Pipelines and the Petroleum Revenue “Take:”  Alaska’s Experience and Implications for Kazakhstan


By Richard A. Fineberg


July 19, 2003  (Revised)



  It is widely recognized that Caspian Basin oil is land-locked and must bear the costs of transportation to tidewater in order to compete on the world market.  But the economic implications of this fact are not so widely recognized or well understood.[1]  Before most payments to the host government are calculated, transportation costs, such as pipeline shipping costs (tariffs), must be netted out.  Therefore, increases in transportation charges result in decreases to host government revenues.  While this general proposition is simple enough, the mechanics of its execution are typically hidden from public view and can be quite complicated. Pipeline terms can also serve to inhibit development by stifling competition through excessive tariffs, or by limiting access to the line and its associated facilities. 

To understand how transportation terms can reduce host government revenues and inhibit competition, this discussion will look at the experience of another remote province with a super-giant oil reservoir, the state of Alaska.[2]  The limited public information about the terms for transporting oil from Kazakhstan suggests that the public interest would be well served by understanding the effects of transportation economics on petroleum revenue, and by careful consideration and public review of the implementation of these important arrangements. 


Alaska’s Experience

Almost all of Alaska’s oil is produced on the continent’s northern edge, where the largest oil field in the United States was discovered in 1968.  Alaska’s North Slope entered production in 1977, peaked at 2.0 million barrels per day (bpd) in 1988 and produces approximately 1.0 million bpd of crude oil today.[3]  Oil produced at that remote outpost is shipped south across Alaska on the 800-mile Trans-Alaska Pipeline System (TAPS) to the ice-free port of Valdez, where most of the oil is loaded on tankers for shipment to the West Coast of the United States.  Approximately eight percent of the oil shipped on TAPS remains in Alaska for in-state refinery use.  Since inception, three major oil companies – British Petroleum, ConocoPhillips and ExxonMobil – have controlled more than 90 percent of North Slope production and a similar percentage of TAPS.[4]   Over the first 22 years of operation, it is estimated that North Slope production and TAPS earned profits an estimated $73.4 billion for investors.[5]  By comparison, the state of Alaska and the federal government received $97.6 billion dollars during the same period.[6] 

The Regulatory Commission of Alaska’s 2002 TAPS Decision.  Between 1977 and 1998, TAPS generated approximately $19.3 billion of the industry’s profits from North Slope production and pipeline operations approximately 26.3% of the industry’s total profits from Alaska’s North Slope.[7]   But this figure only hints at the economic importance of the pipeline.  In November 2002, the Regulatory Commission of Alaska (RCA), a quasi-independent state agency that regulates pipeline shipping charges for the small portion of TAPS oil destined for in-state markets,[8] issued an order summarizing the results of an extensive investigation of the tariffs on TAPS.  The 465-page decision found that the pipeline operators had been overcharging pipeline shippers by gross amounts since TAPS entered service.[9]  Data in the order indicate that, overall, TAPS tariff overcharges reduced state revenues by over $2.0 billion between 1977 and 1996.  For all practical purposes, that money is lost to public coffers.  But the RCA decision was far from academic.  The operational part of the RCA decision deals with more recent tariffs.  The commission concluded that in relation to costs, shipping charges on the pipeline in recent years have been, on average, 57 percent too high.  Therefore, the state commission ordered those tariffs reduced for the oil over which it exercises jurisdiction.[10] 


The primary reason pipelines are regulated is that they are a potential bottleneck that can be used to strangle competition, either by charging excessive rates or by limiting access.  For the TAPS owners, tariffs charges are internal transfer payments, typically made by the firm’s producing arm to its transportation unit. On the other hand, non-owners must pay shipping charges – including a profit allowance -- out of their own pockets.  Perhaps it is not surprising, therefore, that the RCA decision sent ripples through the Alaska oil and gas community.   The Division of Oil & Gas of the Alaska Department of Natural Resources (the state’s land manager) has estimated that reduced tariffs on TAPS – if applied line-wide – would increase state revenues by $110 million per year. At present, the TAPS Owners are pocketing the excess revenue they collect on TAPS.[11]   But assuring a fair share of the petroleum revenue “take” is just one of the important public policy reasons for seeking tariff reductions.  The second reason is this:  Excessive pipeline tariffs penalize prospective producers and inhibit the competition on which future oil development depends.  According to the director of the Oil and Gas Division, “[e]xcessive tariffs create a barrier to entry for all oil and gas companies not owning an interest in TAPS.”  In January 2003, a trade journal survey of 17 key industry participants and observers found that lower TAPS tariffs tied for first place as the top priority for 2003 (with streamlined permitting) and “one of the most important incentives the state could offer.”[12] In February 2003, the Alaska Permanent Fund Board of Trustees voted to investigate “all maintenance and operational practices, including tariff and facility pricing,” that could limit development of state oil leases.[13]    The TAPS owners have challenged the RCA ruling – and its jurisdiction – in the state legislature and in court.[14] 


