On June 23, 1997, the staff for the Northwest Energy Review Transition Board ("Transition Board") published a background paper entitled "Transition Costs: A Review of Practices and Their Possible Application to Bonneville." Subsequently, at its July 14, 1997 meeting, the Transition Board announced its intention to complete by year’s end an analysis of the Bonneville Power Administration’s ("Bonneville’s") possible transition costs and to examine the alternatives that might be pursued by Bonneville in regard to such costs. The Transition Board has invited comments on this subject and, specifically, the staff’s background paper. The following are the comments of the Eugene Water & Electric Board ("EWEB"). 

The staff’s background paper identifies certain "Common Elements of Transition Costs Recovery Mechanisms" (pp. 7 and 8). The paper also notes various aspects of Bonneville's unique situation (pp. 9 to 11) which could require that such common elements be applied to Bonneville in a modified or different form. EWEB agrees with the basic proposition that common elements can be found when different transition cost methodologies are compared. EWEB also agrees that the application of the transition cost concept to Bonneville will require modifications to the basic tenets supporting most of the laws and administrative programs adopted thus far on the subject.  

From the outset, one critical distinction must be made clear. EWEB views transition costs as a concept solely focused on mitigating costs associated with historical commitments, i.e., commitments made prior to a specific date in time. Legally and equitably, recovery of costs associated with historical commitments must be treated differently than those associated with future decisions.  

Under the historical monopoly system, all electricity users in the Region benefitted in one form or another from Federal base system resources. If necessary, the entire Bonneville system, including both power and transmission resources, must remain available to generate revenues sufficient to pay costs incurred under that monopoly regime. With the impending advent of competition, however, the costs of new Federal resources, and the variable costs associated with continued operation of existing resources, should be borne only by those directly receiving specific benefits from those investments. Stranded cost recovery must be contingent upon an adequate division of these costs and be limited in amount to the former. 

These comments first discuss certain "knowns" and "unknowns" about the transition cost issues in the Bonneville setting. The comments next recount certain historical facts which are relevant to how the principles should be implemented to achieve an equitable result. The comments then set forth certain conditions precedent to the imposition of a transition charge against any entity and present EWEB's views as to the principles that should be followed if such charges actually become necessary. 

Before these matters are addressed, EWEB believes that it is important for the Transition Board to understand that EWEB occupies a rather unique, multi-faceted position in regard to the Bonneville transition cost issue. EWEB is a preferred customer of Bonneville under the Bonneville Project Act and its progeny. EWEB is an issuer of net billed debt per its ownership interest in the Trojan Nuclear Plant. EWEB, however, made a conscious decision not to participate in the WPPSS projects. EWEB currently serves its load through both Bonneville and other contractual purchases as well as its own resources. EWEB both buys and sells power in the developing competitive marketplace and purchases unbundled transmission services from Bonneville as well. 

Simply stated, for good or bad, EWEB wears many different "hats" as it evaluates the appropriate treatment of this issue. Consequently, EWEB may be in a position to provide a somewhat less adversarial view on the Bonneville stranded cost issue than those being advanced by entities that buy only transmission from Bonneville, that are not contractually obligated under net-billing agreements, etc.. 

What follows is EWEB’s attempt to divine a path through current law, contracts and bond undertakings to reach an equitable solution to the question of how Bonneville stranded costs should be avoided and, if they cannot be avoided, how they should be recovered. The following involves many concessions EWEB is willing to make if other parties are also willing to compromise. In the event mutual compromises do not appear and Bonneville’s stranded cost are not, in EWEB’s view, equitably distributed, EWEB expressly reserves its rights to make all arguments necessary to protect the interests of its customers. That being said, here is our view of the legally necessary and equitably preferable path. 

I.. Defining the Dilemma: The Knowns and Unknowns Surrounding Bonneville Transition Cost Issues 

We begin with what we do not know. First, we do not know whether Bonneville power will be more or less expensive than market priced power post-2001 when the current Bonneville contracts expire. Second, we do not know if sufficient post-2001 "subscriptions" will be obtained from various classes of Bonneville power purchasers to allow Bonneville to cover its post-2001 power costs. Third, we do not know what principles will or can legally be adopted by Bonneville or FERC to determine transition cost obligations. Fourth, we do not know whether various efforts to escape from exposures to such liabilities through contractual actions will be successful, e.g., the DSI effort to achieve contractual releases for transition cost liability. Fifth, we do not know whether utilities that are forced to pay any type of a transition charge will be able to collect such charges from their retail customers given the unknown direction of future Northwest state laws addressing this subject. Sixth, we do not know when Bonneville will undertake the procedural actions, principally a full Regional Act Section 7(i) proceeding, required under law and certain litigation settlements before a transition charge can be imposed. Finally, we do not know whether any transition payments are or ever will be required if the price for power escalates and Bonneville institutes significant cost-cutting and aggressive marketing policies.

