- Updated Periodically - Contact: Richard A. Fineberg

(Archived Sep 5, 2006)

Comment: Legislature Should Slow Down

Misleading Oil Data Mask Importance
Of Pipeline Tariffs, Income Tax Calculations

April 30, 2006

(Rev. May 10, 2006)

"That's the point at which BP makes zero profit," Angus Walker, Vice President for Commercial Operations, BP Alaska, told the Alaska State Senate Resources Committee April 10 as he handed legislators a chart labeled "Breakeven Barrel $22.50." The BP executive was responding to this question: Why does BP's analysis show a loss, while the Alaska Department of Revenue (ADOR) shows that BP still makes money at prices below $20 per barrel? But BP's simplified chart purporting to show how the revenue from a barrel of oil is divided was highly misleading.

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BP's so-called "Breakeven Barrel" which masquerades  more than $5.00 per barrel in profits.(Where BP shows "zero" profit at $22.50 per barrel, a more accurate estimate at that price would exceed $5.00 per barrel. At BP's 2005 North Slope production rate of 110 million barrels per day on the North Slope, the difference in estimates adds up to about $550 million in after-tax profits for BP. Although ADOR data provide a much fairer representation of the oil industry's Alaska operations than BP's, the agency's information does not constitute a satisfactory basis for analysis, either. After more than three months of intensive deliberations on oil tax issues in the state capital, discrepancies in fundamental benchmark data are surprising.

The average price of Alaska North Slope crude oil in 2005 year was approximately $54.00 per barrel - more than $30.00 per barrel higher than BP's misleading "breakeven barrel" analysis. But experts have been consistent in warning the Legislature that the state must be concerned about the risk of lower prices. And it is at low prices that the deficiencies in the BP and ADOR analyses of North Slope operations assume increasing importance. For these reasons, the question that legislators posed for the BP officials deserves a closer look.

Although BP presented this chart to demonstrate that "[i]t is only at prices above $22.50 that BP starts to make profit," it takes some very creative accounting to support the claim that BP did not make money on this barrel of oil.

On cursory inspection, these aspects of BP's depiction of its breakeven point raise questions:

  • If there was no profit on a barrel of oil that sold for $22.50, why would BP have to pay $1.32 per barrel in state and federal income taxes?
  • When state income taxes are typically estimated to be one-quarter of federal income taxes, why did BP's typical barrel show state income tax nearly twice that of the federal income tax?
  • Why did BP show royalty payments of $3.39 - an amount 70% higher than the average royalty rate? (Royalty is calculated as one-eighth of wellhead value, or the market price less transportation; with transportation at roughly $6.50 per barrel, the wellhead price would be $16.00/bbl.; one-eighth of $16.00 is $2.00.)

Shortly after BP submitted its misleading information to the Legislature, a reporter in Juneau asked about the income tax and royalty anomalies, but it took BP nearly two weeks to offer a response. On April 24, BP offered this explanation for the tax and royalty figures in its April 10 chart:

  • At least a portion of the federal income tax, BP said, was for gains due to accounting machinations that had produced profits in prior years on which the income tax payment had been legally deferred. In other words, at least a portion of the federal income tax payment represented a long-term, interest-free loan from the federal government on prior production gains.
  • Regarding its reported royalty payments, BP acknowledged that at least part of the answer was that its slide showed net profit share payments as royalty.

BP's belated admissions confirmed that its so-called "breakeven barrel" presented a misleading picture. Both the royalty and tax accounting mechanisms indicated that BP earned a profit at a price of $22.50; if not, then why were royalties and taxes being collected? But BP obscured those profits by tucking them away in the $15.68 per barrel that BP labeled midstream and upstream cash and capital costs. BP's obliquely worded, general explanations for its listed government payments call for closer consideration of the costs that BP claims ate up all profits from a barrel of oil at $22.50 per barrel.

  • How much of the midstream and upstream capital costs of $5.74 per barrel represent depreciation payments, or cash flow that BP actually retains?
  • Are there other elements of the midstream and up stream cash costs, listed as $9.94, that actually produced net revenue for BP?

