by section 6, the Osage Reservation in Oklahoma from all sections but allowing, by section 5, delegation of the Secretary’s authority to approve oil, gas and other mining leases to superintendents or other Indian Service officials).

. Leases are issued under authority of section 3 of the 1906 Act, 34 Stat. 543-44, and are subject to the current regulations at the time they are issued, see 25 C.F.R. § 226.5, and to all regulations thereafter enacted that do not "affect the term of the lease, rate of royalty, rental, or acreage unless agreed to by both parties and approved by the Superintendent.” Id. Oil and gas leases must also be in a form prescribed by the Secretary of the Department of the Interior. 25 C.F.R. § 226.7.

. A division order is a contract for the sale of oil between the purchaser and parties who own oil production interests. It establishes the proportions of interest and division of proceeds from the oil well among the existing owners and the prospective purchasers. Division orders generally do not change the terms of the lease and are terminable at will by either party. Howard R. Williams & Charles J. Meyers, Manual of Oil and Gas Terms 302 (12th ed. 2003) (Williams & Myers).

. The Mid-Continent oil field is a broad area encompassing hundreds of oil fields and deposits discovered in the late 1890s and early part of the twentieth century, initially in parts of eastern Kansas, Oklahoma (including the Bartlesville and Burbank fields on the Osage Reservation), and central Texas, and eventually including parts of Arkansas, New Mexico and Louisiana. See id. at 658.

. The court understands “Mcf" to mean one thousand cubic feet. See Williams & Meyers 650.

. The regulations organized under Part 183 of Title 25 of the Code of Federal Regulations were re-designated as § 226 in 1982 as part of a realignment of subject areas in Chapter I of Title 25 without any substantive change in the individual regulations. See 47 Fed.Reg. 13,326 (Mar. 30, 1982); see also supra n. 8.

. In contrast to the rapid increase in crude oil prices that was taking place as the 1974 Regulations were being formulated, by 1987, when the 1990 Regulations that became the rule changes were proposed, oil prices were in free-fall. Defendant's witness Charles Hurlburt testified that "roughly from 1983 to 1986 ..., the oil price was fairly constant, somewhere between $25 and $30 per barrel.... In '87 or in late '86 perhaps the price began to fall and was very volatile for a few years. It fell all the way down to about $9 or $10 per barrel.” Tr. 1055:7-16.

. The numbering of the proposed and final rule notices differed from the numbering in the codification. The proposed and final rule published in the Federal Register as § 226.12(a)(2) was codified at 25 C.F.R. § 226.11(a)(2) (emphasis added). See 52 Fed.Reg. 38,608, 33,609; 55 Fed.Reg. 33,112, 33,113.

. The "ordinarily understood meaning” of offered price was made clear by the BIA in 1994 when it stated that the purpose of the removal of the offered price term from the royalty value formula in the amendment of 25 C.F.R. § 226.11(a)(2) was “to eliminate premium, bonus, or other like payments from consideration in the calculation of the royalty price for crude oil in Osage County, Oklahoma." 59 Fed.Reg. 22,104 (emphasis added); see also Tr. 1059:1-13 (Hurlburt) (describing offered price as a bonus and explaining that under the royalty value calculation formula, "if a major purchaser offered a bonus to one lease or to a number of leases, it would have the same effect as if the major purchaser had published a higher price”).

. The "top 80 percent" of purchasers refers to the definition of major purchasers under the 1974 Regulations: a major purchaser was "any one of the minimum number of purchasers taking 80 percent of the oil in the Kansas-Oklahoma area." 25 C.F.R. § 226.1(h) (1986).

. Plaintiff also proposed the use of prices paid for the sale of crude oil at the Cushing, Oklahoma spot market price. Tr. 109:21-110:7 (Reineke); PX751-0016 ¶ 48 (Reineke Expert Report). Cushing is the center for a number of pipelines bringing oil from Texas and Oklahoma. Tr. 1409:12-18 (Martin). Use of the Cushing price for crude oil would be problematic because it combined oil from areas outside the Kansas-Oklahoma area, Tr. 1409:15-16 (Martin), and included cost adjustments attributable to transportation and location. Tr. 1409:24-1410:14 (Martin).