 What do we know? First, no entity wants to pay transition costs, particularly if it comparatively disadvantages the entity in the new and more competitive marketplace. In fact, it is reasonably predictable that certain companies will attempt to use this issue to their unreasonable competitive advantage by saddling their potential competitors with transition costs that will skew true competition. Second, Bonneville has current legal and contractual obligations which require it to raise sufficient sums to meet its revenue requirement through both power and transmission sales. Third, if any transition cost recovery method adopted by Bonneville compromises the likelihood that any of Bonneville's "creditors" will be paid, the method will be legally challenged - thereby disrupting the implementation of an equitable competitive market in the Northwest for a short time if the challenges lack merit and for a significant time period if the challenges are meritorious. Fourth, while various entities and groups will argue that only a few of the customer classes should be required to bear these charges, the fact is that the obligations that are driving the Bonneville rates were incurred at the urging of all of the traditional customers of Bonneville (the net billed plants) or to satisfy the demands of interest groups which could have prevented the passage of federal legislation such as the Regional Act (fish and wildlife programs) strongly supported by all Bonneville customer classes, including the direct service industries. Fifth, while there are viable power supply alternatives that will somewhat control the price that entities will pay for Bonneville power, virtually all participants in the emerging competitive market will need to buy transmission services from Bonneville. Therefore, only one source of revenue will likely ensure that Bonneville meets its revenue requirements post 2001 and until its power products become competitive - transmission sales. Sixth, we know that Bonneville should and will follow existing law until (and unless) it is changed.  

Based on these knowns and unknowns, EWEB believes that the principles set forth below following a brief historical summary should, and in certain cases must, be adopted by the Transition Board and Bonneville. The principles derive from existing law and the historical facts that caused that law to be what it is. The first set of principles addresses the actions required BEFORE Bonneville could impose any type of transition charge. EWEB believes that a transition cost charge can only be imposed after Bonneville has in fact failed to meet its revenue requirement in a fiscal year taking into account all power and transmission sales and the reasonable use of reserves. The second set of principles addresses the elements of the transition charges that should be followed if the transmission and power sales revenues are insufficient. 

II. Historical Factors Relevant to Designing an Equitable Transition Cost Policy 

A. Why Were The Dams Built and Why Is Bonneville Nuclear-Debt Ridden?

A detailed history of the development of the Federal projects and Bonneville is set forth in Appendix A. The Transition Board is encouraged to carefully review this history because EWEB believes it is vital to determining the equities involved in allocating costs associated with the federal system. Two points, however, must be emphasized. 

First, the Federal projects on the Columbia River and Snake Rivers were constructed with the functional intent of providing navigation, irrigation, flood control, power and recreation. Power generation was but one of several functions and was to be marketed by Bonneville to help recoup costs associated with projects that served, and continue to serve, several needs. 

Second, Bonneville’s fixed cost obligations associated with nuclear debt and other resources were incurred directly or indirectly for the benefit (and at the request) of all electricity users in the Region. That debt was marketed upon the representation that it was secured by all revenues that could be generated from the sale of all of Bonneville’s products and services, including both power and transmission. Further, the security arrangement is set in law through statutory and administrative payment priority provisions. Any alteration of this arrangement or other failure to honor this commitment will result in protracted and wasteful litigation. 

B. Why Does History Matter? 

An historical perspective is essential to the design of any transition cost mechanism. The objective of a transition charge is to ensure that investments are repaid by entities on whose behalf they were made. Transition charges are not favored; they are simply necessary in certain circumstances to avoid unfairly burdening certain consumers at the expense of others as markets move from monopoly to competition. 

However, while intended to ensure system stability and equity, transition charges can easily produce damaging and unintended results. For example, they can result in small consumers paying the actual costs of deregulation to the advantage of larger consumers that hold greater market power in a deregulated market. They can also skew rather than protect the design of a fair competitive marketplace, leading to unfair competitive positions for the new suppliers rather than a true competitive marketplace where all competitors are placed at the same basic starting line when the race begins.  

The FERC and state efforts described in the Transition Board briefing paper can be reviewed in detail to discern not only the common principles described in the paper, but also to predict the parochial and self-serving arguments that will probably be advanced by the various parties that will present their case to the Transition Board in this process. In other words, it is predictable that the same type of arguments made in the California and New Jersey settings will be made by the same type of entities in the development of the Bonneville stranded cost principles.  

For example, the new marketers will likely argue that they should make no transition cost payments because they were not involved in the decisions to build the net billed plants. The direct service industries may even advance the same type of argument although the factual bases for such an assertion are cosmetic at best. The investor-owned utilities may argue that they have received no benefits from the net billed plants and have met their net billed plant obligations in any event.  

Such arguments, however, do not withstand scrutiny when placed in a proper historical contexts. First, as explained in Appendix A, Bonneville incurred its net billed obligations as part of the HydroThermal Program. The DSIs directly encouraged Bonneville’s participation in the Program. Further, Bonneville’s role in the Program was designed to benefit all electricity users in the Region, including the customers of the IOUs and the customers of new marketers (be they former customers of IOUs or publicly-owned and cooperative utilities). 

Second, such arguments fail to recognize the financial arrangements surrounding the net-billed debt and, instead, presume that any stranded cost payments will be made to pay the net billed debt. As shown below, this presumption is factually inaccurate under current law and Bonneville payment practices. Nonetheless, the arguments are predictable and must be addressed by the Transition Board as it recommends transition cost principles for adoption by Bonneville or Congress.  