Pipeline Tariffs: Hidden Consequences

BP's misleading presentation obscures a fundamental issue that has been overlooked in the state capital: excessive tariffs (shipping charges) on the Trans-Alaska Pipeline System (TAPS). In terms of the so-called "breakeven barrel," the pipeline issue divides into two questions:

  • What portion of BP's listed midstream and upstream cash and capital costs are actually pipeline profits, allowed by regulators, that BP charges itself and retains?
  • What portion of those cash costs are actually charges that the Regulatory Commission of Alaska has found to be excessive and therefore should be reckoned as income, rather than outlays?

One key to understanding TAPS issues is that the pipeline's major owners - BP (47.0%), ConocoPhillips (28.3%) and ExxonMobil (20.3%) also control approximately 95% of North Slope production. These unusual and potentially anti-competitive conditions warrant careful attention. The failure of the state's tax-focused models to identify the consequences of regulated TAPS tariff profits for prospective developers that do not own an interest in TAPS are discussed in an April 23 report by this writer. The report identifies regulated or allowed pipeline profits estimated at $1.10 per barrel. This amount represents a regulated, guaranteed profit element that provides the pipeline owners a cushion at low oil prices but penalizes the independent shipper, who must pay that element out of pocket, at a similar level. As the report notes, the failure to address pipeline overcharges will undermine one of the major goals of the overhaul of the proposed petroleum production tax: to encourage new developers to the North Slope.

In fact, regulated pipeline tariffs are only one part of the pipeline tariff story. As noted in the author's April 23 report, the Regulatory Commission of Alaska (RCA), which has authority to set tariffs for the small portion of oil shipped to in-state refiners via TAPS, ordered the pipeline owners to reduce tariffs under its jurisdiction to $1.96 per barrel. (1) For the preponderance of the oil shipped on TAPS, the 2006 tariff averages $3.98 per barrel. Assuming that the $1.96 tariff mandated by RCA includes a just and reasonable profit of ten percent, actual costs for a barrel of oil shipped on TAPS in 2006 would be approximately $1.76 per barrel. By this reckoning, the current TAPS tariff brings its owners an estimated profit of $2.22, consisting of $0.20 in just and reasonable profits and an additional $2.02 in excess charges allowed by the FERC, as shown in Worksheet 1.

When differential state and federal payment to the state are reckoned, independent shippers pay $3.68 per barrel out-of-pocket on TAPS shipments at the FERC tariff, while the TAPS owners retains $0.20 per barrel shipping at the same tariff. Compared to the TAPS owners, the independent shippers are handicapped by the sum of these amounts, or $3.88 per barrel, as shown in Worksheet 2. (Data revised May 10, 2006; see worksheet.)

As discussed in the writer's April 23 report, the effects of the TAPS tariff on independent shippers are obscured by the state's short-term Revenue Share Model. The state's long-term model - following that of Dr. Van Meurs - sweeps TAPS profits off the table altogether. Failure to consider TAPS tariff issues leaves this significant handicap to independent developers in place. Since TAPS tariffs continue to be the subject of controversy in regulatory and court proceedings, as well as state-industry renegotiations, failure to deal with TAPS tariff issues now creates precisely the uncertainty that state and industry representatives say they wish to minimize.

Low Oil Prices and the Perils of Prophecy

TAPS tariff issues are something of a mine canary, warning of potential dangers in dark, unexplored territory. One of those dangers is low oil prices. As consultants to the Legislature and the administration have repeatedly warned, oil prices have an demonstrated capacity to reverse themselves, confounding and humbling all parties arrogant or short-sighted enough to think they know what the future holds. Thus, in looking at the Senate's tax credits, Dr. Pedro Van Meurs has warned that the state should consider the very real possibility that relatively low oil prices could hit and hold for a two to three year period. Legislative consultants Daniel Johnston and the EconOne group have issued similar cautions.

Pipeline tariff effects are relatively insensitive to oil prices. For this reason, TAPS tariff effects assume increasing importance at low prices. Whatever BP's breakeven price might be, failure to consider TAPS tariffs hides a cushion that lowers BP's breakeven point by $1.97 (as calculated in Worksheet 2). But the independent shipper goes underwater at a price $5.64 higher than BP. While prices are high now, if low-price risk isn't important, why all the focus on tax credits and deductions?

