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Washington Law Review

April, 1983

**Symposium on Energy Issues in the Pacific Northwest**

**\*317** THE PATH ALONG THE RIDGE: REGIONAL PLANNING IN THE FACE OF
UNCERTAINTY

[]{#Document0zzFN_B1 .anchor} [[\[FN1\]]{.underline}](#Document0zzFN_F1)

Kai N. Lee [[]{#Document0zzFN_Ba
.anchor}[\[FNa\]]{.underline}](#Document0zzFN_Fa)

Copyright 1983 by the Washington Law Review Association; Kai N. Lee

The Northwest Power Act [[]{#Document0zzFN_B2
.anchor}[\[FN2\]]{.underline}](#Document0zzFN_F2) responds to the
changing circumstances of electric power in the Pacific Northwest by
defining policy directions and creating new institutional arrangements
for regional power planning. [[]{#Document0zzFN_B3
.anchor}[\[FN3\]]{.underline}](#Document0zzFN_F3) The Northwest Power
Planning Council (Council) is the agent of the region in meeting the
challenges of planning under the Act. [[]{#Document0zzFN_B4
.anchor}[\[FN4\]]{.underline}](#Document0zzFN_F4) This paper discusses
the conceptual framework of regional power planning\--a task that
confronts a degree of uncertainty and risk without historical precedent.

For a quarter-century, electricity demand grew rapidly in the Northwest,
doubling roughly every ten years. [[]{#Document0zzFN_B5
.anchor}[\[FN5\]]{.underline}](#Document0zzFN_F5) This growth was
readily met by the low-cost, abundant supply of hydroelectric energy
developed by the federal government and Northwest utilities in the
Columbia River and its tributaries. []{#Document0zzFN_B6 .anchor}
[[\[FN6\]]{.underline}](#Document0zzFN_F6) Steady growth made for simple
planning: build more for a **\*318** brighter tomorrow. When the
potential of the region\'s rivers was fully harnessed,
[[]{#Document0zzFN_B7 .anchor}[\[FN7\]]{.underline}](#Document0zzFN_F7)
it seemed sensible to turn to nuclear [[]{#Document0zzFN_B8
.anchor}[\[FN8\]]{.underline}](#Document0zzFN_F8) and coal: supplies
that promised to facilitate further growth at higher\--but still
reasonable\--cost. But, even as the Northwest Power Act was emerging
from Congress, the era of steady growth ended, a victim of rising power
costs and an unstable economy.

There are no facts about the future: predicting energy demand is an
uncertain and risky enterprise. If the growth rate differs by only 0.3%
per year from the anticipated rate, the gap between the anticipated load
and actual load will amount to the equivalent of a nuclear plant in less
than fifteen years. []{#Document0zzFN_B9 .anchor}
[[\[FN9\]]{.underline}](#Document0zzFN_F9) Our present ability to
forecast demand falls considerably short of even this 0.3% criterion.
[[]{#Document0zzFN_B10
.anchor}[\[FN10\]]{.underline}](#Document0zzFN_F10) It now takes several
billion dollars and more than ten years to plan and build a major power
plant. [[]{#Document0zzFN_B11
.anchor}[\[FN11\]]{.underline}](#Document0zzFN_F11) The costs to the
economy of not having enough power are similarly huge.
[[]{#Document0zzFN_B12
.anchor}[\[FN12\]]{.underline}](#Document0zzFN_F12)

The planning problem is thus a daunting one: the best one can do with
current methods seems to entail major risks of either building too much
or **\*319** too little, with heavy penalties either way.
[[]{#Document0zzFN_B13
.anchor}[\[FN13\]]{.underline}](#Document0zzFN_F13) In the image of Dan
Evans, chairman of the Power Planning Council, the Northwest is walking
along a narrow ridge: we can ill afford missteps, but we cannot see as
far as we stride. Thus, developing a regional plan goes beyond selecting
resources for acquisition by the Bonneville Power Administration: it
must also include thinking about how resources should be acquired,
together with careful consideration of what kind of resources are
suitable for responsible planning in the face of uncertainty. This
article seeks to stimulate discussion of how to do this better.

I. THE UNCERTAIN ENVIRONMENT

From the late 1940\'s until approximately 1970, demand for electricity
in the United States grew in parallel with the gross national product.
This growth reflected the fact that electric power was a good buy. Not
only was electricity convenient, but the real cost of supplying power
steadily declined, as new technology captured economies of scale.
[[]{#Document0zzFN_B14
.anchor}[\[FN14\]]{.underline}](#Document0zzFN_F14) In the Northwest,
the dominant resource was (and remains) hydropower, developed on a large
scale since the federal government launched Grand Coulee Dam during the
New Deal. []{#Document0zzFN_B15 .anchor}
[[\[FN15\]]{.underline}](#Document0zzFN_F15) Northwest hydro projects,
built during an era of low construction costs and low interest
rates\--often backed by the federal government\--produced the cheapest
electricity in the nation. [[]{#Document0zzFN_B16
.anchor}[\[FN16\]]{.underline}](#Document0zzFN_F16) In this setting,
vigorous growth in power production was socially rational: overall
economic growth would not be constrained by power shortages; the advance
of technology meant that new supplies would lower the average system
cost as cheaper sources were brought on line; and the growth of demand
in neighboring regions, especially California and the Southwest,
provided markets for Northwest surpluses.

As steady economic growth gave way in the 1970\'s to stagflation and
energy crisis, the conditions underlying utility planning changed.
[[]{#Document0zzFN_B17
.anchor}[\[FN17\]]{.underline}](#Document0zzFN_F17) Planning **\*320**
should have changed too, but it lagged, [[]{#Document0zzFN_B18
.anchor}[\[FN18\]]{.underline}](#Document0zzFN_F18) with serious
consequences for utilities and their ratepayers. Seven conditions now
shape the future:

1\. Federal sponsorship [[]{#Document0zzFN_B19
.anchor}[\[FN19\]]{.underline}](#Document0zzFN_F19) remains limited in
reach. Despite the regional authority [[]{#Document0zzFN_B20
.anchor}[\[FN20\]]{.underline}](#Document0zzFN_F20) to acquire resources
under the Act, the initiative still rests with utilities, local
governments, and other project sponsors. [[]{#Document0zzFN_B21
.anchor}[\[FN21\]]{.underline}](#Document0zzFN_F21)

2\. The marginal cost of power is rising, [[]{#Document0zzFN_B22
.anchor}[\[FN22\]]{.underline}](#Document0zzFN_F22) but both the cost
and the output of a given project remain uncertain.
[[]{#Document0zzFN_B23
.anchor}[\[FN23\]]{.underline}](#Document0zzFN_F23) The troubles of the
Washington Public Power Supply System [[]{#Document0zzFN_B24
.anchor}[\[FN24\]]{.underline}](#Document0zzFN_F24) have drawn attention
to rising rates. [[]{#Document0zzFN_B25
.anchor}[\[FN25\]]{.underline}](#Document0zzFN_F25)

3\. Conservation entails the stimulation and coordination of activities
undertaken by thousands of individuals and firms. [[]{#Document0zzFN_B26
.anchor}[\[FN26\]]{.underline}](#Document0zzFN_F26) The utilities have
had relatively little experience with conservation or decentralized
sources of supply, and both planning and regulatory oversight have been
hesitant and often confused.

4\. Although the Northwest has a strong tradition of public utility
ownership, [[]{#Document0zzFN_B27
.anchor}[\[FN27\]]{.underline}](#Document0zzFN_F27) the open planning
process created in the Northwest Power Act [[]{#Document0zzFN_B28
.anchor}[\[FN28\]]{.underline}](#Document0zzFN_F28) is unfamiliar and
uncomfortable for the utilities, especially during the period of
adjustment to the institutional arrangements and processes created in
the Act. Openness and a complex agenda make the planning process
difficult for the Council to manage as well.

**\*321** 5. Forecasting demand [[]{#Document0zzFN_B29
.anchor}[\[FN29\]]{.underline}](#Document0zzFN_F29) has become
extraordinarily difficult. [[]{#Document0zzFN_B30
.anchor}[\[FN30\]]{.underline}](#Document0zzFN_F30) Where the smooth and
rapid growth of the 1950\'s and 1960\'s allowed planners simply to
extrapolate historical behavior, the period beyond the mid-1970\'s
continues to be elusive, despite ever more sophisticated methods of
analyzing past demand patterns. [[]{#Document0zzFN_B31
.anchor}[\[FN31\]]{.underline}](#Document0zzFN_F31)

**\*322** 6. Large, capital-intensive resource projects now pose
substantial risks. Costs and schedules have been difficult to control.
[[]{#Document0zzFN_B32
.anchor}[\[FN32\]]{.underline}](#Document0zzFN_F32) Moreover, with the
slowing of load growth, arrangements for fully utilizing large
facilities have become unexpectedly important. [[]{#Document0zzFN_B33
.anchor}[\[FN33\]]{.underline}](#Document0zzFN_F33)

7\. A consequence of the last two points is that commitments to large
resources a decade or more in advance\--standard practice now\--are no
longer tenable without substantial change.