In any event, history is important to the Transition Board's business. It is important in defining equity and interpreting the relevant statutes. It is important in recognizing that certain actions must be taken to meet legal and contractual commitments that pre-date the commencement of the movement toward competition in the sale of electricity even if the commitments were unwise in retrospect. It is important in determining whether a charge is justified at all and, if so, against whom. It is relevant to whether a transition cost policy will function as effectively as possible rather than simply cause greater likelihood that litigation will consume creativity, cooperation and compromise. Therefore, EWEB presents the historical summary attached as Appendix A in the hope that the Transition Board and other interested parties, including Bonneville, will give considerable attention to what actually led to the current situation in determining what should next occur. 

II. Recommended Principles for a Bonneville Contingent Stranded Cost Recovery Mechanism 

A. Fundamental Tenets

1. The priority of payments from the Bonneville Fund, as set forth in the Transmission System Act, DOE regulations, and various contractual commitments, must be maintained. That priority, in essence, is as follows: (1) net-billing credits (and direct cash payments, if needed) and other third-party debt payments, (2) Bonneville operations and maintenance and capital expenditures, and (3) payments to U.S. Treasury. Bonneville’s third-party debt (net billed and conservation) was marketed based on this payment priority. Failure to honor this commitment will result in protracted and wasteful litigation. 
2. Because of the priority set forth in item number 1, the U.S. Treasury stands at the greatest risk of nonpayment in the event that Bonneville is unable to meet its revenue requirement. 
3. The Federal Columbia River Power System and the Federal Columbia River Transmission System were developed with the understanding that it was "one system". Although the goal is to have each portion (power and transmission) sustain itself at cost-based rates, revenues from either function are available on a short-term basis to the other in the event one is unable to meet its individual revenue requirement. The "equitable allocation" requirement of the Transmission System Act and Regional Act means only that Federal and Non-Federal power must pay equivalent rates for equivalent amounts of capacity. Federal and state legislative and regulatory actions designed to completely separate private utilities into power and transmission entities cannot be used as a justification to ignore the historical obligations and contractual commitments surrounding the development and use of the Bonneville system.

 B. Actions Required Before A Transition Charge is Imposed 

One: Bonneville should voluntarily undertake extensive efforts to reduce its costs. Although there are currently few, if any, statutory restrictions on the extent to which Bonneville can obligate itself in performing authorized functions, the Administrator can voluntarily comply with independent audits and other traditional cost control mechanisms. In addition, cost control measures are one of the few areas where statutory changes could most likely be implemented without disturbing historical representations. 

Two: Bonneville should establish cost based post-2001 power and transmission rates under the rate-making principles established in the Regional Power Act.

Three: Bonneville should then offer power and transmission products for sale post-2001 at its cost-based rates to its public body and cooperative customers and the DSIs in accordance with existing statutes. Bonneville should hold these offers open for a reasonable period of time, e.g. six months, in order to allow its customers adequate time to respond. 

Four: Power that is not purchased by Bonneville’s public body and cooperative customers and DSIs at the prices established pursuant to point 2 should then be offered by Bonneville to any potential purchaser under the currently existing surplus and "excess" power guidelines. Marketing its surplus power is one means of mitigating the need for transition cost recovery.  

Five: Given Bonneville's contractual commitments to the net billed bond purchasers and Bonneville's commitments to Treasury, if it appears that Bonneville would be unable to meet its forecasted revenue requirements after aggressive cost-cutting programs and the actions enumerated in items one to four above, Bonneville is required to raise its rates on all products and services that can reasonably be expected to bear such increases. In the most likely circumstance, this would entail Bonneville increasing its transmission rates on a forecasted basis to provide sufficient revenues to meet its total revenue requirements. These increases would be effective against all sales to all transmission purchasers. 

Six: If these actions actually produced insufficient revenues to meet the overall Bonneville revenue requirement (e.g., the demand for an absolutely essential commodity such as Bonneville transmission proves, in fact, not to be "elastic"), Bonneville should first use its monetary reserves to meet revenue deficiencies in a given fiscal year and, secondarily, should defer on its obligations to Treasury. (Politically, however, maximizing Treasury deferral may not remain an option). Only after such actions are actually required in a given fiscal year, should Bonneville be authorized to impose a transition charge for the following fiscal year (or few years if reasonably necessary to minimize the charge’s financial impact). Such a transition charge should be limited to the amount needed to replenish Bonneville’s reserves and bring the Treasury payments current within a reasonable number of years (as determined by the size of the amount needed to be collected). 

One: The charge should be imposed in a manner that equitably allocates the cost to all users of the Federal base system resources and the transmission system. In addition to those who have purchased power or transmission from Bonneville on a firm, surplus firm, or "exchange" basis, the charge should encompass entities that use the Federal facilities for irrigation, navigation, flood control and recreation. 

Two: Bonneville's right to impose the charge on its wholesale customers should be conditioned on the enactment of state laws, or the clarification of existing authorities, that allow those entities to pass these charges on to the retail customers of such entities. If a state failed to enact such a law, it might be necessary to seek federal legislation that allows the collection of the transition charge from the customers of the Region’s utilities.  

Three: All sums recovered pursuant to the charge should be separately accounted for by Bonneville. In the event that Bonneville is able to charge above-cost prices for power in future years following the imposition of the charge, Bonneville should repay the sums advanced through cash payments or discounted future power or transmission prices. 

Four: The amount allocated to power users for transition costs, i.e., the costs remaining after all reasonable price increases and reasonable use of reserves and Treasury deferral, should be based on the total number of megawatts purchased (directly or through exchanges) or transmitted by customers over the past twenty years as compared to the total sums that must be collected to meet any Bonneville revenue deficiencies per the conditions described above.