The experience of Conoco demonstrates that although pipeline tariff consequences may be tricky to model, this is not an academic exercise. In 1987 (long before its merger with Phillips) Conoco developed and operated the Milne Point field to become the first and only company other than a major TAPS owner to operate a North Slope field. But in 1993, during a period of low prices, Conoco traded Milne Point to BP and left the state. Later, Archie Dunham, then President and CEO of Conoco, said: "It broke my heart to trade Milne Point, but we had to do it. All the value of that property was taken away from us in the pipeline tariffs. It was a valuable strategic lesson - just look at why the producers in the Caspian Sea are so worried." (2) The author's 1998 report on North Slope profitability indicated that in 1993 Conoco was in the red by an amount roughly equal to the profit elements on TAPS. In 1999, during deliberations over the ARCO-BP merger, Dunham told reporters he wouldn't come back to Alaska without a share of TAPS. And, in fact, after Conoco merged with Phillips, the combined company subsequently increased the stake in TAPS Phillips acquired when the Federal Trade Commission required BP to divest its ARCO Alaska properties as a condition of that merger.)

Income tax effects also assume increasing importance at low oil prices. As demonstrated in the author's April 23 report, administration models fail to deal with this important problem, compounding the failure to depict accurately what happens at low oil prices.

Although the industry has launched an advertising campaign blaming the state's consultants for being tax-happy, to the extent that they depend on administration models that fail to model fiscal results at low oil prices accurately, the state consultants have understated the effects of low oil prices on potential developers - and on state's share of net revenue.

The Perils of Litigation

If future oil prices are difficult to predict, the future of litigation over oil revenue is not. The history of litigation over petroleum revenue in Alaska clearly demonstrates that unless legislation related to the petroleum fiscal regime is precisely crafted, industry lawyers and accountants will have a field day looking for unanticipated loopholes and finding ways to expand them. As they engage in this process, one can be equally certain that they will attempt to blame bureaucrats for the myriad accounting problems they are so well paid - and obligated to their company shareholders - to create and exploit.

In 2003, this writer summed up Alaska's petroleum litigation experience in this way:

. . . . Over the past 25 years, more than one dollar out of every six that Alaska has received from North Slope oil development has been obtained through legal challenges to the industry's original payment. These challenges typically involved disputes over industry reporting of the value of the oil produced and/or the cost of producing that oil and transporting it to distant markets. The importance of these arcane conflicts to the Alaskan commonweal is made evident by this fact: During the 1990s, the fruits of the disputes over industry payment practices became the funding mechanism for Alaska's multibillion-dollar Constitutional Budget Reserve Fund.
. . . . Alaska has found it necessary to pursue a path of prolonged and intensive litigation in order to obtain what public officials consider a fair share of the take from petroleum development. Essentially, the State of Alaska found that the industry chronically reduced the bases for calculating royalty, severance, and income tax payments by understating the market value of a barrel of oil at the point of sale. Overstated pipeline shipping charges (tariffs) had the same result. The disputes often turned on differences between the state and industry regarding interpretations of contractual, statutory or regulatory language; many could be chalked up to legitimate differences of opinion, but others could not. . . . .
These cases were argued in different institutional forums. Royalty disputes proceeded directly from agency audits to the Superior Court of the State of Alaska's court system; tax settlements resulted from audit findings preliminary to proceedings before an administrative hearing officer of the Alaska Department of Revenue; pipeline tariff issues were handled by the Federal Energy Regulatory Commission (FERC) or the Regulatory Commission of Alaska (RCA, or its predecessors). It was not unusual for the same issue-and even the same set of facts-to be argued separately by different agencies, in different venues, and with different results. In sum, the cases were complicated-and, consequently, costly-to research, brief, and present.