Despite the explosion of uncertainty\--indeed, because of it\--it is
more urgent than ever to plan and to share risks regionally.
[[]{#Document0zzFN_B34
.anchor}[\[FN34\]]{.underline}](#Document0zzSDUNumber41) A central
feature of the Northwest Power Act is the ability to plan a
cost-effective mix of resources on a regional basis.
[[]{#Document0zzFN_B35
.anchor}[\[FN35\]]{.underline}](#Document0zzFN_F35) The uncertainties
listed above imply a need for regional risk management as well\--a
process for insuring long term cost-effectiveness in the face of
uncertainty.

II\. PRINCIPLES FOR MANAGING RISK

Regional planning can be organized around eight principles, several of
which are drawn directly from the Northwest Power Act. These principles
form a coherent framework for dealing with the uncertainties facing the
Pacific Northwest. To facilitate exposition, they are first listed
briefly:

1\. In place of deterministic planning, there should be a regional
risk-management process [[]{#Document0zzFN_B36
.anchor}[\[FN36\]]{.underline}](#Document0zzFN_F36) that stresses
flexibility.

2\. In particular, the planning process should prepare the region to
meet a **\*323** wide range of loads in all the years encompassed by the
plan, instead of relying upon a most-likely demand forecast.
[[]{#Document0zzFN_B37
.anchor}[\[FN37\]]{.underline}](#Document0zzFN_F37)

3\. The regional plan should shift the burden of risk from individual
project proponents to the region as a whole, as a form of regionwide
insurance. [[]{#Document0zzFN_B38
.anchor}[\[FN38\]]{.underline}](#Document0zzFN_F38)

4\. The Act establishes fundamental priorities for resource planning:
[]{#Document0zzFN_B39 .anchor}
[[\[FN39\]]{.underline}](#Document0zzSDUNumber42) to minimize expected
cost, while giving priority, first, to conservation; second, to
renewable resources; third, to resources utilizing waste heat or
generating methods of high fuel conversion efficiency; and fourth, to
\'all other resources.\' [[]{#Document0zzFN_B40
.anchor}[\[FN40\]]{.underline}](#Document0zzFN_F40)

5\. The Northwest Power Act also creates an institutional structure for
decentralized implementation of a centrally written plan.
[[]{#Document0zzFN_B41
.anchor}[\[FN41\]]{.underline}](#Document0zzFN_F41)

6\. In place of the conventional bias toward economies of scale in power
generation, planners should search for cost-effective combinations of
conservation and resources that can provide planning flexibility. When
comparing projects that are equally costly to the region, those
available on short notice should be given priority over those with long
lead-times; small projects should be preferred to large ones; and
programs that can be slowed, halted, or reversed should be more useful
than those entailing inflexible commitments.

7\. The planning process should manage the burdens of financing,
licensing, and institutional change by making regional commitments on a
schedule that reflects the slower load growth that characterizes a
period of rising real rates.

8\. The integrated hydro system has been augmented with thermal
generation developed on a piecemeal basis. The Northwest Power Act\--and
the risk- management approach in particular\--implies a substantially
more complex regional power system, [[]{#Document0zzFN_B42
.anchor}[\[FN42\]]{.underline}](#Document0zzFN_F42) one encompassing
activities and actors unfamiliar to the utility community.
[[]{#Document0zzFN_B43
.anchor}[\[FN43\]]{.underline}](#Document0zzFN_F43) The challenge of
this additional complexity must be taken seriously in the planning
process. []{#Document0zzFN_B44 .anchor}
[[\[FN44\]]{.underline}](#Document0zzFN_F44)

**\*324** The paradox of regional planning and decentralized execution
can be resolved in two somewhat different, but complementary, ways.
[[]{#Document0zzFN_B45
.anchor}[\[FN45\]]{.underline}](#Document0zzFN_F45) First, there should
be liberal use of markets and market-like incentives.
[[]{#Document0zzFN_B46
.anchor}[\[FN46\]]{.underline}](#Document0zzFN_F46) Second, and plan and
planning process should be instruments of political leadership,
articulating purposes [[]{#Document0zzFN_B47
.anchor}[\[FN47\]]{.underline}](#Document0zzFN_F47) and mobilizing the
energies of the diverse interests whose partly independent activities
constitute the implementation of the plan. Decentralized execution will
not be easy to achieve, but there is an important opportunity for
Council leadership in the fact that the economic interests of the region
parallel the goals of the Act.

The shift from deterministic planning to regional risk management is
fundamental. This article focuses on planning, but a flexible approach
implies significant changes in the way that projects are developed and
**\*325** programs managed. Regional risk management also requires
coordination of operations with planning, [[]{#Document0zzFN_B48
.anchor}[\[FN48\]]{.underline}](#Document0zzFN_F48) in order to permit
adjustment of both plans and operational policies to respond to emerging
conditions. [[]{#Document0zzFN_B49
.anchor}[\[FN49\]]{.underline}](#Document0zzFN_F49)

The broad ramifications of a risk-management philosophy should not
obscure its essential simplicity, however. Faced with uncertainty, the
planner seeks two critical attributes: diversification
[[]{#Document0zzFN_B50
.anchor}[\[FN50\]]{.underline}](#Document0zzFN_F50) and the ability to
adapt to changing conditions. Flexibility and diversity are
well-accepted notions in finance, where the sharp economic fluctuations
of the past decade have underscored their value.

A planning concept that provides flexibility in the utility context is
the resource option. [[]{#Document0zzFN_B51
.anchor}[\[FN51\]]{.underline}](#Document0zzFN_F51) The Act provides a
mechanism for regional acquisition of conservation and generating
resources. [[]{#Document0zzFN_B52
.anchor}[\[FN52\]]{.underline}](#Document0zzFN_F52) A resource option is
an acquisition contract that explicitly provides for regional control of
the timing and magnitude of the project.

It is important to distinguish our use of the word \'option\' from the
similar- sounding term \'option to purchase \[a share of a generating
project\]\' commonly used in the utility industry. In this article, an
option is a contract between the administrator of BPA and a project
proponent which **\*326** reserves to the administrator certain rights
to alter the schedule on which the project is built or implemented. This
contract also spells out a timetable for payments to the project sponsor
from BPA, payments to meet the costs of the project as well as certain
of the opportunity costs borne by the project sponsor.
[[]{#Document0zzFN_B53
.anchor}[\[FN53\]]{.underline}](#Document0zzFN_F53) In some instances,
the lead-time for undertaking a project is a good deal shorter than the
period between the present and the date at which the resource is
expected to be a cost-effective element of the regional power supply.
Resources meeting this combination of criteria, so-called \'planned
options,\' [[]{#Document0zzFN_B54
.anchor}[\[FN54\]]{.underline}](#Document0zzFN_F54) can be scheduled in
the Council\'s plan without a corresponding effort by BPA to initiate a
contract for acquisition. These planned but not yet purchased options
should, in general, be treated as less definite resource alternatives
than projects for which a contract has been signed.

In order to be usable in planning, an option can be no less real than
any other resource in the plan. [[]{#Document0zzFN_B55
.anchor}[\[FN55\]]{.underline}](#Document0zzFN_F55) The experience of
the last fifteen years indicates that resource plans regarded by the
utilities as \'real\' cannot be counted on. [[]{#Document0zzFN_B56
.anchor}[\[FN56\]]{.underline}](#Document0zzFN_F56) If the regional
planning process cannot improve upon this **\*327** record,
[[]{#Document0zzFN_B57
.anchor}[\[FN57\]]{.underline}](#Document0zzFN_F57) one of the main
hopes in the Northwest Power Act will have been dashed. Thus, if there
are unresolved technical questions, such as the feasibility of stack-gas
scrubbers on coal plants, [[]{#Document0zzFN_B58
.anchor}[\[FN58\]]{.underline}](#Document0zzFN_F58) a credible research
and development program should be underway to settle them. If there are
uncertainties in cost and schedule, these must be managed on the same
basis for an option as for an acquired resource. [[]{#Document0zzFN_B59
.anchor}[\[FN59\]]{.underline}](#Document0zzFN_F59) If there are
institutional hurdles, such as approval of a site by a state licensing
authority, these must be addressed in a timely fashion whether the
project is an option or an acquired resource. [[]{#Document0zzFN_B60
.anchor}[\[FN60\]]{.underline}](#Document0zzFN_F60) In short, a resource
option should be no different from an acquired resource except in the
way it is handled by the BPA and the Council.