. Plaintiff presented testimony from persons who had participated in burning certain Osage Agency documents and papers that had been removed from storage, see Tr. 704:18-724:18 (Big Horse), or had observed the charred remains of documents following the burning, Tr. 729:21-757:14 (Mattingly). Toby Van Big Horse testified that at some time during the late 1980s to early 1990s he, along with other Osage Agency employees, removed boxes of materials from Osage Agency storage, some of which were burned, Tr. 705:2-706:25, and others moved to archives elsewhere in the United States, Tr. 710:3^-15. Mr. Big Horse identified some of the burned documents as "run tickets and other miscellaneous paper,” Tr. 706:7-8, but could not recall the date of the documents in question, Tr. 707:4-6 (stating dates were possibly in the 1980s and before); Tr. 713:6-7 (stating documents may have been from 1950s and 1960s). A run ticket is a record made by a gauger upon taking delivery of oil from an oil tank and includes physical characteristics such as temperature and BS & W level (basic sediments and water), as well as the top and bottom levels of oil in the tank, corresponding to measurements made prior to and following removal of oil by the purchaser's agent. Tr. 696:11-699:24 (Big Horse).
Stanley Ann Mattingly testified that she had received a phone call alerting her to the alleged burning of run tickets, Tr. 731:12-13, and that she subsequently recovered charred document fragments from a barbecue pit with a spatula which she then took to her home, Tr. 737:9-21. Ms. Mattingly testified that she had been told that the charred pieces of paper were run tickets, Tr. 739:11-17, but also acknowledged on cross-examination that she did not have personal knowledge of the types of documents that were in the barbecue pit, Tr. 750:4-6.
Plaintiff also presented testimony of alleged document shredding at the Osage Agency in 1994. Tr. 763:1-772:25 (Standing Bear). Eugene Shawn Standing Bear testified to finding historical documents, including "council minutes, tribal resolutions, accounting ledgers regarding oil production and payments,” Tr. 792:1^4, on shelves near a shredding machine as well as a number of bags of shredded paper, Tr. 770:11-20, 772:17-20. Mr. Standing Bear identified one document as a council resolution or council minutes dated 1906. Tr. 773:17-774:1. Plaintiff has not alleged that defendant had a duty to preserve the documents that were allegedly destroyed, nor that defendant breached such a duty by destroying the documents. See Columbia First Bank, FSB v. United States, 54 Fed.Cl. 693, 702-03 (2002) (noting that the elements of a spoliation claim include evidence that (1) there was a duty to preserve the lost evidence; (2) evidence was lost due to a culpable breach of that duty; and (3) the non-breaching party was prejudiced by the loss of the evidence).
Plaintiff argues that "the fact that the Osage Agency was destroying so many historically valuable documents without checking with the tribe about it displays basically a careless attitude towards record keeping, and we think their attitude and practice with respect to the records that they kept is relevant to the case.” Tr. 782:7-12 (Plaintiff’s Counsel); see also Pl.'s Br. 45 (arguing that despite the unavailability of pertinent documents, plaintiff "has made a good-faith effort to estimate its damages” and that "the Osage Nation is entitled to an inference that at least some of the relevant documents may have been destroyed”). Plaintiff did not establish that any of the records allegedly destroyed were germane to the Tranche One period, nor did plaintiff provide any evidence that the United States acted in bad faith in destroying evidence. See Columbia First Bank, FSB, 54 Fed.Cl. at 703 (finding that "there must be a showing of bad faith before [the breaching party] can be sanctioned under the spoliation doctrine for the loss of ... documents”). The court concludes that plaintiff's allegations and the evidence presented at trial do not support a spoilation claim. See Columbia First Bank, FSB v. United States, 58 Fed.Cl. 54, 56 (2003) (denying motion to sanction for spoliation of evidence because of failure to show bad faith, which is "an essential element of the spoliation doctrine that must be present for an adverse inference to be drawn”).

. See Thorman & Hibpshman 8. The 1979 BIA report estimates that "[t]otal cumulative oil pro*657duction from fields within Osage County between October 1897 and January 1977 was slightly in excess of 1.26 billion bbl____Altogether, about 34,000 wells have been drilled in Osage County, and about 10,000 still are producing.” Id.

. Rowena Beach was employed at the Muskogee Area Office as an office automation clerk from 1974-1977 and was deposed as a 30(b)(6) witness. Beach Dep. 6:10-7:1.

. The Price Waterhouse report is also cited as a source document for Mr. Lundelius's November 3, 2005 Expert Report. See DX1668-0035.

. The 1906 Act provides for quarterly payments of interest and royalty income to be made on a pro rata basis to the enrolled members of the Osage Tribe. 1906 Act § 4. Section one of the 1906 Act detailed the procedure for enrollment as a legal member of the Tribe. 1906 Act § 1. Legal membership and the accompanying right to participate in the quarterly distribution of Osage funds is also known as a headright, with the holder of a headright referred to as an annuitant or shareholder. Tr. 718:16-20 (Big Horse); Tr. 2357:2-10 (Currey).