 CONCLUSION

EWEB believes that the resolution of the transition cost issue is absolutely fundamental to defining the nature of the post 2001 Northwest power sales market. If the suggestions advanced by EWEB herein are followed, it is probable but not certain that transmission charge increases will be required for a short period of time until the market prices increase and Bonneville is able to achieve further cost reductions. However, such charges will not stifle competition and should not result in meritorious legal challenges. 

As time passes following 2001, EWEB believes that Bonneville power will again become attractive. What would be most unfortunate is for the Region to pursue costly and complicated solutions to a problem that is competently dealt with under the existing contractual and statutory structure applicable to Bonneville. While some may argue that the Transmission and Regional Acts did not contemplate a situation where Bonneville would be unable to sell power at cost, this is simply not true.

 In fact, one of the reasons that deferrals on the Treasury payments were allowed even after Bonneville became a self-funded agency was that no entity has ever known for sure how much power Bonneville would be able to sell in a given year. As to the security behind the WPPSS debt, there is no question that the priority payment provisions, secured by the entire Bonneville Fund, were intended to reassure potential bond purchasers that all transmission system revenues as well as the power sales revenues would be used to pay the bondholders.  

Finally, no mechanism should be put in place that could allow for the collection of transition costs above that needed for Bonneville to meet its revenue requirements. No transmission surcharges should be imposed until they are proven necessary in a given fiscal year. Furthermore, there is nothing preventing Bonneville from allowing future power sales revenues to be repaid to entities that are forced to pay transmission surcharges.  

We can make this complicated or fairly simple. If we do what the law requires, we can move our attention away from how to put the burden on one class of customer or another and get on with a collective effort to control Bonneville costs. Essentially, the Region needs a map, not a new freeway. EWEB believes that the Region’s retail customers will ultimately benefit from this course of action. 

Thank you for the opportunity to comment on this subject. While some of our factual summary may be disputed, we have tried to be accurate. While some of our legal tenets are untested, we believe they have substantial merit and would receive judicial sanction. The Region needs to follow the law and compromise what is left to be decided. This is in the best interest of the consumers. 

We look forward to comments, corrections and a cooperative process. 

Randy Berggren,

General Manager

For:The Board of Commissioners

Of the Eugene Water & Electric Board

A. The Early Years - 1933 to 1965

The Columbia River dams were built by the Corps of Engineers primarily for flood control, navigation and irrigation purposes. These facilities also could and did produce a great deal of electricity at very low "real" cost given their primary purposes. Thus, the projects gradually came to be viewed as "multi-purpose" installations - flood control, irrigation, navigation, low cost power production and recreation. They have provided all of these benefits for many years.

The achievement of this multi-purpose concept required that some electrical transmission facilities be constructed. It also created the need for some type of federal agency to market the power from the dams. However, Congress intended to do more with the formation of Bonneville than create a means to sell electricity. It desired to use the Agency to promote the electrification of the more rural areas in the Northwest. This led to both the creation of Bonneville itself and the directive in the Bonneville Power Act and the Flood Control Act to sell the power to public utilities and cooperatives on a preferred basis - and at cost. This was an important concept because the privately owned utilities that were being formed in the Region were not interested in, or were unable to economically justify, serving more rural areas.

Viewed in this early context, certain features of the early Bonneville program that may seem less than sensible today make more sense. For example, the preference and priority principles were typical of federal laws intended to electrify more rural areas. The idea that Bonneville would sell power for no more than cost was consistent with the rural electrification objective. A further example is the idea that Bonneville would be obligated to repay Treasury for the cost of building the dams from electrical sales if possible but would be entitled to "defer" these payments if the Agency was unable to immediately collect enough revenues to pay all of its costs. After all, the dams were being built to accomplish mulitiple purposes. If electrical sales alone were unable to pay all expenses, it was only reasonable that Bonneville would be given some time to come into balance against all of its costs from electrical sales revenues alone.

During these early years, it became apparent that the dams produced more power than was going to be required in the foreseeable future to meet the needs of the public and cooperative utilities. Particularly given the nature of a hydro-electric system, it made no sense to simply waste generating capacity constantly reserving the same for the benefit of only one type of retail customer - the retail customer located in less densely populated areas. Therefore, Bonneville sold power surplus to the needs of the public and cooperative utilities to privately owned utility companies. This allowed the benefits of the dams to be spread to a broader market without compromising the electrification of rural areas objective. It also made it more probable that Bonneville costs would be kept low and the Treasury payments would be made from power sales revenues alone. Everyone won - the rural customers, the investor-owned utilities, their retail consumers and the federal government.

It was a truly winning proposition for the federal government. Three objectives were being accomplished that helped Northwest citizens a great deal - flood control, irrigation and electrification - and the volume of electrical sales were being maximized in order to have such sales pay the full cost of the multi-faceted program, if possible.

During the 1940's and 50's, Bonneville continued to have a surplus of very inexpensive power even given its sales to all utilities in the Bonneville Region - public utilities, cooperative utilities and private utilities. "Preference" really meant very little because the essence of any preferred right is that it is given priority over other demands. In Bonneville's case, supply exceeded demand so that no prioritization was needed. In this respect it should be noted that the federal dams were far from the only generating facilities in the Region. Other very low cost generating facilities, built prior to or contemporaneously with the federal projects, were owned by the investor owned utilities and certain public utilities.