An option is treated differently by the region in two respects. First,
the option agreement would authorize BPA and the Council to accelerate,
delay, or cancel the project, as part of a cost-effective regional power
program. The early stages of developing a conservation program or
generating resource are typically far less costly than the construction
or implementation phase, []{#Document0zzFN_B61 .anchor}
[[\[FN61\]]{.underline}](#Document0zzFN_F61) while taking up a sizable
fraction of the total time needed for development.
[[]{#Document0zzFN_B62
.anchor}[\[FN62\]]{.underline}](#Document0zzFN_F62) An option agreement
might therefore schedule **\*328** a regional decision on whether to
proceed, and how rapidly to do so, before construction begins.

A second way that the region treats an option differently from an
acquired resource is that the project sponsor may be compensated for the
risk that the project will be rescheduled or terminated. An option is a
form of insurance to the region, since it improves the ability of the
regional planning process to meet a range of loads.
[[]{#Document0zzFN_B63
.anchor}[\[FN63\]]{.underline}](#Document0zzFN_F63) Risk payments to the
sponsor are insurance premiums. [[]{#Document0zzFN_B64
.anchor}[\[FN64\]]{.underline}](#Document0zzFN_F64)

Regional resource options are an important means of improving the
flexibility of planning, but there are additional ways to do so.
[[]{#Document0zzFN_B65
.anchor}[\[FN65\]]{.underline}](#Document0zzFN_F65) For example,
existing generating projects can be operated beyond their normal
capacity for short periods. [[]{#Document0zzFN_B66
.anchor}[\[FN66\]]{.underline}](#Document0zzFN_F66) Smaller projects and
resources available on short lead-times make it easier to respond to
changing circumstances. Conservation seems unusually flexible because
the size of the resource can be adjusted; if loads grow more rapidly
than anticipated, a more aggressive, and expensive, conservation effort
can be pursued with little lead-time, if this possibility has been
planned for. Renewable resource projects promote flexibility as well,
[]{#Document0zzFN_B67 .anchor}
[[\[FN67\]]{.underline}](#Document0zzFN_F67) when they are smaller than
thermal projects. Some uncertainty remains, however, on two points: the
quantity of conservation [[]{#Document0zzFN_B68
.anchor}[\[FN68\]]{.underline}](#Document0zzFN_F68) and renewable
resources that can be developed at cost-effective levels; and the
credibility of schedules for developing such projects.
[[]{#Document0zzFN_B69
.anchor}[\[FN69\]]{.underline}](#Document0zzFN_F69)

It is also worth noting that large central-station plants can be made
more flexible through institutional changes, including option
arrangements. []{#Document0zzFN_B70 .anchor}
[[\[FN70\]]{.underline}](#Document0zzFN_F70) Obtaining approval for
sites and for engineering designs is a **\*329** time-consuming part of
a power plant project. If sites and licenses can be approved and then
\'banked,\' to be used for full-scale development later, the lead-time
for large projects can be substantially shortened.
[[]{#Document0zzFN_B71
.anchor}[\[FN71\]]{.underline}](#Document0zzFN_F71) Similarly, marketing
part or all the output of a power station to utilities outside the
Northwest decreases the effective size of the commitment shouldered by
the region. [[]{#Document0zzFN_B72
.anchor}[\[FN72\]]{.underline}](#Document0zzFN_F72) If these marketing
arrangements include contingency arrangments, perhaps along the lines of
the call-back provisions in the Canadian Storage Power Exchange,
[[]{#Document0zzFN_B73
.anchor}[\[FN73\]]{.underline}](#Document0zzFN_F73) both size and timing
can be made flexible. Regional control of banked sites and callback
options enhances the risk-management capability. Finally, flexible
arrangements for providing power in the Northwest may be obtainable from
sources outside the region: the spot market in wholesale power; purchase
on contract; and power exchange agreements have been used by individual
utilities in the past. [[]{#Document0zzFN_B74
.anchor}[\[FN74\]]{.underline}](#Document0zzFN_F74)

In addition, there are institutional arrangements with consumers that
can improve planning flexibility. For instance, rate schedules that are
implemented only when a shortage looms can be used to hold down demand
on short notice, [[]{#Document0zzFN_B75
.anchor}[\[FN75\]]{.underline}](#Document0zzFN_F75) if loads surge
unexpectedly or supplies sag. [[]{#Document0zzFN_B76
.anchor}[\[FN76\]]{.underline}](#Document0zzFN_F76) Such contingent
rates would require advance approval by public utility commissions,
however, to make them usable as regional options. The fact that secure
power supply is more valuable to some industrial customers than others
[[]{#Document0zzFN_B77
.anchor}[\[FN77\]]{.underline}](#Document0zzFN_F77) can form the basis
for a futures market, [[]{#Document0zzFN_B78
.anchor}[\[FN78\]]{.underline}](#Document0zzFN_F78) in which costly
resources can be developed on behalf of those willing to bear the risk
of paying for them in order to assure supply. Conversely, there may be
consumers **\*330** willing to purchase interruptible power,
[[]{#Document0zzFN_B79
.anchor}[\[FN79\]]{.underline}](#Document0zzFN_F79) who have not had
access to lower- quality power in the past; their purchases can provide
peak-load reserves and flexibility in planning.

The flexible, risk-managing approach differs from deterministic planning
in one important economic respect: risk management does not minimize
short-run costs. [[]{#Document0zzFN_B80
.anchor}[\[FN80\]]{.underline}](#Document0zzFN_F80) But if the future is
really uncertain, a flexible combination of projects can lead to much
lower costs than a least-cost investment that turns out to be based upon
mistaken assumptions. [[]{#Document0zzFN_B81
.anchor}[\[FN81\]]{.underline}](#Document0zzFN_F81) The concept of
portfolio diversification\--not putting all one\'s eggs in the same
basket\-- embodies the same risk-managing philosophy. A diversified
portfolio may not earn the maximum return, but it greatly decreases the
probability of substantial losses. [[]{#Document0zzFN_B82
.anchor}[\[FN82\]]{.underline}](#Document0zzFN_F82)

Of course, one can hedge one\'s bets foolishly as well as wisely.
Regional risk management is not self-implementing. But the deterministic
approach, in the face of the uncertainties that confront the region, may
guarantee failure. Putting these principles into a workable planning
process will require technical, organizational, and governmental
changes. As a first step it may be sensible to consider a deliberately
oversimplified example of how a regional plan could be more flexible.

III\. AN EXAMPLE OF FLEXIBLE PLANNING

In conventional utility forecasting the objective is to estimate as
accurately as possible the future demand for electric power. A common
approach is to make high, low, and intermediate forecasts, using
different demographic variables and assumptions about consumer response
to rate changes; typically, the intermediate forecast is selected as the
planning target. [[]{#Document0zzFN_B83
.anchor}[\[FN83\]]{.underline}](#Document0zzFN_F83) When uncertainty is
high, however, there may be insufficient information to identify an
appropriate intermediate case. That is, the region may have to meet a
demand for power ten or twenty years in the future that can lie anywhere
within a broad range. It is reasonable to think, however, that one can
still identify a broad range within which demand is expected to lie;
[[]{#Document0zzFN_B84
.anchor}[\[FN84\]]{.underline}](#Document0zzFN_F84) the question for
planning is how to use this information.

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**\*331** Figure 1 shows a pair of schematic demand forecasts. They are
limiting cases, chosen on the basis of a consensus within the
forecasting community [[]{#Document0zzFN_B85
.anchor}[\[FN85\]]{.underline}](#Document0zzFN_F85) that actual demand
will lie between the lower and upper bound forecasts. Regional risk
management proceeds this way:

1\. The regional plan must assure that resources are adequate in each
year of the planning period to meet the lower bound forecast demand.
This requires resource acquisitions.

2\. The regional plan must also assure that a combination of resources
and options is available to meet the upper bound forecast in each year
of the planning period. This requires development and acquisition of
options, as well as resources.

3\. In order to be included in the plan, an option must meet standards
developed by the Council. These standards should insure that the option
can, in fact, be converted into a resource by the year in which it is
listed.

4\. A regional plan developed in this fashion must be reviewed
frequently\-- perhaps annually\--so that the mix of options and
resources acquired can be adjusted in light of new information.
Important kinds of new information **\*332** include changes in the
existing power system; revised lower and upper bound forecasts; data on
costs and schedules of resources acquired; data on the costs of options
and their availability for the year planned; and new resources and
options developed since the last review.