Richard A. Fineberg, in Caspian Oil Windfalls: Who Will Benefit?,
Ch. 3 (2003; footnotes omitted)

A doctoral thesis on Alaska's 15-year royalty litigation, based on court records and approved by the Washington State University Department of History in August 2005, came to a similar conclusion. Although he decried the fact that was denied access to confidential documents that remain under seal years after termination of the case, William R. Johnson managed to locate court records in Juneau that enabled him to piece together this tortuous case history. Working his way through endless boxes of court documents, he was able to describe the machinations through which the industry attempted to evade its royalty obligations through creative interpretations of convoluted legal provisions. He summarized the case as follows:

At first, the issue appeared to be a simple disagreement over the computation method, but Alaska subsequently expanded the charges to include fraud. Eventually, after fifteen years, all the companies settled with Alaska out-of-coiurt, and the state collected roughly $600 million (unadjusted for inflation), or two thirds of its original claim. . . .
Simply stated, the oil companies mastered the ability to manipulate their books to create artificially low profits. This amounted to fraud, to the tune of hundreds of millions of dollars. Their actions were a calculated gamble with minimal risk and three possible outcomes. First and best for the corporations was the possibility that they would not get caught. Second, if they got caught and were forced to pay they at least would have stalled the process, thereby reaping interest on their money during the delay. Finally, there was the chance that if caught they might be able to spend enough money over litigation to make the battle too expensive for the state. In doing so, they hoped to force a settlement for a lesser amount than rightfully owed.

- William R. Johnson, Jr., Alaska v. Amerada Hess: Alaska Litigates
for Oil Royalties, 1977-1992
(unpublished doctoral dissertation),
Washington State University, 2005, pp. 244-245.

For litigation, the TAPS experience once again serves as the mine canary. The tariff problems discussed in this article result from a 1985 settlement between the state and the TAPS owners that was supposed to end eight years of expensive and time consuming litigation over TAPS tariffs. Legislative review of the 1985 TAPS tariff settlement failed to alter what many thought at the time to be the Department of Law's misguided course on behalf of the administration. In 1990, after leaving the administration, this writer prepared a report for state House leadership on the manner in which confidentiality crippled effective review of the settlement steamroller. Two facts from that report stand out:

The major piece of information on the settlement available to legislators and Executive Branch policy-makers prior to settlement was an undated memorandum from the Dept. of Law, "Summary of Proposed TAPS Settlement." This 40-page memorandum (27 pages of text followed by 13 pages of tables and graphs) contained a 5-page, single-spaced summary and was labeled, "Confidential-Advice of Counsel." This key document:

  • underplayed and obscured the potential refunds at issue;
  • emphasized sthe difficulty of collecting refunds; and
  • failed to mention a unanimous 1978 U.S. Supreme Court decision that established the right of shippers - and, presumably, the State - to collect any refunds due from the TAPS litigation.

The same report recounted and documented that the briefing on which the governor made his final decision approving the final TAPS settlement in October 1985 incorrectly reduced the potential revenue from a litigation victory and increased settlement gains. Due to these mistakes, continued litigation seemed far less attractive an option than it really was. What happened when the error was discovered is even more surprising: Administration personnel issued a call for the return of all copies of the erroneous document and destroyed them; an altered, public version was released several weeks later that omitted critical sections and corrected the erroneous data on which the governor had been briefed. Officials of both the Departments of Law and Revenue later denied that the public version of the document was changed from the erroneous confidential document (see: The 1985 TAPS Settlement, p. 31 and Appendix 3).

Two decades later, it is hard to know what to make of these highly irregular occurrences. But the consequences of the faulty public policy deliberations are clear: As indicated by the court-upheld RCA orders on TAPS, the 1985 TAPS settlement set up a tariff regime that runs counter to the rational goals of public policy in important respects. And buried within that settlement lies a DR&R provision that was portrayed as revenue neutral, when it in fact functions to deliver significant gains to the TAPS owners. Hundreds of millions of dollars in revenue and countless hours of administrative energy spent or saved ride on the skill with which the Legislature resolves its decisions regarding the myriad details that make up the petroleum fiscal regime.

Former Revenue Department official and contract oil litigator John Messenger, now under contract to the House minority, has suggested that, instead of establishing a new tax regime that is liable to provoke extended litigation, the state should fix the broken severance tax, whose nuances are already familiar to administrators. Messenger joins a phalanx of knowledgeable former state officials who warn that the proposed shift from a value-based production tax to a net-profits-based tax creates a framework that is a sinecure for attorneys and accountants.