With all of this low cost generation available, certain large industries were attracted to the Northwest to build their primarily aluminum-producing plants. These industries were encouraged to locate in the Northwest. In fact, the idea of producing aluminum with surplus inexpensive power provided what can be referred to as an additional "multi-purpose" use of the Bonneville system - national defense. As the direct service industries began to locate in the Northwest the Columbia River dams became even more justified than had been the case when they served only flood control, irrigation and electrification purposes. Furthermore, it became even more probable that the federal Treasury would be paid back for funding the dams from Bonneville power and transmission sales.

Heading into the mid and late 1960's, the "Bonneville" multi-purpose power and transmission sales program seemed to be extremely successful for both Northwest and national interests. Then, things began to change.

B. The Middle Years - 1960 to 1974

By the mid-60's, there were growing concerns about whether the power available for sale by Bonneville would be sufficient to meet the expected demands. Part of this concern was driven by very high compounding load growth forecasts which resulted from the public and cooperative utilities following Bonneville standards in forecasting future demand.

The perception of future shortages was of great concern to all Bonneville purchasers - preferred customers, investor-owned utilities and the direct service industries. Most of Bonneville’s public body and cooperative utility customers had no resources to use in meeting loads if Bonneville issued a "Notice of Insufficiency" and stopped meeting all demands on an assured basis. Further, these utilities had a clear legal duty under state laws to take all actions reasonably possible to meet all future and forecasted loads.

The investor-owned utilities were also concerned. For one thing, they purchased secondary and non-firm power from Bonneville at very advantageous prices. Like Bonneville, these companies also had the right to sell a significant amount of hydro power. It was becoming very difficult to license and construct new hydro facilities. Therefore, it made sense to build certain large station thermal plants to meet the forecasted demands. This could make more Bonneville and investor-owned hydro resources available to the investor-owned utilities at lower prices. Finally, the investor-owned utilities were aware of developing state curtailment plans that were being considered for adoption by the different Northwest states. These plans would ensure that if one utility was "short" then all utilities in the state would be short.

The direct service industries were extremely concerned with the forecasted shortages. If Bonneville issued a Notice of Insufficiency, the DSIs would be threatened with interruptions to their power supply under the "interruptible" form of their power sales agreements with Bonneville. Furthermore, if Bonneville had a forecasted inability to meet future loads, then Bonneville would be unable to enter into new long term agreements with the DSIs. Since the DSI's had located in the Northwest to take advantage of the lower cost and plentiful power, it was naturally a very serious situation to the DSIs if the power became either scarce or expensive.

Given these joint concerns, Bonneville and its various customers met and evaluated different possible ways to deal with the perceived shortage problem. The negotiated solution was the "Hydro-Thermal Power Program." There were two essential foundations to this program. First, the Northwest Region's power supply future depended on joint action to construct a number of thermal generating stations that would then be operated on a coordinated basis allowing the Region to "base load" the new thermal plants and "peak" with the existing hydro system. Second, all of Bonneville's customers would cooperate to act as "one utility" in accomplishing the first objective.

Bonneville's role in the program was hotly debated. Essentially, the region's utilities did not want Bonneville to become a new TVA. To avoid an unreasonable expansion of Bonneville's powers and expensive and inefficient federal bureaucratic practices, it was agreed that Bonneville would not actually own the new facilities. However, it was essential that Bonneville provide a variety of essential functions if the one utility concept was to work efficiently. 

The Bonneville roles included the following.

1. Bonneville would expand the transmission system in coordination with some of the private utilities as required to accommodate the new thermal facilities.
2. Bonneville would tailor its major power sales agreements with its various customers to best ensure that all beneficiaries of the new program would pay their fair share of the cost of building the new facilities during the operating life of the new plants. 
3. Bonneville would act as a coordinating entity or an "agent" for its preferred and direct service industry customers to accomplish a number of joint goals. These goals included maximizing the cost benefits of marketing power generated from the hydro system if median or high water conditions were experienced as compared to the critical water assumptions that were made in forecasting shortages under the Bonneville load forecasting methodologies. 
4. Bonneville would act in a variety of ways to encourage and expedite the construction of the new thermal plants and to maximize the amount of tax exempt financing available to build the facilities. Bonneville participated in the Hydro Thermal Program in the following ways. 

A. Bonneville continued to coordinate the load forecasts submitted by its preferred and DSI customers under the provisions of their Bonneville power agreements. The forecasts submitted under the Bonneville methodologies continued to show a great need for a large number of new 1000 megawatt power plants although the forecasts subsequently dropped abruptly in 1981, one year after the passage of the Regional Act. These forecasts demonstrating the need for the new thermal power plants were very important to the individuals and entities that invested large sums in the bonds issued to build the plants.  

B. Bonneville suggested various types of agreements for execution by its preferred customers, participated in bond marketing programs with the Washington Public Power Supply System and made it abundantly clear to the preferred customers that a Notice of Insufficiency would have to be issued unless these entities executed "Participants Agreements" for the new facilities in amounts adequate to ensure that the rapidly escalating load forecasts were met through the installation of up to seventeen new 1000 megawatt generating plants. 