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How does one fill in the V-shaped space between the lower and upper
bound forecasts? [[]{#Document0zzFN_B86
.anchor}[\[FN86\]]{.underline}](#Document0zzFN_F86) Figure 2
demonstrates an approach for a single target **\*333** year. Looking at
the target year from the vantage of the planning year in Figure 2, the
planner ranks resource possibilities in order of increasing expected
cost. [[]{#Document0zzFN_B87
.anchor}[\[FN87\]]{.underline}](#Document0zzFN_F87) The resource
possibilities vary in size, but when assembled they span the range from
resources in being\--the regional system projected for the target
year\--to beyond the upper bound forecast.

Lead times for these resources vary. Some projects have already been
optioned or acquired in earlier planning years, though more are needed
to reach the lower bound forecast. Some projects do not need to be
started yet, such as Project 1. In three cases\--Projects, 2, 3, and
6\--a decision must be made in the current planning year. The
risk-management process concentrates on these decisions.

Project 1 does not have to be examined in detail, even though, among
resources available in the target year, it is expected to be lowest in
cost. An acquisition decision has tobe made on Project 2, however.
Situations like this illustrate the trade off between cost-effectiveness
and flexibility. [[]{#Document0zzFN_B88
.anchor}[\[FN88\]]{.underline}](#Document0zzFN_F88) If Project 2 is
acquired, an irreversible commitment will have been made before the
region has purchased lower-cost power from Project 1. The dilemma is
that the planning process cannot wait for the Project 1 decision point,
for Project 2 would no longer be available, and higher cost resources,
such as Project 5, might then have to be developed. How should one value
Project 2? There is, unfortunately, no simple method for gauging the
relative value of flexibility and cost.

For this reason, among others, the design of the regional energy plan is
necessarily a task requiring judgment by the Council. Even whether to
acquire Project 2 is a choice that can be illuminated through analysis.
For example, it is possible to compare the implications of acquisition
and deferral of this project. Pulling Project 2 out of the resource
stack\--the result if the project is not acquired\--would necessitate
the addition of more resource possibilities, higher in cost than Project
6, so that the range between **\*334** lower and upper bound forecasts
is still covered. At the same time, deciding not to acquire Project 2
could mean that it remains available for development in a later target
year, though probably at higher cost. On the other hand, if load growth
falls in the low part of the range, foregoing acquisition can lead to a
lower cost regional system.

Note that Project 2 has a decision point for an option after it is
acquired. This indicates the possibility of a sales option: a
contractual agreement with a wholesale power purchaser for sales
beginning in the target year. A sales option protects the possibility of
selling power at a given price. The sales-option decision can be
scheduled just before the bulk of the money is spent on construction,
thus providing an opportunity to evaluate progress. If a sales option
can be obtained by that time, the region can proceed, knowing that there
is an assured market for part of the Project when it comes on line in
the target year. At the same time, an option to sell decreases one\'s
flexibility, since the option is likely to include an assurance that the
power will be available to sell in the target year. Without such an
assurance, the price of the option would probably be so high that the
Northwest would gain little from having it.

Project 3, like Project 1, provides the possibility of a purchase
option: an agreement to initiate a project with regional financing,
subject to review at the point labeled \'A.\' The point of no return,
economically speaking, occurs soon after the acquisition decision.
Project 4 was optioned in an earlier planning year, and the final
acquisition decision is still some way off; no decisions need to be made
in the current planning year. Note, however, that information obtained
since the last planning year may have shifted the costs and schedule of
Project 4; its position in the stack may thus be different from a year
earlier.

Project 5 is also a resource possibility for which no decision need be
made. It is high enough in the cost stack, however, that, on the basis
of current information, a future sales option may not allow the
Northwest to recover the full cost of the project. This information
clearly has a significant bearing on the acquisition decision. Finally,
Project 6 requires an option decision in the current planning year. As
with Project 2, payment to keep Project 6 available will have to be made
this year, despite its relatively unfavorable position in the
cost-effectiveness stacking. The questions that arose earlier in the
discussion of Project 2 are thus relevant. The answers to these
questions may be different, however; both the high expected cost of
Project 6 and the fact that a sales option may be difficult to arrange
decrease its desirability.

These resource possibilities have been discussed schematically,
Important considerations have been slighted in this example, including
the geographical location of the projects, how they fit into thepriority
classes **\*335** mandated by the Northwest Power Act,
[[]{#Document0zzFN_B89
.anchor}[\[FN89\]]{.underline}](#Document0zzFN_F89) and the operational
characteristics of the overall resource mix [[]{#Document0zzFN_B90
.anchor}[\[FN90\]]{.underline}](#Document0zzFN_F90) if these projects
were to be acquired. These complications matter, of course, and would
need to be analyzed in detail, using information developed by BPA, the
Council, the utilities, and other project sponsors and analysts.

It must also be stressed that the regional risk management process is a
dynamic one. As new information comes in about resources and about the
outlook for demand, it should be used to adjust plans and commitments.

Consider what is likely to happen in the next planning year. There is
now more information about each target year, though it is still
incomplete. Upper and lower bound forecasts have shifted; usually, the
distance between upper and lower bounds will have narrowed, since each
target year is now closer to the point of the V. [[]{#Document0zzFN_B91
.anchor}[\[FN91\]]{.underline}](#Document0zzFN_F91) Second, the expected
resources in being may have changed; changes in one target year affect
the resources in being in later years. Third, the costs, sizes, and
availability of resource possibilities have changed; projects that have
been delayed are no longer available in the original target year. This
plethora of alterations illustrates the need for frequent review of the
plan.

Regional risk management emphasizes the development of options. Resource
possibilities whose costs remain in the cost-effectiveness range spanned
by the upper and lower bound forecasts are likely to be acquired at some
point, though slow demand growth may delay them for a time. On the other
hand, if the economics of power supply change dramatically, an option
may be priced out of the evolving market. For instance, federal hydro
projects introduced an extremely low cost resource to the Northwest,
lowering the cost of electricity substantially; the escalating cost of
Projects 4 and 5 of the Washington Public Power Supply System, in
contrast, undermined their viability in the regional market.
[[]{#Document0zzFN_B92
.anchor}[\[FN92\]]{.underline}](#Document0zzFN_F92)

The risk management approach also uses the information produced by
forecasting in a novel way. The stress now lies on using the bounding
estimates to define the range of resources and options needed in each
target year. The traditional reliance on best-estimate forecasts has
meant that high and low cases were selected casually. There is
considerable room for improvement in choosing defensible upper and lower
bound forecasts. Asking experienced forecasting modelers for consensus
judgments on in put data [[]{#Document0zzFN_B93
.anchor}[\[FN93\]]{.underline}](#Document0zzFN_F93) is a first step:
what is the range within which the population **\*336** trend is nearly
certain to lie? How much and little can electric energy users respond to
changes in rates? Additional information comes from analyses of the
relative costs of over- and under-building. A power shortfall of, say,
300 megawatts does not have the same impact as a 3000-megawatt surplus.
[[]{#Document0zzFN_B94
.anchor}[\[FN94\]]{.underline}](#Document0zzFN_F94) One could choose
bounding forecasts so that the upper and lower bounds reflect equivalent
costs to the regional economy. [[]{#Document0zzFN_B95
.anchor}[\[FN95\]]{.underline}](#Document0zzFN_F95) More generally,
using economic forecasting to set limits for planning is a more modest
task than identifying a precise target. There is reason to hope that
approaches such as those sketched here would lead to estimates that are
more scientifically sound and less burdened by political ideology.
[[]{#Document0zzFN_B96
.anchor}[\[FN96\]]{.underline}](#Document0zzFN_F96)

In sum, the schematic risk management approach illustrated here replaces
the concept of a single best forecast with an iterative three step
process: []{#Document0zzFN_B97 .anchor}
[[\[FN97\]]{.underline}](#Document0zzFN_F97)

1\. Use the best forecasting data and methods available to project the
highest and lowest plausible cases. These upper and lower bound
forecasts should reflect a range of demand broad enough that the actual
demand can be confidently assumed to fall between the bounds.

2\. Develop a stack of resource possibilities to fill the span between
the lower and upper bounds for each year in the plan. The region should
retain the right to delay acquisition in light of additional information
about expected costs and demand. Options to sell part of the output of
large facilities, together with purchase options\--regional financing of
project initiation costs\--can facilitate the development of resource
possibilities while retaining flexibility.

3\. Make decisions as necessary on resource possibilities, so that there
will be resources acquired to meet the lower bound forecast, and so that
there will be a combination of resources and options capable of covering
demand **\*337** ranging as high as the upper bound forecast in each
target year. Acquisitions should be made following the
cost-effectiveness and resource priorities set forth in the Northwest
Power Act.