Conoco’s Experience.  The importance of pipeline ownership is demonstrated by the experience of Conoco,[15] the former operator of the North Slope’s Milne Point field.  Conoco was the only company that has operated a field on the North Slope without a share of the super-giant Prudhoe Bay or TAPS.  During a period of relatively low oil prices in 1993, Conoco sold its North Slope interests to BP.  Analysis of North Slope production and pipeline revenue streams reveals that the guaranteed profits from TAPS ownership might have kept the operation afloat until oil prices rose again.[16] Later, reflecting on his company’s departure from Alaska, Conoco Chairman and CEO Archie Dunham 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.”[17]  By virtue of the mergers among major oil companies (see footnote 3, above), ConocoPhillips is now a major TAPS owner.  In addition to joining a vigorous defense of the TAPS tariff in a court challenge to the recent RCA decision,[18] ConocoPhillips has proposed legislation to limit the authority of the RCA.[19]


The Devil Is in the Details.  The RCA decision also served notice that the commission intends to deal with another tariff issue of enormous fiscal and public policy importance:  the provisions governing TAPS dismantling, removal and restoration (DR&R).[20]  In recent orders, the RCA has reconfirmed its commitment to exercise its jurisdiction over DR&R issues under state law.[21]   At issue is the industry’s accelerated or front-loaded collection and retention of approximately $1.6 billion in funds for the future dismantling of the pipeline.  This tariff element is an undeserved windfall to the TAPS owners of enormous proportions, delivered to the TAPS Owners at shipper and public expense.  The Staff Expert Witness for the Alaska Public Utilities Commission, predecessor to the RCA, first identified the financial benefits of the DR&R provision to the TAPS owners, as well as the policy consequences for the State of Alaska, in 1986.[22]   Since then, DR&R problems have come to public attention at least four times; in every instance, the state administration has failed to remedy the problem, thereby continuing to penalize the state treasury and place the environment at potential risk.[23] 


While the DR&R provision has major implications for public policy in Alaska, it is a relatively minor aspect of the TAPS DR&R terms that best illustrates the complicated nature of pipeline tariff issues -- and the potential for industry to profit from the complexity surrounding transportation costs at public expense.  The TAPS tariff formula allows the TAPS owners to collect from shippers an income tax surcharge on all DR&R payments as part of the tariff.  But instead of actually making those payments to the federal Internal Revenue Service (IRS), the pipeline owners obtained a special ruling allowing annual deductions on DR&R income – long before that money is actually spent on dismantling.  For the TAPS owner shipping its own oil, the unnecessary income tax collection is simply a transfer to from the company’s production arm to its transportation subsidiary.  But this phantom transportation cost penalizes non-owner shippers, who must pay the cost out of pocket under the tariff formula.  Moreover, the excess cost also reduces the production arm’s royalty and severance tax basis, saving the company – and costing the state -- an estimated $0.21 per dollar.[24]   Three years ago, a committee of the Alaska State Legislature tried to find out how money much the state has lost over the years as a result of this scam.  The legislative committee was unsuccessful.[25] 

                        What about using pipeline facilities to limit access to the North Slope oil trade?  In 1993, U.S. Oil, a small oil company with a refinery on the West Coast decided that it could obtain oil from the North Slope more cheaply by chartering its own tanker than by paying BP to deliver that oil. By offering cheaper tanker rates than the major North Slope producers, U.S. oil planned to fill its tanker with oil for other refineries.  The tanker would have been the only tanker calling at the Valdez terminal to pick up North Slope oil that was not under the control of the major North Slope producers.  The TAPS operators denied the U.S. Oil tanker from Valdez, claiming that the company lacked the financial resources required by law to provide adequate spill response.  Barred from competing in the TAPS trade, the tanker owners filed two lawsuits – a suit against TAPS in state court for breach of contract and an antitrust case against the pipeline company and its owners in federal court.   After a three-week trial in 1998, the state court concluded that the TAPS operators had imposed unreasonable financial requirements beyond those required by law, causing the tanker’s owners to lose more than $10 million dollars.  Armed with that court judgment, the tanker owners negotiated a settlement with the pipeline company and dropped their antitrust case.[26]  Attorneys for the barred tanker could not discuss details but said they were happy with their settlement.[27]  However, the facts laid out in the court documents strongly suggest that the TAPS owners used their control of their facilities to bar a competing tanker from the TAPS trade.

The State’s Response to the RCA Decision.  You might think that the state of Alaska would be vigilant to ensure robust competition and promote development and increase revenues by preventing excessive pipeline tariffs and ensuring open access to key transportation facilities.  But you would be surprised.  Strange as it may seem, when Oilwatch Alaska, a nongovernmental organization, raised these issues with Alaska’s Attorney General, he responded that none of the parties allegedly injured by the conduct of the major North Slope producers has ever raised his concerns with the Department of Law.[28] 