Devilish Details

Buried in the 1985 TAPS tariff settlement was an obscure provision that serves as an example of the kind of details that can have inordinate significance. Called "DR&R" (for dismantlement, removal and restoration), this provision of the negotiated 1985 settlement enabled the TAPS owners to pre-collect future abandonment costs from shippers through the tariff. Although portrayed as revenue neutral, the TAPS settlement provision required shippers to pay these future costs through the tariff on an accelerated schedule. Consequently, the TAPS settlement DR&R terms gave the owners free, tax-paid cash, creating a windfall for the TAPS owners that will grow to an excess of billions of dollars over the amount necessary to perform dismantling when the time comes. At the same time, this provision reduced state royalty and tax revenue and further handicapping potential competitors to the TAPS owners. (See the author's 2004 report on TAPS dismantling charges). (3)

Reporting of liabilities for future expenditures like DR&R falls into what is known in accounting circles as a gray area - an area where practices are not clear cut, allowing creative tax attorneys and accountants room to maneuver to attain the best possible results for their shareholders. Under the standard business procedures, cost write-offs are typically based on actual expenditures and tax deductions are taken when the expense is incurred. But this convention does not work well for anticipated future outlays such as abandonment. In this gray area, the TAPS owners tried to replicate their TAPS gains on the North Slope when Exxon attempted to take an advanced abandonment deduction at Prudhoe Bay for the 1977-82 period under an IRS provision known as the "all events test." That this deduction was terminated in 1984 and was designed for different circumstances did not deter Exxon from litigating; the potential deductions for the pre-1984 were well worth the price of litigation, particularly when a victory for Exxon in Tax Court might have established a precedent for future years. But the issue was decided against the Exxon in May 2000, when the United States Tax Court ruled, in essence, that oil companies could not take an advance deduction for future abandonment because the date and the required amounts could not be determined. In 2003, the Financial Accounting Standards Board promulgated new requirements for the treatment of long-lived assets, including abandonment liabilities. (4)

The history of dismantling issues on TAPS and on the North Slope - and the potential negative consequences for the state and independent developers - suggests that pre-collection of money for future dismantling is a subject that requires careful attention to detail. Instead, the Senate Finance Committee added a provision to the proposed petroleum production tax April 22 that would allow producers to take deductions for future abandonment expenditures. There was little discussion, leading one to wonder whether tax accountants and attorneys had reviewed the proposal to ensure that the new abandonment provision would not be used -- as adroit industry representatives had used the abandonment terms they negotiated in the 1985 TAPS settlement -- to reduce state tax liabilities and charge independent developers a high price in the process.

At the same time, the Senate, ignoring the lessons of the 15-year royalty litigation battles, has rejected safety provision that would permit the state to conduct audits of transfer pricing following Internal Revenue Code guidelines. (On the other hand, a measure that would require owners of a regulated facility receiving tax credits to report those credits and support the application of those credits to rate calculations was adopted on the Senate Floor after being rejected by the Senate Finance Committee.)


From the outset, several aspects of the proceedings to overhaul the state's petroleum fiscal regime did not make sense. For example:

  • The governor insisted that the oil and gas tax regime must be restructured and agreed to before the proposed contract on Prudhoe Bay natural gas pipeline negotiated between the administration and the major North Slope producers is unveiled. Under these strange circumstances, legislators can only guess how their actions will affect one of the most important operations the new legislation will govern.
  • While legislators initially said their actions on the PPT would apply only to oil, the bill now appears to cover both oil and gas.
  • In tendering its proposal, the administration warned that changes to its tax proposal could scuttle the still-unseen natural gas contract agreement. When did the executive branch of government take over the Legislature's functions?
  • The administration supported a "no changes" guarantee that is supposed to prevent changes to the fiscal regime overhaul for 30 years. But the world-savvy consultants who have been retained advise that governments around the world are changing their terms to deal with high oil prices - and that it is not necessary to offer a three-decade guarantee on those changes. The fact that the severance tax has required revision twice in less than three decades suggests that more frequent revisions to the petroleum fiscal regime are liable to be necessary in the future.