Regional risk management brings to the fore the question of whether it
is possible to put a great deal more flexibility into the acquisition
process. Before discussing some of the practical issues raised by the
idea of options, one should pause to observe that flexibility may not be
desirable in all cases, nor may it be obtainable on favorable terms.
First, electric power planning does not take place in a vacuum; there
are costs and benefits to others, and these costs and benefits depend
upon how utility resources are scheduled. For example, Northwest
electroprocess industries invest large sums in capital equipment on the
assumption that power will be available to utilize it. The Northwest
Power Act recognizes the value of secure supply to the direct-service
industrial customers. [[]{#Document0zzFN_B98
.anchor}[\[FN98\]]{.underline}](#Document0zzFN_F98) More generally,
flexible, risk-oriented planning benefits some and imposes risks and
costs on others but our understanding of the distributive effects of a
new planning method is necessarily limited. [[]{#Document0zzFN_B99
.anchor}[\[FN99\]]{.underline}](#Document0zzFN_F99)

Second, a flexible, incremental approach encounters the problem of
\'second best.\' [[]{#Document0zzFN_B100
.anchor}[\[FN100\]]{.underline}](#Document0zzFN_F100) Incremental
decisions, each of which is rational, may lead to a suboptimal outcome.
Second best is the economists\' version of the road paved with good
intentions. For instance, vigorous attempts to improve the accuracy of
forecasts\--a rational program\--may lead planners to have an
inappropriate confidence in their estimates of future demand; thus,
incremental improvements in the single best forecast do not lead one to
the rather different approach suggested here. It is important to bear in
mind, then, that flexibility is desirable as a means to a larger end:
cost-effective power supply. On account of both the external effects of
planning and the problem of second best, it is wise to be cautious about
the value of flexibility. But a flexible approach has obvious merit in
the uncertain environment faced by the Northwest.

IV\. PRACTICAL QUESTIONS

Regional risk management is clearer conceptually than practically. The
ideas discussed in this article are familiar and well-established in
business, especially in finance and other cyclical industries. Yet
applying **\*338** them to the complex web of technological and
institutional relationships that constitute electric power in the
Northwest will be challenging. The promise of the risk-management
approach is large: it is the one conceptual framework that offers
significant, achievable strengths in facing uncertainty.

The region will be served best by a vigorous critique of the
risk-management concept. What are the barriers that stand in the way of
using these ideas to structure the regional plan? What special
advantages might accrue from using a risk-management approach, and what
special disadvantages are attached to using it?Who will benefit, and who
will lose, if a risk-management philosophy is adopted? Most of all, is
flexible planning practical given the regional power system as it is,
and will a system shaped by regional risk management be a better one for
the ratepayers of the Northwest?

The key questions are those that surround measures to increase planning
flexibility, especially resource options:

1\. Who will find it sensible to provide options, and under what
conditions? [[]{#Document0zzFN_B101
.anchor}[\[FN101\]]{.underline}](#Document0zzFN_F101) What are the
legal, economic, institutional, or psychological barriers that inhibit
the development of options?

2\. Are options compatible with the Northwest Power Act? Is the language
of section 6(f), [[]{#Document0zzFN_B102
.anchor}[\[FN102\]]{.underline}](#Document0zzFN_F102) providing for
reimbursement of resource development expenses, [[]{#Document0zzFN_B103
.anchor}[\[FN103\]]{.underline}](#Document0zzFN_F103) adequate as a
legal framework for using options? []{#Document0zzFN_B104 .anchor}
[[\[FN104\]]{.underline}](#Document0zzFN_F104)

3\. Are options compatible with regulatory rules?
[[]{#Document0zzFN_B105
.anchor}[\[FN105\]]{.underline}](#Document0zzFN_F105) Approval for major
generating facilities usually requires determination of the need for
power [[]{#Document0zzFN_B106
.anchor}[\[FN106\]]{.underline}](#Document0zzFN_F106)\--a **\*339**
determination that is eschewed in flexible planning. \'Banking\' a site
entails a commitment by regulatory agencies that future regulations will
still be consistent with use of that location. []{#Document0zzFN_B107
.anchor} [[\[FN107\]]{.underline}](#Document0zzFN_F107) Permits and
licenses for projects often carry deadlines, limiting the allowable
delay between licensing and the start of construction;
[]{#Document0zzFN_B108 .anchor}
[[\[FN108\]]{.underline}](#Document0zzFN_F108) changing this aspect of
the rules of many agencies will not be easy. State and federal
regulations pose a significant barrier to regional risk management.

4\. Presumably, the front-end costs of most power supply projects are
small near the time of initiation: design, siting, and licensing are all
activities that require far less expenditure than construction. So an
option could be purchased at modest cost. But are conservation programs
like this? What about experimental resources that may involve
substantial research and development costs? More generally, what
determines the cost of an option in a technical sense?
[[]{#Document0zzFN_B109
.anchor}[\[FN109\]]{.underline}](#Document0zzFN_F109)

5\. Why would a project sponsor be willing to delay or halt a project
once it is begun, and do so on the basis of regional criteria
interpreted by the Council or BPA? [[]{#Document0zzFN_B110
.anchor}[\[FN110\]]{.underline}](#Document0zzFN_F110) In part, this is a
matter of what the region is willing to pay for the option in the first
place. More generally, what negotiating factors influence the price of
an option? [[]{#Document0zzFN_B111
.anchor}[\[FN111\]]{.underline}](#Document0zzFN_F111)

6\. How reliable are the cost and schedule estimates of options? Can
they be made at least as credible as those for projects proposed for
acquisition or billing credits under the Act? An especially important
question is schedule slippage. It may be crucial to provide assurance
that designation as an option will not increase the probability that a
project will be slowed by anyone besides BPA and the Council.
[[]{#Document0zzFN_B112
.anchor}[\[FN112\]]{.underline}](#Document0zzFN_F112) Schedule slippages
in the years preceding passage of the Act may have sustained the
tendency to overbuild resources over the past decade. Overcoming the
utilities\' fears of slippage is a major hurdle for any planning
process, perhaps especially so for one incorporating projects subject to
regional review after they are underway.

**\*340** 7. Some options involve few direct costs beyond those of
negotiation, such as contractual arrangements for power sales or
purchases. What options for the Northwest are to be found in the plans
of utilities in neighboring regions such as California or western
Canada? Note that this question is similar to that of load diversity,
but the focus is on planning rather than operations.

8\. Are there institutional arrangements other than contracts that can
facilitate options? Are there conditions in which having shared
ownership is advantageous? The aluminum industry has played an important
role in the Northwest power system by providing a market for reserves
that had no alternative market; [[]{#Document0zzFN_B113
.anchor}[\[FN113\]]{.underline}](#Document0zzFN_F113) are there similar
industry-utility compatibilities with respect to resource options?

9\. If options are obtainable, which characteristics are most valuable?
What is the relative value, for instance, of cost as compared to
lead-time? Of size compared to the uncertainties of completion on time?
Does putting a high value on flexibility lead to unanticipated results?
[[]{#Document0zzFN_B114
.anchor}[\[FN114\]]{.underline}](#Document0zzFN_F114) This article has
implicitly assumed that cost and flexibility were the only relevant
variables, but clearly that is not so. What would one want from an
option? What makes an option a valuable form of insurance to the region?
[[]{#Document0zzFN_B115
.anchor}[\[FN115\]]{.underline}](#Document0zzFN_F115)

10\. What sort of options might be helpful if the lower bound forecast
indicates prolonged periods of power supply surplus or even declining
demand in the region? [[]{#Document0zzFN_B116
.anchor}[\[FN116\]]{.underline}](#Document0zzFN_F116)

11\. This article has implicitly assumed that central planning for the
whole region will prevail. But large utilities will continue to operate
autonomously within the Bonneville service area. How are they affected
by a shift to a flexible planning process? Neither their technological
or economic ability **\*341** nor their continuing willingness to
participate in a centrally-directed risk management strategy can be
assumed. [[]{#Document0zzFN_B117
.anchor}[\[FN117\]]{.underline}](#Document0zzFN_F117)

12\. Can the fragile and complicated regional utility industry structure
absorb the complexities of flexible planning? If the region\'s utilities
were a single organization, this would be a question of corporate
strategy. Within the existing fragmented situation, there is a danger
that this system-level institutional question will not be considered
seriously enough. [[]{#Document0zzFN_B118
.anchor}[\[FN118\]]{.underline}](#Document0zzFN_F118)

V. CONCLUSION

The risks that face the Northwest are plainly visible. The technical and
institutional means of taking account of these risks in regional
planning are now being developed. Individual utilities have, of course,
invented sophisticated means to insulate themselves from the effects of
the kind of uncertainties analyzed here. Moreover, through
instrumentalities such as the Pacific Northwest Coordination Agreement
of 1964 or the Northwest Power Pool founded in 1942, the utilities have
acted at the regional level to address technological uncertainties.
[[]{#Document0zzFN_B119
.anchor}[\[FN119\]]{.underline}](#Document0zzFN_F119) The conditions
that confront the region today arise primarily from social and economic
rather then technological uncertainties; and the principal instrument
for coping with these uncertainties is the new institutional framework
created in the Northwest Power Act.