Although the state Division of Oil and Gas has recently pointed out the problems resulting from the TAPS settlement methodology, it is the Department of Law that exercises primary responsibility for state pipeline tariff policy.  It should be noted that it was the Department of Law’s attorneys who negotiated the 1985 settlement agreement between the state and the TAPS owners.[29]   Participants in settlement negotiations are likely to believe it is a good one, whatever the outcome; if the negotiators didn’t think the settlement was the best possible under the circumstances, they would continue to negotiate or litigate.   This may be one reason why Alaska’s policy makers do not seek immediate reduction of TAPS tariffs[30] and do not try to get to the bottom of the DR&R question.  To do so would be to criticize their own 1985 settlement agreement.  When the Department of Law’s settlement defense fails on the merits, the state’s attorneys resist challenges by relying rely on a provision of the settlement that obligates all signatories to defend the settlement.[31]


In 2001, the Alaska Department of Law claimed that the 1985 settlement resulted in tariff reductions resulting from that settlement augmented state revenues by $3.8 billion during the next 10 years.[32]  This figure should not be mistaken for demonstration that the settlement served the public interest; that argument turns the excessive tariffs filed by the TAPS owners into a reference point, then substitutes that faulty benchmark for the standard of just and reasonable tariffs.  But the rationale for high tariffs offered by attorneys obligated to advocate the interests of their company’s stockholders is not the appropriate standard for evaluating the settlement tariffs.  Rather, tariffs should be evaluated in terms of factors such as actual costs and appropriate rates of return for risks incurred.  It is the latter approach that the RCA correctly applied when it determined that TAPS tariffs were – and are – grossly excessive.    

The lessons from TAPS and Alaska’s North Slope may be summarized as follows: 

è Excess transportation costs from a remote province can reduce host government revenues significantly;

è high costs and selective enforcement of transportation terms can also inhibit competition by companies who do not share in pipeline ownership;

è calculation of transportation costs and their implications for host government revenues are liable to be quite complicated;

è state actions in this arena have not maximized the public interest.

In this situation, an informed public can play an important role by encouraging government to avoid problems or demanding that mistakes be corrected. 


Caspian Basin

                        Oil exports from the Caspian Sea region totaled approximately 0.92 million bpd in 2001.  This figure is expected to triple by 2010.  Much of that oil will likely be carried by two major new oil pipelines that will carry Caspian oil to western markets.  In October 2001, the Caspian Pipeline Consortium (CPC) Pipeline loaded its first barrel of Kazakhstan oil into a tanker at the Black Sea port of Novorossiisk, Russia.  The CPC line, which circles the north rim of the Caspian Sea on its 1,580-kilometer trip to the Black Sea, will serve as the principal conduit for the super-giant Tengiz field in western Kazakhstan.  A second major line, the Baku-Tbilisi-Ceyhan (BTC) Pipeline, is presently under construction.  When completed, the 1,738-kilometer BTC Pipeline will carry oil from another super-giant field, Azerbaijan’s Azeri-Chirag-Gunashli complex in the southern Caspian Sea through Georgia to Ceyhan, Turkey, on the Mediterranean.    A third super-giant field, Kashagan, was discovered in the northern Caspian, just west of Tengiz, in 2000.  Oil from that field might be shipped on either new pipeline, or both.   Meanwhile, smaller but significant quantities of oil produced in other Kazakhstan oil provinces are now transported via other truck, rail, barge and pipeline connections.  The most important of these is a network of older pipelines that transports oil north to Russia.  Some of this oil may use excess capacity in the BTC and CPC pipelines.  Additionally, construction is underway on a new pipeline that will carry Kazakhstan oil east to China.  Export through Iran would provide an attractive economic alternative, but a major impetus for Caspian oil development is to reduce western dependence on the Persian Gulf states.[33]

The Chicken-Egg Dilemma: Part I.  It has been suggested that large pipelines face a classic “chicken and egg” problem:  An oil field needs a transportation link, but a pipeline needs oil.  Investors in the component that is completed first faces a risk of economic loss if the latter fails to be completed on schedule or fails to live up to expectations.[34]  It is difficult to establish the correct rate of payment for shipments on a pipeline with an uncertain future.  Thus, the “chicken and egg” dilemma was a significant factor delaying the construction of the CPC Pipeline.  In 1993, it was estimated that the CPC line would cost $1.4 billion.  Chevron (now ChevronTexaco) held a major interest in Tengiz and thus had a primary interest in the pipeline to the west.  But the financing proved difficult to arrange and construction did not begin immediately.  By the time the financing to build the pipeline was arranged and construction began five years later, the consortium had no less than eleven identified participants.  With a capacity of 400,000 bpd in 2002, an additional $1.7 billion investment is planned to increase CPC’s capacity to 1.34 million bpd by 2015.[35] 

Three governments own 50 percent of CPC, while eight private investing groups comprised the other half.  The present owners of Tengiz and the CPC pipeline are:



Table 1.  Tengiz and  CPC Pipeline Project


CPC Pipeline

Estimated 9 billion barrel recoverable, discovered in 1979; production in 2001, 290,000 bpd; anticipated peak of approximately 0.9  million bpd around 2010.


From Tengiz to Novorrossiisk; first phase completed 2001; present capacity 600,000 bpd; when completed, will carry 1.34 million bpd for a total cost of $4.2 billion                                                   






ChevronTexaco (50%) . . . . . . . . . . . . . . . . . . . . . . .
ExxonMobil (25%) . . . . . . . . . . . . . . . . . . . . . . . . . .