C. Bonneville contractually supported the Hydro Thermal Program by the execution of a number of "Net Billing Agreements." In order to construct a large number of thermal plants, it was essential that the credit of the Bonneville system be pledged to bond purchasers. This was a conceptually difficult proposition because, as noted above, Bonneville was not authorized to own any generating facilities in the late 1960's when the Hydro Thermal Program was conceptualized. How could Bonneville provide the primary financial backing for plants it would not own? 

The answer was net billing. Essentially, consumer owned and cooperative utilities would agree to execute capability purchase agreements with plant owners - EWEB for thirty per cent of Trojan and the Supply System for Nuclear Projects Nos. 1, 2 and 3. These agreements obligated the power purchasers (referred to as "Participants") to pay given percentage shares of the total costs of the plants regardless of whether the plants were ever completed, performed at a given level or virtually any other circumstance - that is, "come hell or high water." 

Bonneville participated in this program by agreeing to "net bill" all of the costs which the Participants agreed to pay the plant sponsors. The net billing agreements obligated Bonneville to credit all costs of building the participants' shares of the plants against the Bonneville power bills to the Participants. If a given Participant's Bonneville power bill was not greater or equal to its share of the net billed plant costs, Bonneville agreed to cross assign the surplus costs to another Participant who had a lower Bonneville power bill as compared to its share of the costs. To facilitate these cross assignments, each Participant agreed to "step up" its power purchases by up to twenty-five percent if required to balance the net billed costs with the Bonneville power bills.

Finally, Bonneville agreed to pay the plant owners in cash for any deficiency in the total net billing coverage. Due to the fact that Bonneville was an appropriated agency when these commitments were made, it was necessary that these agreements be placed before Congress in the then yearly appropriation process which determined how much money Congress would make available to Bonneville during a given fiscal year to run the Agency. This was done with each set of net billing agreements and the net billing and Hydro Thermal Program was explained in detail to Congress. 

With these agreements in place, the plant construction program could begin. Millions (and soon billions) dollars of tax exempt bonds were issued under the above-described credit format. However, in the early to mid 1970's it became apparent that the bond market required some further assurances due to the rapidly escalating costs of the new facilities and the fact that the financing program was based on borrowing sufficient funds to pay the interest on the debt incurred to bring the facilities to commercial operation. That is, each bond issuance was based on the need to borrow enough money to pay the projected costs of construction of each net billed facility and to pay the interest on the sums borrowed until the facility became commercially operable. This meant that of each dollar borrowed a certain percentage of the dollar would go to pay the sponsor's overhead costs, a certain percentage would go to pay the interest on the sums that had been and were being borrowed and only the remainder would go to pay the actual physical construction costs. As the costs escalated, the interest rates escalated and the plants were delayed due to design and other regulatory changes, the bond market's appetite for the bonds was placed under significant stress. 

Recognizing this growing problem (which was additionally exacerbated by the concept of also building WPPSS Project 4 and 5 without net billing coverage), Bonneville and its three customer groups (public body and cooperative utilities, DSIs and IOUs) again met in the early 1970's to determine what to do to protect the viability of the Hydro Thermal Program. The result of these meetings was a joint drafting and lobbying effort that culminated in the passage of the Transmission Act in 1974.  

The Transmission Act addressed a number of subjects that were essential to the "one utility" concept and the Hydro Thermal Program. The Act expanded Bonneville's ability to borrow sums to expand and maintain the regional transmission system. It granted Bonneville the ability to act as a "Trust Agent" in buying power to supplement and maximize the joint hydro and thermal capability of the generating system that was to be constructed for the benefit of all regional consumers. This authority also allowed Bonneville to make power purchases to meet the estimated growing demand while the thermal plants were delayed.  

Most importantly, the Transmission Act converted Bonneville from an "appropriated" to a "self-funded" federal agency. As an appropriated agency, Bonneville's ability to pay any cost was subject to whether Congress would appropriate a given amount of money to the Agency in a given year. As a self-funded agency, Bonneville was legislatively authorized to expend the sums raised by Bonneville from power and transmission sales to meet Bonneville's debt obligations. While Congress continued to review Bonneville's budget and various programs on an annual basis, Bonneville was authorized to contractually pledge the revenues in the new Bonneville fund for certain types of expenses. Such a pledge did not constitute a literal full faith and credit commitment of the federal government, but it did at least represent a pledge of all sums in the Bonneville Fund, including both power and transmission revenues. 

One section of the Transmission Act directly addressed the growing financial market concern with the rapidly escalating costs of the new Hydro Thermal Program facilities, principally Supply System Plants Nos 1, 2 and 3. Section 11(b)(6) of the Act provided that Bonneville was authorized to pledge the Bonneville Fund on a priority basis for the payment of costs associated with "capability purchases" made prior to the passage of the Act that had been approved in appropriation processes - that is, the capability purchases of the preferred customers from the Trojan and Supply System Projects.

Following the passage of the Transmission Act, Bonneville wrote the CEO's of both EWEB and the Supply System. A copy of these letters is appended hereto for review by the Transition Board. These letters were widely circulated to the bond markets and were given significant attention by the rating agencies. What was important about the Transmission Act, as explained in the appended letters, was that Bonneville was now authorized without further appropriation action by Congress, to pay the net billed costs in cash on a priority basis from all sums in the Bonneville Fund. It was essential that all sums in the Fund were to be pledged - both power sales revenues and transmission revenues - because the costs of the plants were escalating so rapidly.