Because of the limited authority granted BPA and the Council in the Act,
the methods of recognizing, analyzing, and adapting to changing
conditions at the regional level are critically dependent upon informed,
**\*342** creative, timely, and constructive leadership from the
utilities, state and local governments, and interest groups. The
concepts of flexible risk management set forth here are offered as a
framework within which genuinely collaborative planning can take place.

[[]{#Document0zzFN_Fa .anchor}[\[FNa\]]{.underline}](#Document0zzFN_Ba)
A.B., Columbia, 1966; Ph.D., Princeton, 1971; Associate Professor of
Environmental Studies and Political Science at the University of
Washington; sometime consultant to the Northwest Power Planning Council.
This article owes much of its thinking to contributions of members of
the Power Council, especially Charles T. Collins, member from the State
of Washington.

Author\'s note: An earlier version of this article was prepared as a
discussion paper in March 1982 and distributed widely in the Pacific
Northwest. Numerous written and oral comments on the paper were
received, and the Northwest Power Planning Council discussed both the
paper and comments on it at the Council\'s meeting on May 6, 1982. In
November 1982 the Council adopted a planning philosophy similar to the
one outlined here in its Resource Options Decision Memorandum. This
article incorporates the author\'s responses to earlier comments as well
as two major analyses stimulated by the discussion paper: a study of the
resource options concept concluded in October 1982 by the Pacific
Northwest Utilities Conference Committee; and an analysis commissioned
by the Council and carried out by the Battelle Pacific Northwest
Laboratories.

[[]{#Document0zzFN_F1 .anchor}[\[FN1\]]{.underline}](#Document0zzFN_B1).
Many of the concepts discussed here were initially developed in R.
Watson, S. Aos, J. Douglass, & P. Downey, Power Planning and Uncertainty
(revised version, Feb. 3, 1982) \[hereinafter cited as WSEO I\], a paper
prepared at the Washington State Energy Office. These arguments were
later extended in S. Aos, J. Douglas, P. Downey, G. Hill, & R. Watson,
The Design and Evaluation of a Flexible Power Plan (July 4, 1982)
\[hereinafter cited as WSEO II\].

[[]{#Document0zzFN_F2 .anchor}[\[FN2\]]{.underline}](#Document0zzFN_B2).
Pacific Northwest Electric Power Planning and Conservation Act, [[Pub.
L.
96-501]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000819&DocName=USPL96-501&FindType=L),
94 Stat. 2697 (codified at [[16 U.S.C. § 839 (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839&FindType=L))
\[hereinafter cited as Northwest Power Act\].

[[]{#Document0zzFN_F3 .anchor}[\[FN3\]]{.underline}](#Document0zzFN_B3).
See BONNEVILLE POWER ADMINISTRATION, LEGISLATIVE HISTORY OF THE PACIFIC
NORTHWEST ELECTRIC POWER PLANNING AND CONSERVATION ACT 41ff & 75ff
(1981) \[hereinafter cited as LEGISLATIVE HISTORY\]. A helpful
perspective may be found in E. Redman, A Brief Functional Analysis of
the New Northwest Power Act (June 1, 1981) (unpublished memorandum)
(copy on file with the Washington Law Review).

[[]{#Document0zzFN_F4 .anchor}[\[FN4\]]{.underline}](#Document0zzFN_B4).
Northwest Power Act, supra note 2, § 4, [[16 U.S.C. § 839b (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L).

[[]{#Document0zzFN_F5 .anchor}[\[FN5\]]{.underline}](#Document0zzFN_B5).
See K. LEE, D. KLEMKA & M. MARTS, ELECTRIC POWER AND THE FUTURE OF THE
PACIFIC NORTHWEST 135 (1980) \[hereinafter cited as ELECTRIC POWER\].

[[]{#Document0zzFN_F6 .anchor}[\[FN6\]]{.underline}](#Document0zzFN_B6).
See generally id. ch. 2 (discussing sources and uses of electric power
in the region).

[[]{#Document0zzFN_F7 .anchor}[\[FN7\]]{.underline}](#Document0zzFN_B7).
There is a relatively small, but perhaps important, quantity of
hydropower still to be developed on the mainstem of the Columbia. The
possibilities of utilizing this resource within the planning framework
developed in this article are discussed in Pacific Northwest Utilities
Conference Committee, A Discussion Paper of Resource Options 48-49 (Oct.
1982) \[hereinafter cited as PNUCC Options Paper\]. A substantial
quantity of so- called \'small hydro\' is available for development on
smaller rivers and streams in the Northwest.

[[]{#Document0zzFN_F8 .anchor}[\[FN8\]]{.underline}](#Document0zzFN_B8).
See generally ELECTRIC POWER, supra note 5, ch. 3 (describing the
Hydro-Thermal Power Program).

[[]{#Document0zzFN_F9 .anchor}[\[FN9\]]{.underline}](#Document0zzFN_B9).
Power demand in the Northwest in 1980 amounted to approximately 16,000
average megawatts. BONNEVILLE POWER ADMINISTRATION, BONNEVILLE POWER
ADMINISTRATION FORECASTS OF ELECTRICITY CONSUMPTION IN THE PACIFIC
NORTHWEST, 1980-2000 (FINAL) 28 (July 1982) \[hereinafter cited as BPA
1982 FORECAST\]. Compare the 1.6% annual average rate of growth
estimated in the base case of this forecast to one only 0.3% higher. The
BPA projects that by 1995 the demand at 1.6% will be 21,101 average
megawatts; at 1.9% growth the demand would be more than 22,000 average
megawatts, 900 megawatts higher. The output of a large nuclear power
station is conventionally estimated at 60 percent \'load factor\' (the
fraction of the time the plant is delivering its full rated output). For
a plant nominally rated at 1000 megawatts, then, 600 average megawatts
may be used as a rule of thumb. This figure is smaller than the
difference between our two estimates.

[[]{#Document0zzFN_F10
.anchor}[\[FN10\]]{.underline}](#Document0zzFN_B10). The BPA forecast
uses low, base case, and high forecasts whose average annual growth
rates range from 0.9% to 2.4%. BPA 1982 FORECAST, supra note 9, at 4-10.
These values are based upon judgment. The BPA also judges that there is
no more than a 75% probability that actual loads will fall within this
range. Id. By the year 2000 the low and high forecasts differ by
approximately 7900 average megawatts. Id. at 28. To gain a sense of the
uncertainties involved, consider the fact that a typical coal-fired
power plant is rated at 500 average megawatts; such a plant costs
roughly \$1 billion in 1982 dollars.

[[]{#Document0zzFN_F11
.anchor}[\[FN11\]]{.underline}](#Document0zzFN_B11). R. BERNEY, W.
BUTCHER, G. HINMAN, R. LEWIS & L. SCHWARTZ, INDEPENDENT REVIEW OF WNP-4
AND WNP-5 (March 15, 1982) (Washington Energy Research Center,
Washington State University) \[hereinafter cited as WERC FINAL REPORT\].
The Final Report states that these two nuclear projects, now terminated,
would have taken thirteen years and \$12.5 billion to complete. Id. at
15, 36.

[[]{#Document0zzFN_F12
.anchor}[\[FN12\]]{.underline}](#Document0zzFN_B12). See generally id.
at 133-37 (discussing imbalances between loads and resources).

[[]{#Document0zzFN_F13
.anchor}[\[FN13\]]{.underline}](#Document0zzFN_B13). The case of
Washington Public Power Supply Systems (WPPSS) Projects 4 and 5
illustrates the difficulties. Fearing the economic consequences of
shortage, 88 utilities agreed in the mid-1970\'s to build two plants now
terminated because insufficient demand for their output is anticipated.
That termination action itself has become the focus of legal and
financial crisis. See generally E. CARLSON, J. ELORRIAGA & G.
WEYERHAEUSER, A REPORT ON THE ECONOMIC IMPACTS OF THE ALTERNATIVES
FACING THE REGION ON WASHINGTON PUBLIC POWER SUPPLY SYSTEM UNITS 4 AND
5, REPORT OF THE GOVERNORS PANEL (1981).

[[]{#Document0zzFN_F14
.anchor}[\[FN14\]]{.underline}](#Document0zzFN_B14). See Chapman,
Tyrrell & Mount, Electricity Demand Growth and the Energy Crisis, 178
SCIENCE 703, 706 (1972).

[[]{#Document0zzFN_F15
.anchor}[\[FN15\]]{.underline}](#Document0zzFN_B15). See generally C.
McKINLEY, UNCLE SAM IN THE PACIFIC NORTHWEST ch. 4 (1952) (discussing
history of BPA in the Northwest); R. BESSEY, PACIFIC NORTHWEST REGIONAL
PLANNING\--A REVIEW (1963) (Bulletin No. 6, Division of Power Resources,
Washington Department of Consevation).