Kazakhoil (20%)  

LUKArco (5%) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Russian Federation (24%)

Republic of Kazakhstan (19%)

Sultanate of Oman (7%)

Chevron CPC Consortium (15%)

ExxonMobil (7.5%)


LUKArco (12.5%)

Kazakhstan Pipeline Ventures LLC (1.75%) Rosneft-Shell Caspian Vent. (7.5%)

Agip International (2%)

BG Overseas Holdings (2%)

Oryx Caspian Pipeline Co. (1.75%)


 (From:  U.S. Energy Information Agency, “Kazakhstan” (country briefing report), January 2002 and  “Caspian Sea Region:  Reserves and Pipeline Tables,” July 2002, Tables 1, 2 and 4.)



Although its name does not appear in the preceding list, BP – the major British transnational whose interests on Alaska’s North Slope were discussed in the preceding section – owns approximately 6.62% of the CPC pipeline.  When BP acquired ARCO in 2000, BP inherited ARCO’s interests in LUKArco, a joint venture with the Russian oil company Lukoil formed in 1997.   As a result of that merger, BP has a 5.75% share of CPC (46% of LUKArco’s 12.5% stake), with an obligation to finance 25% of the pipeline.[36]   Press accounts indicate that BP also controls an additional 0.875% of CPC through LUKArco’s half interest in Kazakhstan Pipeline Ventures LLC.[37]  In December 2000, CPC shareholders named Sergei Gnatchenko as the new General Director of CPC.  According to the company press release, “prior to his appointment Mr. Gnatchenko was the President of LUKArco Services B.V., a joint venture of Lukoil and Arco, a subsidiary of BP-Amoco.”[38] 

When Tengiz oil began to fill the CPC pipeline in March 2001, the cost to construct the pipeline had escalated to $2.6 billion. At that point, start-up was delayed again – this time by disagreements with Russian authorities over shipping rates. According to one observer, the dispute revolved around the method of valuing the different types of crude oils that each producer contributed to the pipeline, each of which had a different chemical composition and, consequently, a different market value.  Another warned that the quality bank – the method of assigning different values used in western nations  – was new to the Russian energy sector and would be difficult to explain.  Others said that the root of the problem was that Transneft, the Russian state pipeline monopoly, simply viewed CPC line as an unwelcome competitor; still other suggested that Russia delayed the opening of CPC in an effort to compel Kazakhstan to agree not to transport oil through the BTC pipeline later in the decade.[39]  

The first shipment of oil on the CPC was delivered to the Black Sea in November 2001, but the difficulties making arrangements to get Kazakhstan’s oil to market continued.  In March 2002, it was reported that Russia was preparing to classify a portion of the pipeline as a “natural monopoly,” which would make its tariffs subject to review. At the same time, oil companies were challenging new petroleum legislation in the Russian Federation and in Kazakhstan before international tribunals.[40]


PetroKazakhstan (Hurricane) and CPC.  PetroKazakhstan (formerly Hurricane Hydrocarbons Ltd.) is a small, vertically integrated Canadian firm that has become one of the largest oil companies in Kazakhstan while remaining focused on production from relatively small on-shore fields in the south-central part of the country.[41]  Unlike the major transnational oil companies, PetroKazakhstan does not invest in the large, high-stakes prospects that lie beneath the western part of the country and the Caspian Sea; according to PetroKazakhstan chief executive Bernard Isautier, the Caspian is “a different game – long lead times, massive capital investments and different technology.”[42]  In its turbulent, six-year history, the company has gone from near-bankruptcy in 1999[43] to one of the largest oil companies in Kazakhstan.   During the first quarter of 2003, PetroKazakhstan’s 0.14 million bpd represented a 14 percent increase over the preceding year.[44]

PetroKazhakstan publishes a great deal of information on its complicated business at its on-line web site.[45]  The importance of the costs that PetroKazakhstan incurs to move its oil, using a variety of barge, rail, truck and pipeline connections, is indicated by these data.  During the first three months of 2003, the company reported costs of $8.32 per barrel for the variety of barge, rail, truck and pipeline connections necessary to transport its export oil to market.[46]  That amount reduces the revenue PetroKazakhstan receives on its exported oil by 35%.  