Based on the net billing agreements, the referenced provisions of the Transmission Act and the letters and other explanations from Bonneville to the Participants and the bond purchasers, the financing program for the Hydro Thermal Program was again secure. The borrowing and construction efforts proceeded until certain events described below killed most of the new thermal plant construction efforts after more than seven billion dollars of bonds had been issued under the above described security format. 

C. The Regional Act Consideration and Implementation Years - 1974 to 1990

Unfortunately, the problems did not stop with the enactment of the Transmission Act. The new facilities were not being completed even on the revised schedules. (This would have presented an even more serious problem but for the fact that the load growth estimates were also not materializing.) By 1976, Bonneville and the regional utilities and DSIs, operating under the auspices of the Pacific Northwest Utilities Conference Committee, began organizing to evaluate, draft and lobby for the passage of new legislation. This new legislation would give yet more flexibility to Bonneville to expedite the completion of the Hydro Thermal Program and the one utility regional cooperative concept. It would also meet other new concerns that threatened the ability of all of the Region's utilities and DSIs to act cooperatively and collectively. 

What were the concerns that led to the enactment of the Regional Act? The initial problems were different from the issues that were eventually addressed in the legislation as the interested parties grew from just the utilities and DSIs to include the individual states, certain cities and various environmental and other interest groups. The eventual list of problems or objectives included the following.

A. Providing access to the low cost federal hydro power for the domestic and rural consumers of investor-owned as well as consumer and cooperatively owned utilities.

B. Providing new borrowing authority for Bonneville to keep the Hydro Thermal concepts viable and accomplish other objectives such as the improvement of the Regional and extra-Regional transmission systems.

C. Preserve the preference and priority principles while also meeting the objective noted in paragraph A., above.

D. Allowing Bonneville to execute new twenty year sales agreements with all of its customers by 1980, including the DSIs which could not otherwise have received such long term commitments given Bonneville's issuance of the Notice of Insufficiency and the still high and compounding regional load forecasts.

E. Creating a multi-state oversight Council for Bonneville.

F. Funding fish and wildlife, conservation and other non-traditional power and transmission programs coordinated and administered by Bonneville.

G. Securing Bonneville's fiscal integrity and ability to make power purchases to meet the estimated growing loads until the new thermal plants were completed.

The provisions of the Act as eventually adopted encompassed a variety of new roles for Bonneville. The Act also expanded the universe of entities that were tied to the Agency and dependent on the Bonneville revenues to fund their programs. Bonneville was authorized to do many things. However, Bonneville was also given the responsibility to charge for the power and transmission services it provided at a level necessary to meet its yearly "Revenue Requirements." All of these expenses were now Bonneville "costs," and FERC had to determine that the rates would cover the costs, to ensure that the federal treasury payments were made as well as the operation and maintenance costs, the net billed costs, the transmission system costs, the power acquisition costs, the fish and wildlife costs, the experimental resource costs, the conservation costs and the cost of the new Council that would oversee certain Bonneville programs.

The basic way that Bonneville was directed by Congress to proceed was as follows.

A. Bonneville was to execute new twenty year power sales agreements with its preferred customers and with the DSIs.

B. Bonneville was to execute power "Exchange Agreements" with the IOU's.

C. Resource plans and fish and wildlife plans were to be issued by the new Regional Council.

D. Bonneville was to pursue resource and conservation acquisitions consistent with the plans through direct acquisitions, guarantee programs, "billing credit" acquisitions, etc. All of the costs associated with these actions were to be included in the Bonneville rates.

E. Bonneville was directed to fund the fish and wildlife programs consistent with the plans and to raise the sums required to pay these costs in the power and transmission sale rates.

For obvious reasons, the costs were going to increase and they did. The new 1980 power sales agreements did not set twenty year rates. Instead, they obligated the various classes of purchasers to pay the rates established by Bonneville in rate proceedings. These "rate cases" were conducted under very specific rate-setting criteria established in the Act. The negotiations that led to the passage of the Act centered to a great degree on who would pay as well as what would be funded by Bonneville. 

Bonneville was directed to take the following actions in establishing rates. First, Bonneville would estimate its "Revenue Requirements" for the rate period. Second, Bonneville would allocate the power and transmission costs among its various classes of power consumers - public body and cooperative utilities, DSIs and IOUs - according to the priority established in the Bonneville’s organic statutes. Third, if the rates for Bonneville’s public body and cooperative customers were estimated at a level that exceeded limitations incorporated in the Act (the preference customer "rate test"), the preference customers would pay no more than the rate-test limited sums and the other Bonneville customers would pay higher costs (DSIs and other non-preference purchasers such as extra-regional buyers) and the exchange benefits would be reduced, limiting the amount of money that Bonneville would pay the IOU's under the paper exchange intended to pass the benefits of the Bonneville marketed hydro system to all rural and domestic customers in the Region.

The final piece of the puzzle dealt with the priority of payments that would be made by Bonneville to cover its various obligations. This subject was addressed through preserving all Bonneville powers under legislation that preceded the passage of the Regional Act. All pre-existing contractual commitments also remained intact. This meant that Bonneville would meet its total and various obligations in essentially the following manner.