[[]{#Document0zzFN_F16
.anchor}[\[FN16\]]{.underline}](#Document0zzFN_B16). See ELECTRIC POWER,
supra note 5, at 31.

[[]{#Document0zzFN_F17
.anchor}[\[FN17\]]{.underline}](#Document0zzFN_B17). See Willrich, The
Electric Utility and the Energy Crisis Part I, PUB. UTIL. FORT., Jan. 2,
1975, at 22-28; and Part II, PUB. UTIL. FORT., Jan. 16, 1975, at 25-34.

[[]{#Document0zzFN_F18
.anchor}[\[FN18\]]{.underline}](#Document0zzFN_B18). See generally
ELECTRIC POWER, supra note 5, chs. 3-5 (describing events leading up to
the Northwest Power Act).

[[]{#Document0zzFN_F19
.anchor}[\[FN19\]]{.underline}](#Document0zzFN_B19). The principal
statements are the Bonneville Project Act of 1937, [[16 U.S.C. § 832
(1976 & Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS832&FindType=L),
and the Pacific Northwest Federal Columbia River Transmission System
Act, [[16 U.S.C. § 838 (1976 & Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS838&FindType=L).

[[]{#Document0zzFN_F20
.anchor}[\[FN20\]]{.underline}](#Document0zzFN_B20). See Northwest Power
Act, supra note 2, § 6, [[16 U.S.C. § 839d (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839D&FindType=L).

[[]{#Document0zzFN_F21
.anchor}[\[FN21\]]{.underline}](#Document0zzFN_B21). Id.

[[]{#Document0zzFN_F22
.anchor}[\[FN22\]]{.underline}](#Document0zzFN_B22). See WERC FINAL
REPORT, supra note 11, at 84.

[[]{#Document0zzFN_F23
.anchor}[\[FN23\]]{.underline}](#Document0zzFN_B23). See ELECTRIC POWER,
supra note 5, at 111-13. Costs are uncertain because of difficulties in
accurately estimating construction costs, overruns, and delays; the cost
of fuel; expenses for operations and maintenance, especially for new
technologies; tightening environmental control obligations (such as
waste disposal, decommissioning, or advanced pollution control
equipment); and the expense of replacement power in the event of
unforeseen outages or fuel-supply interruptions.

The amount of power produced by a project is also subject to
uncertainties: a project may fail to be completed or to be operated (a
so-called \'dry hole\'); it may produce less power than planned; or it
may encounter unanticipated forced outages.

[[]{#Document0zzFN_F24
.anchor}[\[FN24\]]{.underline}](#Document0zzFN_B24). For an independent
analysis of the situation facing WPPSS Projects 4 and 5, see the study
commissioned by the Washington State Legislature, WERC FINAL REPORT,
supra note 11; Lee, WPPSS 4 and 5: The agony and the legacy (Part I),
The Weekly (Seattle), May 12, 1982, at 2, col. 1; (Part II), The Weekly
(Seattle), May 19, 1982, at 2, col. 1.

[[]{#Document0zzFN_F25
.anchor}[\[FN25\]]{.underline}](#Document0zzFN_B25). Note that the
projected average rate increases are modest in real economic terms (WERC
FINAL REPORT, supra note 11, at 22) but political reaction reflects
instead the large size of the nominal increases in rates.

[[]{#Document0zzFN_F26
.anchor}[\[FN26\]]{.underline}](#Document0zzFN_B26). See Lee, Regional
Electric Power and Local Governments, 9 WASH. PUB. POL\'Y NOTES 4
(Autumn 1981).

[[]{#Document0zzFN_F27
.anchor}[\[FN27\]]{.underline}](#Document0zzFN_B27). See generally
ELECTRIC POWER, supra note 5, chs. 2 & 3 (describing the history of the
public power movement in the Pacific Northwest).

[[]{#Document0zzFN_F28
.anchor}[\[FN28\]]{.underline}](#Document0zzFN_B28). See Northwest Power
Act, supra note 2, § 4, [[16 U.S.C. § 839b (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L).

[[]{#Document0zzFN_F29
.anchor}[\[FN29\]]{.underline}](#Document0zzFN_B29). It is important to
bear in mind that definitions of forecasts differ. The Council\'s
forecast, pursuant to the Northwest Power Act, supra note 2, §
4(e)(3)(D), [[16 U.S.C. § 839b(e)(3)(D) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L),
will be a projection of electric power sales for the 20-year period
commencing April 28, 1983, explicitly taking into account conservation
programs already underway and cogeneration. Conservation induced by
projected increases in rates will be treated as an addition to the
supply of power. Variations in the treatment of conservation and
cogeneration have led to substantial confusion in the interpretation of
forecasts, including the ones developed by the BPA and the Washington
Energy Research Center.

[[]{#Document0zzFN_F30
.anchor}[\[FN30\]]{.underline}](#Document0zzFN_B30). The uncertainties
in forecasting are traceable to two causes. First, there is now greater
uncertainty in projecting economic trends, a result of uneven
macroeconomic performance in the last dozen years, together with a
continued increase in mobility, which has made demographic projections
less reliable. Second, the Pacific Northwest is experiencing rapidly
rising utility rates, after more than half a century of electric prices
that decreased in real economic terms. The response of ratepayers to
rising rates is likely to be both significant and complex over the next
sev eral years ; the character and magnitude of reactions to increasing
real prices is not well understood at the national level, not to mention
the Northwest region. See Northwest Power Planning Council, Economic and
Demographic Assumptions 2-5 (Revised Draft, Dec. 10, 1982).

A major consequence of these uncertainties is that the input assumptions
in long-range forecasts cannot be estimated with satisfactory precision.
At best, then, the information base from which the analyst begins can
only produce an estimate of the likely range of future demands, as
described in the text. Moreover, when the estimates are imprecise, a
regional plan limiting the discretion of the Bonneville Power
administrator to make regional power investments (as set forth in the
Northwest Power Act, supra note 2, § 4(d)(2), [[16 U.S.C. § 839b(d)(2)
(Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L))
becomes, faute de mieux, a form of regional economic plan.

The challenge of the Northwest Power Act can therefore be framed in the
following terms: the Council must attempt to set investment priorities
in conservation and electric power development which will
facilitate\--rather than direct or circumscribe\--the overall economic
evolution of the region in response to private initiative, market
forces, and policies set by duly constituted governmental authority.

The Council\'s choices of economic and demographic assumptions are set
forth in Northwest Power Planning Council, Decision Memorandum, Economic
and Demographic Assumptions (Oct. 13, 1982). For a critique of economic
efficiency as a target of energy planning, see Winner, Energy Regimes
and the Ideology of Efficiency, in ENERGY AND TRANSPORT: HISTORICAL
PERSPECTIVES ON POLICY ISSUES 270-76 (1982).

[[]{#Document0zzFN_F31
.anchor}[\[FN31\]]{.underline}](#Document0zzFN_B31). It is instructive
to examine the track record of the Pacific Northwest Utilities
Conference Committee (known as the \'West Group\' prior to passage of
the Northwest Power Act), which publishes annual 20-year forecasts for
the Bonneville service area. The West Group forecasts for 1969-1980 are
compared with actual average loads in WERC FINAL REPORT, supra note 11,
at 77; a similar compilation, covering the years 1965-75, is presented
in BONNEVILLE POWER ADMINISTRATION, THE ROLE OF THE BONNEVILLE POWER
ADMINISTRATION IN THE PACIFIC NORTHWEST POWER SUPPLY SYSTEM IV-84 to -85
(July 22, 1977) (Draft Environmental Statement). These tables
demonstrate several interesting tendencies: (1) Since the 1969-1970
operating year (and in a majority of cases earlier as well) the PNUCC
forecasts have consistently projected larger loads than actually
occurred. (2) The magnitude of the overestimates increased beginning in
the 1973-1974 year, regularly reaching more than 10 percentage points in
the late 1970\'s. (3) There is a weak tendency for the size of the
overestimate to correlate with regional economic conditions in the year
forecast was made. (I am indebted to H. M. Mozer for bringing these data
to my attention, and for pointing out the third of these trends.)

The second trend, the increase in error since 1973-1974, may be
traceable to the fact that firm sales of hydropower from the Federal
Columbia River Power System to the investor-owned utilities of the
Northwest ended in 1973. As a result, rates paid by consumers served by
investor-owned utilities began to rise that year. With the rise in
rates, consumption dropped, and the size of this change may have eluded
forecasters. See THE WPPSS INDEPENDENT STUDY STEERING COMMITTEE, AN
EVALUATION OF THE WASHINGTON ENERGY RESEARCH CENTER\'S FINAL REPORT,
INDEPENDENT REVIEW OF WNP-4 AND WNP-5, at 6-11 (Mar. 26, 1982); Economic
and Demographic Assumptions, supra note 30, at 2-5.