In setting up this framework, the governor appeared to be dictating terms to the Legislature on behalf of the petroleum industry. Despite the governor's wishes, there is no compelling reason for the Legislature to complete its work on oil taxes in advance of reviewing natural gas contract.

Under these strange circumstances, the Legislature has labored long and hard to educate itself about the petroleum fiscal regime. That effort reflects recognition of the importance of petroleum development to Alaska's future, and that Alaska's petroleum resources belong to the public and should be developed in the public interest for the maximum benefit of its people. (5)
Early in March, Daniel Johnston, one of the international experts retained by the Legislature for this purpose, laid out four basic goals for the overhaul of the state petroleum fiscal regime. That system, Johnston said:

  • Must be progressive;
  • Must achieve a fair division of profits;
  • Must contain no unhealthy disincentives to development; and
  • Hopefully will be simple and transparent. (6)
The governor's proposal fails to meet any of these four standards. By adding a progressive surcharge to the proposed PPT, the Legislature has attained one. The measure of progressiveness added by the Legislature, the flagship product of its extensive review efforts, is a step in the right direction. Nevertheless, attainment of the goals outlined by Johnston are undercut by the following shortcomings in the legislative product discussed in this review:
  • The models tendered by the administration do not provide a meaningful, comprehensive basis for assessment of the division of net revenue, particularly at low oil prices. For this reason, it cannot be ascertained whether the proposed legislation ensures a fair division of net revenue.
  • The Legislature's failure to deal with pipeline tariff overcharges leaves in place at least one strong disincentive to development.
  • The proposed legislation, which was introduced with 22 pages of technical language and now contains 33, is anything but transparent.

In October 2005, the Department of Natural Resources commissioner was sacked and six top staffers resigned when the commissioner questioned r the course of direction chosen by the governor. (7) Other knowledgeable former administrative officials have joined them in warning that the switch to a profits-based tax sets the stage for cost accounting arguments that could set off a new round of expensive and time-consuming petroleum litigation. With the clock running down on the governor's schedule and on the legislative session, the process of petroleum fiscal regime overhaul has come to an important crossroads. Instead of the customary bicameral wrangling over competing proposals, it is time for the Legislature to put on the brakes and consider its next steps carefully. To minimize the possibilities for unanticipated consequences, the Legislature should create a checklist of critical issues against which the proposed legislation can be evaluated. Legislation of this importance and complexity should not move forward until it has been evaluated against that list. Responsible stewards of Alaska's resources can do no less.


Endnotes to "Misleading Oil Revenue Data"

1. The Regulatory Commission of Alaska has re-affirmed its 2002 order twice (see: Regulatory Commission of Alaska, "Order Rejecting 2006 Intrastate TAPS Settlement Methodology Rates," Docket No. P-06-1[1], Dec. 16, 2005) and the State Superior Court has upheld the RCA's initial decision ("Decision and Order," Amerada Hess Pipeline Corporation, et al. [Appellants] vs. Regulatory Commission of Alaska [Appellee], Case No. 3AN-02-13511 CI, Jan. 18, 2006).

2. "Getting to the Future First," Hart's Oil & Gas Investor, August 1996, p. 41.

3. During public 1985 settlement reviews, the significance of DR&R pre-collections was obscured when the administration inappropriately lumped this allowance for future payments with depreciation - a much larger allowance for money already spent.

4. See: ExxonMobil v. Commissioner, 114 T.C. 293 (United States Tax Court, 2000) and Financial Accounting Standards Board, "Statement of Financial Accounting Standards No. 143: Accounting for Asset Retirement Oblligations" (June 2001 [Effective Date: June 15, 2002]).

5. Alaska State Constitution, Article VIII., Sec. 1.

6. Daniel Johnston, "Alaska's Proposed Production Tax ('PPT 20/20%,' SB 305/HB 488): Issues for Discussion and Further Research," presented to the Alaska State Senate Resources Committee, March 6, 2006 p. 9.

7. Sean Cockerham, Don Hunter and Paula Dobbyn, "Irwin's memo cost him his job - Housecleaning: Goivernor dismisses natural resources commissioner; 6 others resign," Anchorage Daily News, Oct. 28, 2005.


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