The unsuccessful effort of PetroKazakhstan to buy into the CPC pipeline provides insight into the importance of pipeline economics in the Caspian Basin.  In 2001, PetroKazakhstan announced plans to streamline its transportation operations by purchasing one-half of the Kazakh Pipeline Ventures interest in CPC from BP for $100 million.   According to press reports, the deal would give PetroKazakhstan a 0.875% stake in the CPC pipeline and the right to export 64,000 bpd over that line, saving the company “millions of dollars every year in transport costs.”    By June 2002, the deal was less than a week away from completion and PetroKazakhstan had already paid BP $40 million.  But at that late date, for reasons that were not clear, the deal was scuttled by Kazakhstan’s newly-created oil and gas conglomerate and PetroKazakhstan’s CPC partner-to-be, KazMunaiGaz.[47]  According to one observer, “BP went through tremendous amounts of work to get letters of credit and every major CPC shareholder went through incredible amounts of work for 11 months to put this through. . . . Then you’ve got this ridiculous reversal . . . . There’s something that doesn’t add up here.”[48]  PetroKazakhstan spent the next year arranging more costly access to CPC as an independent shipper.[49]

Press reports on PetroKazakhstan’s unsuccessful effort to buy into CPC suggests that investors in the CPC pipeline may be richly rewarded for their investment in that project.  Look at it this way:  BP sold 0.875% of the CPC pipeline for $100 million.   This suggests that the CPC pipeline is worth $11.4 billion.  The pipeline was built between 1998 and 2001 for approximately $2.6.  Thus the sale price was more than four times the original investment.  If you could quadruple your original investment in four years, you’d smile all the way to the bank.[50]  PetroKazhakstan must have thought it could realize significant savings on transportation charges by investing in CPC or it would not have been willing to invest $100 million in CPC.


The Chicken-Egg Dilemma:  Part II.   The discovery of Kashagan in 2000 added a new dimension to the “chicken-egg” dilemma.  A super-giant field probably larger than Tengiz, Kashagan is estimated to contain approximately 10 billion barrels of recoverable oil with first production anticipated by 2005.[51]   The ownership structure shown in Table 2 reflects the sale of a 14.29% share in Kashagan formerly held by BP and Statoil to the other members of the consortium.[52]



Table 2.  Kashagan Project


Approximately 10 billion barrels; discovered in 2000; production anticipated to begin in 2005, peaking at approximately 1.2 million bpd around 2015.




Agip – ENI (16.67%), BG (16.67%), ConocoPhillips (8.33%), ExxonMobil (16.67%), Inpex (8.33%), Shell (16.67%), TotalElfFina (16.67%).


From:  Phillips Petroleum Co., “Kashagan Declared Commercial” (press release), June 28, 2002.



If production from both Tengiz and Kashagan increases during the coming decade as anticipated (see Tables 1 and 2), the CPC pipeline will not be able to transport all of Kazakhstan’s new production to western markets.  One analyst estimates that by 2011 Kazakhstan will be producing 0.7 million bpd of oil in excess of export pipeline capacity by 2011.  The first candidate for transporting excess Kashagan production is the BTC pipeline, which is supposed to be ready to carry 1.0 million bpd by early 2005 and is contracted to carry the production from the third super-giant in the Caspian region, Azerbaijan’s Azeri-Chirag-Gunashli complex (see Table 3).[53]




Table 3.  Azeri-Chirag-Gunashli (ACG) Field and BTC Pipeline Project
ACG Field

BTC Pipeline

Estimated recoverable reserves of 5.4 billion barrels; production of 130,000 bpd in 2001 Anticipated to increase to 400,000 bpd by 2004, 800,000 bpd in 2007 and more than 1.0 million bpd in 2010

From Baku (Azerbaijan oil to be exported in 2005; when completed, will) to Ceyhan (Turke)y; first carry 1.0 million bpd; total cost of $2.95 billion ($3.6 billion with financing).



BP (34.14%) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Unocal (10.28%) . . . . . . . . . . . . . . . . . . . . . . . . . . . .

State Oil Co. of Azaerbaijan (10.0%) . . . . . . . . . . . .

LUKoil (10.0%)

Statoil (8.56%)  . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

ExxonMobil (8.0%)

TPAO (6.75%). . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Devon Energy (5.63%)

Itochu (3.92%). . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Delta Hess (2.72%). . . . . . . . . . . . . . . . . . . . . . . . . .

BP (30.1%)

Unocal (8.9%)

State Oil Co. of Azerbaijan (25%)


Statoil (8.71%)


TPAO (6.53%)


Itochu (3.4%)

Delta Hess (2.36)

Agip (2.5%)

TotalElfFina (5%)

ConocoPhillips (2.5%)

INPEX (2.5%)

From:  http://www.caspiandevelopmentandexport.com/ and “Building Tomorrow’s Crisis?”


It is not clear whether the two major export routes to the west will be handle the production from the three super-giant fields and other production from the Caspian region.  Additionally, the schedules for expanding the capacity of two major pipelines may not match the increase in production from the three super-giant fields discussed above.  BTC needs oil in the first years of its life, but the Kazakhstan surplus may not materialize until several years later.  With a partially empty pipeline, BTC inves tors will face potentially serious problems recouping their investment in the early years.  Under these circumstances, BTC’s projected rate of return – already below industry norms – could be seriously reduced.[54]  In recognition of these problems, the BTC Pipeline grants its owners the right to ship on the pipeline at reduced rates.[55]

For oil produced in Kazakhstan, the BTC route poses another significant problem:  How to get that oil across the Caspian Sea to Baku?  The governments of Kazakhstan and Azerbaijan have a mutual interest in solving this problem – Kazakhstan wants to export oil and Azerbaijan wants to fill the BTC pipeline.  Possible solutions include surface transport by tanker and an undersea pipeline; both solutions add to the shipping costs, potentially reducing Kazakhstan’s share of the petroleum revenue “take” from its production.[56]

Another potential problem for BTC is that cost over-runs could increase per-barrel shipping costs, again depriving Kazakhstan of income.  With construction on the Georgia portion just beginning in 2003, a challenge by an environmental lawsuit there is accompanied by cost overruns and delays on the long portion through Turkey.[57] 




The major oil fields and the new pipeline routes out of the Caspian Basin face a wide range of technical, environmental, political and economic complications.  These problems might increase pipeline tariffs, decreasing government revenues and adversely affecting development.