. As this court found in Chippewa Cree Tribe of the Rocky Boy's Reservation v. United States, 69 Fed.Cl. 639 (2006), legislation enacted by Congress over the past century has consistently required the United States to increase the productivity of funds it holds in trust for Indian tribes.
The history of investment-related legislation indicates a congressional commitment to increasing the productivity of Indian funds held in trust by the government. For trust funds held in Treasury accounts, Congress began by authorizing the deposit of trust funds in interest-bearing Treasury accounts (the 1880 enactment of 25 U.S.C. § 161 allowing interest to be paid on Treasury deposits), then mandated that all Indian trust funds held in Treasury accounts receive a floor interest rate of 4% unless otherwise provided by treaty or statute (the 1929 passage of § 161a making the payment of interest mandatory), and finally provided for variable interest rates that reflected current market yields for Indian trust funds held in Treasury accounts (the 1984 revision of § 161a(a) providing for the payment of variable interest rates on trust funds). Prior to 1880, Congress had also provided for the placement of trust funds in investments other than interest-bearing Treasury accounts that allowed the funds to attract more favorable market rates, but the risks involved led to the enactment of 25 U.S.C. § 161. Yet the importance of seeking higher market-based yields prompted further legislation (the 1918 enactment of 25 U.S.C. § 162) that allowed for the investment of Indian trust funds outside of the Treasury in banks that offered adequate security, and even further legislation (the 1938 repeal of § 162 and replacement with § 162(a)) that permitted the use of "unconditionally guaranteed” investment vehicles including notes, bonds and other obligations.
69 Fed.Cl. at 659.

. Defendant argues in its post-trial brief that "[pllaintiff presented no evidence at trial addressing the prudence of BIA's investment practices. In the absence of any testimony on the subject, [pllaintiff utterly failed to meet its burden of proof on this issue.” Def.'s Br. 43. Plaintiff counters that in its analysis and presentation at trial, it had adopted defendant's definition of prudent investment and demonstrated defendant’s failure to meet its own stated standard. PL's Resp. at 15-16 (noting that it was "uncontested at trial that Lundelius's 80/20 rate was an appropriate standard,” and that it was "introduced into evidence during [plaintiff's expert’s] testimony and ... in [the expert] report, both of which were sponsored by plaintiff” (citation omitted)). The court agrees with plaintiff that by adopting defendant's standard and producing evidence that brings into question its successful attainment, plaintiff has met its burden of production. See id. at 16 (quoting 32A C.J.S. Evidence § 1343, to the effect that "the weight and sufficiency of one party's evidence may generally be aided by evidence introduced by the adverse party").

. Defendant argues that "a prudent investor might not always reach an expected rate of return.” Def.’s Resp. at 14 (citing Tr. 2222:23-2223:15 (Lundelius)). Mr. Lundelius asserted that ”[i]t is certainly possible, and indeed, very probable, that a trustee will underperform an expected rate of return in a given year____That would include very famous investment managers like Peter Lynch of the Fidelity Magellan Fund or Warren Buffet of Berkshire Hathaway. No one makes a consistent rate of return that always beats a relevant index.” Tr. 2223:1-10 (Lundelius). Unlike the market-imposed "relevant index" against which the performance of these private sector investors is evaluated, here, defendant selected "an expected rate that a prudent investor could have achieved ... under the constraints imposed by the duties of care and caution.” Def.’s Br. 47. As plaintiff observes, "An expected rate consisting of CDs and T-bills is a very low threshold of prudence” and "[Qailure to achieve such a rate ... is especially probative in this case given that the prudent investments were specified by statute and were risk-free.” Pl.’s Resp. 16. The court agrees. Mitchell, 664 F.2d at 274 (finding that because ”[t]he bank deposits are subject to rigid statutory precautions to assure complete safety[,] ... defendant must as trustee exercise reasonable management zeal to get for the Indians the best rate, the statutory 4% being but a floor, not a ceiling”).

. Plaintiff justifies its reliance on data from the Arthur Andersen report on the ground that "the BIA’s accounting system for tribal trust funds has been in disarray for many years____Thus, deficiencies and gaps endemic to BIA’s accounting system prevent the kind of lease-by-lease, deposit-by-deposit analysis that would allow the Osage Nation as beneficiary to hold the United States accountable for the particulars of its investments in Tranche One.” Pl.'s Br. 33-34 (citations omitted); see also Tr. 472:7-17(Jay) (stating same as expert opinion); Tr. 491:13-498:19(Jay) (identifying various reports critical of BIA accounting procedures).

. Plaintiff also notes, "Before 1978, BIA’s accounting system did not even distinguish investment income form other types of income.” Pl.’s Br. 38 n. 16 (citing PX476-0004).