Bonneville would first pay its O&M costs and its net billed obligations on a priority basis. Bonneville would then pay the costs associated with other power purchases, fish and wildlife expenses and debt amortization payments for borrowings made under the Regional Act. As a last priority, Bonneville would make the interest and principal payments to the Federal Treasury, payments that Bonneville had traditionally had the power to defer if the annually appropriated amount of money granted Bonneville by Congress was insufficient to allow Bonneville to meet all of its costs. The primary reason that FERC was given the authority to review the Bonneville rates was to reasonably ensure that sufficient sums would be raised through the sale of all Bonneville goods and services to make the last priority payments from the Bonneville Fund - payments to the Treasury.

With these new powers in hand, Bonneville set about the business of implementing the Regional Act. Bonneville did what it was directed to do. It executed new twenty year power sales and exchange agreements which were negotiated through a series of meetings and public proceedings. It began funding a variety of conservation programs which were also designed and negotiated in a public type of process. It received the conservation and resource and fish and wildlife plans and began acting to implement the same. It made resource acquisitions and continued to fund and support further borrowings to build the net billed facilities. It also paid for a number of efforts to implement fish and wildlife programs.

Eventually, all of this paying for things, however laudable, led to higher power and transmission rates. The net billed plants did not fare well. Only one of the Supply System facilities was completed and even that plant produced electricity at a higher than market or Bonneville system costs. Trojan was completed, operated for 17 years, and then terminated. The fish and wildlife costs continued to increase. Some of the Bonneville resource acquisitions were made at costs far higher than the market prices.

Increased Bonneville power costs unfortunately arrived contemporaneously with passage of the Energy Policy Act of 1992 and its plans for opening wholesale power markets to competition. Suddenly, the world Bonneville had known for almost fifty years had changed. Higher prices and access to alternative suppliers shifted the question from who was entitled to buy Bonneville power to who, if anyone, could avoid buying power at above market prices.

D. The Recent Years - A Struggle to Survive - 1992 to 1997

It is a very difficult task to keep an agency fiscally healthy when it is required to sell goods and services at cost and the costs are higher than market prices. It is also asking a great deal for utilities that face competition for the first time to buy goods or services at a higher cost than are otherwise available. Nonetheless, these two propositions are precisely the hub of the dilemma facing Bonneville and its utility customers.

Does any entity want to pay for the net billed debt? No. Does any utility desire to buy power from Bonneville at a cost which will result in a loss of customers? No. Do the utilities and marketers want to pay more for transmission than the direct cost? No. Do utilities or the DSIs want to be forced to continue to buy power from Bonneville if lower cost alternatives are available? No.

Facing these problems, Bonneville has tried over the last few years to take a number of actions that will resolve the current dilemma for the short term, allowing the Agency to again become competitive over the long term.

A. Bonneville negotiated new terms for the power sales agreements with its DSI customers. Bonneville offered what the DSIs argue are limited or absolute protections from paying for the net billed debt through transition charges. These agreements for power and transmission sales until 2001 resulted in the first round of Bonneville litigation. The initial cases are now under judicial advisement before the Ninth Circuit.

B. Bonneville next negotiated new or amended power sales agreements with most of its preferred customers. These agreements require the "preferred" customers to pay higher than market prices for power until 2001 and more, in fact, than the DSI's. Furthermore, Bonneville refused to grant its preferred customers any relief from stranded investment liability, even to the extent purportedly granted the DSI's.

C. Bonneville agreed in litigation settlements to not impose any stranded investment charges against any entity until it had completed an evidentiary and fact finding proceeding under Section 7(i) of the Regional Act.

D. Bonneville obtained some limitations from Congress on the sums that the Agency will be required to pay in the immediate future for fish and wildlife mitigation efforts.

E. Bonneville has restructured the Treasury debt through Congressional action.

F. Bonneville has participated in certain Regional efforts intended to address its problems on a conceptual basis, leading to the formation of the Transition Board to further advise the Region, the individual states and perhaps Congress on how to resolve the current challenges. One of the recommendations that has emanated from this process is to pursue a "subscription" process which is hoped to result in the traditional Bonneville customers buying power from Bonneville post-2001 for amounts and at sufficient prices to allow Bonneville to meet its post-2001 revenue requirements without implementation of any transition charge.

G. Bonneville has instituted cost cutting measures. The Transition Board has instituted a cost review process designed to reveal areas where further reductions can be made. Bonneville has announced that it seeks to sell power at 20 mills in 2001 - an objective that may bring Bonneville power to a reasonably competitive level before new power sales contracts must be executed.

H. Bonneville has obtained expanded authorities to sell power outside of the Region, increasing its ability to offer contract terms and prices that will be more appealing to extra-regional buyers that can infuse revenues into the Bonneville system.

I. Bonneville has and continues to invite and consummate transactions with plant sponsors and utilities that will eliminate or lower the cost of resource acquisitions made following the passage of the Regional Act. Some of these efforts have resulted in significant cost savings, working toward the goal of lower costs to meet the presently low market. 

While some entities will argue that Bonneville's efforts are insufficient or meager, the fact is that the Agency is trying to act. If Bonneville power can be made attractive given the developing competitive market, that is certainly the best solution. It would lead to yet another swing of the pendulum - the argument could again be how much Bonneville power am I entitled to buy rather than how much must I buy.