In the United States, pipeline tariffs are regulated to ensure all parties access to a pipeline on equal terms, and at rates that are just and reasonable.  Despite these safeguards, the RCA’s November 2002 TAPS decision found that TAPS tariffs have been inflated, with two major consequences: reduced host government revenue and a decrease in the robust competition among potential producers that many observers believe is vital to development.  It has yet to be determined whether the state of Alaska intends address the arguments set out in the RCA’s TAPS decision in a meaningful manner.    

The legal framework for pipeline regulation emerging in the Caspian Basin appears to be quite different from that of the United States.   As PetroKazakhstan’s attempt to buy into the CPC pipeline and the differential rates on the BTC pipeline make clear, pipeline owners are allowed to derive significant differential benefits from their ownership.  

In light of Alaska’s experience and the contrast between the regulatory approach to pipeline economics, the people of the Caspian Basin should insist on vigilance and attention to detail in analyzing pipeline tariff policy and execution.


[1] This article rests on the premise that revenues from resource extraction should enrich the lives of the people of the territory from which those resources are taken from the earth.  Achievement of this fundamental human right depends on the degree to which the financial mechanisms by which oil is transformed into wealth are implemented in a just and meaningful manner.  Therefore, this article is focused on the revenue stream produced by petroleum development, rather than the ecological effects of pipeline construction and operations on land, air and water.


[2] The term “super-giant” is usually reserved for oil fields estimated to contain at least 5.0 billion barrels of recoverable oil.  In 1993 there were only 42 such fields in the world (L.F. Ivanhoe and G.G. Leckie, “Global Oil, Gas Fields, Sizes, Tallied, Analyzed,” Oil & Gas Journal, Feb. 15, 1993, pp. 87-91).  Alaska and the Caspian Basin are among the relatively few regions outside the Persian Gulf that possess super-giant oil reservoirs.


[3]  See:  Alaska Department of Revenue, Revenue Sources Book:  Forecast and Historical Data, Spring 2003, Appendix D.  (on-line at www.revenue.state.ak.us).


[4] Mergers and acquisitions have changed the corporate names of the three dominant companies on Alaska’s North Slope.  BP’s U.S. subsidiary merged with the Standard Oil Company of Ohio (Sohio) in 1970 and formally took over management of its Alaska partner in 1987; ExxonMobil represents the combined interests of the former Exxon and Mobil Corporations; Phillips Petroleum became the third major North Slope player by virtue of Phillips Petroleum’s  acquisition of ARCO’s Alaska properties in 2000.  United States antitrust regulators required BP to divest ARCO’s Alaska holdings as a condition of its global merger with ARCO; the enlarged Phillips subsequently merged with Conoco, which held smaller interests on the North Slope before trading them to BP and leaving Alaska in 1993.)


[5]  Data for 1977-87 from: Edward B. Deakin, Oil Industry Profitability in Alaska, 1969 through 1987 [Alaska Dept. of Revenue, 1989], Appendix E; data for 1988-1998 from:  Alaska Department of Revenue, “State of Alaska’s Oil Revenue Pie (Production and Value Added by TAPS),”  March 22, 2000 (in letter from Dan E. Dickinson, Director, Tax Division, to Representative Jim Whitaker, Chair, Special Committee on Oil and Gas, Alaska State House of Representatives).  Adjusted to 2003 dollars using Consumer Price Index (CPI-U), industry North Slope production and pipeline profits totaled approximately $118.0 billion).


[6]  Estimated from Deakin and “State of Alaska’s Oil Revenue Pie (Production and Value Added by TAPS).” 


[7]  TAPS profit data from Richard A. Fineberg, How Much Is Enough?  Estimated Industry Profits From Alaska North Slope Production and Associated Pipeline Operations, 1993-1998 (Oilwatch Alaska, 1998), Table 4.1. 


[8]  Approximately eight percent of the oil shipped through TAPS goes to in-state refineries.  But the state commission’s 165-page decision calls into question the shipping rates for the remaining 92 percent of TAPS oil because that oil is shipped under a similar formula arrangement approved by the Federal Energy Regulatory Commission (FERC).


[9]  Regulatory Commission of Alaska, Order Rejecting 1997, 1998, 1999 and 2000 Filed TAPS Rates; Setting Just and Reasonable Rates; Requiring Refunds and Filings; and Outlining Phase II Issues, Docket P-97-4, Order #151 Nov. 27, 2002 (on-line at www.state.ak.us/rca).    


[10] Although the RCA has jurisdiction only over the shipping charges for approximately eight percent of the oil shipped through TAPS, the state commission’s decision calls into question the shipping rates for the remaining 92 percent of TAPS oil shipped under a similar formula arrangement approved by the Federal Energy Regulatory Commission (FERC).


[11]  Allen Baker, “State weighs pipeline fees -- $110 Million:  If rates are cut, Alaskans, small producers benefit,” Anchorage Daily News, Dec. 31, 2002, p. A-1.


[12]  ‘Good news’ wanted in 2003,” Petroleum News Alaska, Jan. 19, 2003, p. 1.


[13]  Sean Cockerham, “Oil lease probe sought – Permanent Fund:  Corporation worries smaller companies are shut out, state is being shortchanged,” Anchorage Daily News, Feb. 20, 2003  (on-line).


[14]  See: Indicated TAPS Cariers’ Statement of Points on Appeal, Amerada Hess Pipeline Corporation, BP Pipelines (Alaska) Inc., ExxonMobil Pipeline Company, Mobil Alaska Pipeline Company, Phillips Transportation Alaska, Inc. and Unocal Pipeline Co. v. Regulatory Commission of Alaska, Dec. 6, 2002 (Superior Court for the State of Alaska, Third Judicial District, Case No. 3AN-02-___ CIV); and Wesley Loy, “Oil bill would ‘decapitate’ regulators, critics say,” Anchorage Daily News, April 26, 2003 (on-line).


[15]  Conoco was an independent oil company until 2001, when it merged with the Phillips Petroleum Co. to become part of ConocoPhillips (see footnote 3, above). 


[16] For the effect of pipeline costs on Conoco’s profitability during its final year of operation in Alaska, see How Much Is Enough?, op. cit., pp. 27-35.


[17] For Dunham’s statements see “Getting to the Future First,” Hart’s Oil and Gas Investor, August 1996, p. 41.


[18]  Indicated TAPS Cariers’ Statement of Points on Appeal.


[19]  “Oil bill would ‘decapitate’ regulators, critics say.”


[20]  This discussion of the treatment of DR&R on TAPS  is presented as an example of the way in which complex formula can be used to generate profits.  Provisions for dealing with dismantling issues in the Caspian Basin differ significantly from those governing TAPS. 


[21] Regulatory Commission of Alaska, Order Denying Indicated TAPS Carriers’ Motion to Cancel Prehearing Conference and Ruling on DR&R Question, Docket P-97-4, Order #157, March 6, 2003 (on-line at www.state.ak.us/rca).


[22]  Prefiled Testimony of Rudolph L. Bertschi   (Alaska Public Utilities Commission Docket No. P-86-2), December 17, 1986, pp. 63-70. 


[23]  For a summary and economic analysis of DR&R issues in the context of the TAPS tariffs, see Richard A. Fineberg, The Emperor’s New Hose:  How Big Oil Gets Rich Gambling with Alaska’s Environment (Alaska Forum for Environmental Responsibility, June 2002), Chapter 5 (on-line at www.alaskaforum.org).


[24]  This issue is briefly summarized in Richard A. Fineberg, “New filings reveal oil pipeline owners’ tax scam,” Anchorage Daily News, Feb. 8, 2000, p. B-8.


[25]  Alaska State House House Oil and Gas Committee hearing, April 13, 2000 and follow-up letter from Michael A. Barnhill, Assistant Attorney General, to Rep. Jim Whitaker, May 23, 2000. 


[26]  This account is taken primarily from the following court documents:  “Complaint,” Maritime Endeavor Associates, L.P. v. Alyeska Pipeline Service Company,  Alaska Superior Court Case No. 1JU-95-1141 Civil, May 31, 1995; “Complaint,”  Maritime Endeavor Associates, L.P. v. Alyeska Pipeline Service Company, Inc., BP America, Inc., BP Oil Company, BP Oil Supply Co., BP Exploration & Oil Inc., BP Oil Shipping Co. USA, BP Pipelines (Alaska) Inc., Amerada Hess Pipeline Corp., ARCO Transportation Alaska Inc., Exxon Pipeline Co., Mobil Alaska Pipeline Co., Phillips Petroleum Co. and Unocal Pipeline Co., United States District Court (Juneau) Case No. J97-010 CV (HRH), May 27, 1997; “Memorandum of Decision and Order,” Case No. 1JU-95-1141 CI, Sept. 30, 1998; and “Stipulation and Order for:  Vacation of September 30, 1998 Memorandum of Decision and Order and Dismissal of Action with Prejudice,” Case No. 1JU-95-1141 CI, Feb. 17, 1999.


[27]  Author’s interview with attorneys representing U.S. Oil’s successors (Maritime Endeavor Associates, L.P.).


[28]  Letter from Alaska Attorney General Bruce Botelho to Jim Sykes, Executive Director, Oilwatch Alaska, Nov. 28, 2997 (see also:  Brian O’Donoghue, “Suits allege antitrust violations by Alyeska,” Fairbanks Daily News-Miner, November 30, 1997, p. A-1).


[29] Settlement Agreement between The State of Alaska and ARCO Pipe Line Co., BP Pipelines Inc., Exxon Pipeline Co., Mobil Alaska Pipeline Co., Union Alaska Pipeline Co. with Respect to the Trans Alaska Pipeline System, June 28, 1985 (Federal Energy Regulatory Commission  Docket OR 78-1), p. 1.


[30]  In the RCA tariff proceedings, the State of Alaska, represented by the Department of Law, supported the 1985 settlement in opposition to the shippers who sought lower tariffs.


[31]  Settlement, Section  I-3.


[32]  “Oil and Gas Settlements,” attachment to letter from Bruce M. Botelho (Alaska Attorney General) to Representative Eric Croft (Alaska State House of Representatives), Feb. 7, 2001.  

[33] For a summary of Caspian Sea region reserves, production and pipeline routes, see:  U.S. Energy Information Agency, “Kazakhstan” (country briefing report), January 2002 and  “Caspian Sea Region:  Reserves and Pipeline Tables,” July 2002, Tables 1, 2 and 4 (on-line at http://www.eia.doe.gov).


[34] Mark Mansley, “Building Tomorrow’s Crisis? The Baku-Tbilisi-Ceyhan Pipeline and BP:  A Financial Analysis,” Claros Consulting, May 2003 (on-line at http://www.bankwatch.org), p. 9. 


[35] Robert M. Cutler, “The Caspian Pipeline Consortium Beats the Skeptics,” The Analyst, Sept. 12, 2001 (on-line); and “Caspian Sea Region:  Reserves and Pipeline Tables,” July 2002.

[36] See:  Lukoil, “International exploration and production,” undated (circa 2002;  on-line  at http://www.lukoil.com/razvedka_dobycha/inter.htm).


[37] See for example:  Charles Coe, “Questions concerning Kazakhstan’s future go beyond oil,”  Alexander’s Gas & Oil Connections, July 31, 2002 (on-line at http://www.gasandoil.com/goc/news/ntc23492.htm); and Pravda On-line, “Hurricane Abandons $100 Million Pipeline Deal,” June 17, 2002 (on-line at http://english.pravda.ru/comp/2002/06/17/30498.html; originally published by Reuters, June 14, 2002).


[38]  Caspian Pipeline Consortium, “Caspian Pipeline Consortium Shareholders Approve Budget for the Year 2001 – CPC General Director Viktor Fedotov to be succeeded by Sergei Gnatchenko,” Dec. 1, 2000 (press release; on-line at http://www.cpc-ltd.com/).


[39] “The Caspian Pipeline Consortium Beats the Skeptics.”


[40]  Michael Lelyveld, “Kazakhstan: Foreign Investors May Face Troubles Over Pipeline Tariffs,” Radio Free Europe / Radio Liberty, March 7, 2002 (on-line).


[41] See:  “Oil Industry of the Republic of Kazakhstan,” Oil & Gas Vertical  (Analytical Journal, #15 [82]), September 2003 p. 152.


[42] Jeffrey Jones,  “Kazakhstan aims for Caspian oil rush in 2004” (update 1), Reuters, June 27, 2003 (on-line).


[43] Gary Park, “Soaring share prices trouble Canadian securities regulators:  Trading activity of takeover companies under scrutiny as rumor mill churns out fresh speculation, dominated by talk of a BP bid for oil sands leader Suncor Energy,” Petroleum News Alaska, March 31, 2003.


[44] PetroKazakhstan Inc. “Management’s Discussion and Analysis,” 2003, FirstQuarter, p. 2 (on-line).  

[45] PetroKazakhstan’s web site can be accessed at http://www.petrokazakhstan.com.


[46]  See:  “Management’s Discussion and Analysis,” 2003 (first quarter), p. 14 (on-line).


[47]  “Questions concerning Kazakhstan’s future go beyond oil.” 


[48]  “Hurricane Abandons $100 Million Pipeline Deal.”


[49] See:  “PetroKazakhstan gets new pipe for fast oil exports,” Reuters, June 24, 2003 (on-line).


[50] $100,000,000 * 100 * 8 / 7 = $11,428,571,429.


[51] “Kazakhstan” (country briefing report).


[52] Phillips Petroleum Co., “Kashagan Declared Commercial” (press release), June 28, 2002  (on-line at http://www.phillips66.com/newsroom/NewsReleases/Print/rel396.doc).


[53]   “The Baku-Tbilisi-Ceyhan Pipeline and BP:  A Financial Analysis,” p. 9. 


[54] “The Baku-Tbilisi-Ceyhan Pipeline and BP:  A Financial Analysis,” pp. 25-29.


[55]  “The Baku-Tbilisi-Ceyhan Pipeline and BP:  A Financial Analysis,” p. 11.


[56] Platt’s Global Energy, “U.S. hopeful of cross-Caspian oil export agreements by end-2003,” June 3, 2003 (http://www.platts.com/features/caspian/related.shtml).


[57] For background see: “The Baku-Tbilisi-Ceyhan Pipeline and BP:  A Financial Analysis,” pp. 10-11, 28-31.