[[]{#Document0zzFN_F32
.anchor}[\[FN32\]]{.underline}](#Document0zzFN_B32). For a careful
analysis of the components of cost in generating stations, see P. HILL,
POWER GENERATION (1977); I WASHINGTON STATE SENATE ENERGY AND UTILITIES
COMMITTEE WPPSS INQUIRY, 47th Leg., CAUSES OF COST OVERRUNS AND SCHEDULE
DELAYS ON THE FIVE WPPSS POWER PLANTS (1982); WASHINGTON ENERGY RESEARCH
CENTER, COSTS AND SCHEDULES. MODULE III FINAL REPORT (Jan. 1982).

[[]{#Document0zzFN_F33
.anchor}[\[FN33\]]{.underline}](#Document0zzFN_B33). See WASHINGTON
ENERGY RESEARCH CENTER, MARKETS FOR IMPORTS OF ELECTRICITY, MODULE IV
FINAL REPORT (Jan. 1982).

[]{#Document0zzSDUNumber41 .anchor}

[[\[FN34\]]{.underline}](#Document0zzFN_B34). See Lee,Electricity:
Toward a Regional Strategy, in ENERGY POLICY AND PUBLIC ADMINISTRATION
(1980).

[[]{#Document0zzFN_F35
.anchor}[\[FN35\]]{.underline}](#Document0zzFN_B35). Northwest Power
Act, supra note 2, § 4(e), [[16 U.S.C. § 839b(e) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L).

[[]{#Document0zzFN_F36
.anchor}[\[FN36\]]{.underline}](#Document0zzFN_B36). The utilities\'
appraisal of this approach is contained in PNUCC Options Paper, supra
note 7. The argument of this article accords with their conclusion:
\'The electric utility industry is well aware of the need for greater
flexibility in the planning and construction process. A well designed
and workable options process would be highly welcome.\' PNUCC Options
Paper, supra note 7, at 2.

[[]{#Document0zzFN_F37
.anchor}[\[FN37\]]{.underline}](#Document0zzFN_B37). See supra notes
30-31 (discussing limited accuracy of forecasting).

[[]{#Document0zzFN_F38
.anchor}[\[FN38\]]{.underline}](#Document0zzFN_B38). As the number of
participants in a project increases, the risk to the collectivity
decreases, since adverse outcomes will be more widely shared. For the
economic theory putting this concept on a rigorous foundation, see Arrow
& Lind, Uncertainty and the evaluation of public investments, 60 AM.
ECON. REV. 364 (1970).

[]{#Document0zzSDUNumber42 .anchor}

[[\[FN39\]]{.underline}](#Document0zzFN_B39). Northwest Power Act, supra
note 2, § 4(e)(1), [[16 U.S.C. § 839b(e)(1) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L).

[[]{#Document0zzFN_F40
.anchor}[\[FN40\]]{.underline}](#Document0zzFN_B40). Id.

[[]{#Document0zzFN_F41
.anchor}[\[FN41\]]{.underline}](#Document0zzFN_B41). Section 4(e)(2) of
the Act authorizes central planning by the council. Id. § 4(e)(2), [[16
U.S.C. §
839b(2)(2)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L).
[[Section
2(5)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS2&FindType=L)
expressly foreswears limits or restrictions upon the freedom of
utilities and maintains \'the authorities and responsibilities of State
and local governments, electric utility systems, water management
agencies, and other non-Federal entities.\' Id. [[§
2(5)(A)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS2&FindType=L),
[[16 U.S.C. §
539(5)(A)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS539&FindType=L).

[[]{#Document0zzFN_F42
.anchor}[\[FN42\]]{.underline}](#Document0zzFN_B42). See PNUCC Options
Paper, supra note 7, at 3.

[[]{#Document0zzFN_F43
.anchor}[\[FN43\]]{.underline}](#Document0zzFN_B43). The technological
implications of increased complexity are addressed, in part, by a System
Analysis Model being built by a committee of the Pacific Northwest
Utilities Conference Committee. This model estimates the interactive
effects of adding new supplies, such as renewable resources, to the
existing regional hydro system. The System Analysis Model is an
outgrowth of a long tradition of technical cooperation among the
region\'s utilities, a relationship specified in the Pacific Northwest
Coordination Agreement of 1964. On the Coordination Agreement, see
ELECTRIC POWER, supra note 5, at 54-55.

It remains to be seen, however, whether this technical level of
cooperation can be extended to nonutility actors such as industrial
firms undertaking cogeneration, and whether technical cooperation can
foster institutional collaboration. It is a hopeful sign, accordingly,
that the use of the System Analysis Model for regional planning is
discussed in PNUCC Options Paper, supra note 7, at 23-27.

[[]{#Document0zzFN_F44
.anchor}[\[FN44\]]{.underline}](#Document0zzFN_B44). There are two
critical differences in regional power planning under the Act. First,
financing of a major resource may be accomplished through acquisition of
its capability by the Administrator of BPA, pursuant to authority
granted him under § 6(a), (d), (e), (f), (h), & (l), [[16 U.S.C. §
839d(a), (d), (e), (f), & (l) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839D&FindType=L).
But second, authorization for acquisition depends upon designation of
that resource in the Northwest Power Planning Council\'s regional energy
plan, in accordance with the process set forth in § 4(d)-(g), [[16
U.S.C. § 839b(d)-(g) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L);
the Administrator\'s authority is further subject to the constraints
outlined in § 6(b)-(m), [[16 U.S.C. § 839d(b)-(m) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839D&FindType=L).
These new arrangements create a major financing role for the BPA,
extending, perhaps a great deal, the possibilities devised under the
rubric of \'net billing\' in the 1968 Hydro- Thermal Power Program. See
generally ELECTRIC POWER, supra note 5, ch. 3 (discussion and
explanation of net billing). Moreover, a new set of actors, state
governments acting through their representatives on the Council,
effectively controls access to the regional financing mechanism. These
two principal changes affect the independence with which utilities may
plan their own activities by altering the financial and organizational
incentives for joint action in response to expectations of future power
demand. The Northwest Power Act affects utility planning in other
significant ways as well, notably through its requirement for a fish and
wildlife program in the Columbia River basin.

[[]{#Document0zzFN_F45
.anchor}[\[FN45\]]{.underline}](#Document0zzFN_B45). See generally
ELECTRIC POWER, supra note 5, ch. 7 (analyzing conceptual approaches to
regional planning).

[[]{#Document0zzFN_F46
.anchor}[\[FN46\]]{.underline}](#Document0zzFN_B46). See generally C.
SCHULTZE, THE PUBLIC USE OF PRIVATE INTEREST (1977) (advocating use of
market arrangements to implement public policy).

[[]{#Document0zzFN_F47
.anchor}[\[FN47\]]{.underline}](#Document0zzFN_B47). See P. SELZNICK,
LEADERSHIP IN ADMINISTRATION (1957) (emphasizing the role of purposes in
organizational management).

[[]{#Document0zzFN_F48
.anchor}[\[FN48\]]{.underline}](#Document0zzFN_B48). For example, the
regional energy plan now being developed by the Council will be adopted
in April 1983 (executing the mandate of § 4(d)(1) of the Northwest Power
Act, supra note 2, [[16 U.S.C. § 839b(d)(1) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L)),
after the adoption in November 1982 of a program \'to protect, mitigate,
and enhance fish and wildlife\' in the Columbia River and its
tributaries. Id. § 4(h)(1)(A), [[16 U.S.C. §
839b(h)(1)(A)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L).
A flexible energy plan affects and interacts with the fish and wildlife
program: changes in one influence choices in the other. In part for this
reason, the fish and wildlife program adopted by the Council
contemplates studies and revisions of the program. As information on the
implementation of that program accumulates, corresponding modifications
of the energy plan may also be appropriate. Thus, the complexity of the
planning task set forth in the Northwest Power Act itself points to the
wisdom of a flexible approach to planning, so that new information can
be incorporated in decisionmaking.

[[]{#Document0zzFN_F49
.anchor}[\[FN49\]]{.underline}](#Document0zzFN_B49). Note that the
utilities explicitly reserve judgment on the operational implications of
a risk-managing approach to planning. PNUCC Options Paper, supra note 7,
at 2.

[[]{#Document0zzFN_F50
.anchor}[\[FN50\]]{.underline}](#Document0zzFN_B50). For an economic
analysis of diversification, see Tobin, The Theory of Portfolio
Selection, in THEORY OF INTEREST RATES (1965).

[[]{#Document0zzFN_F51
.anchor}[\[FN51\]]{.underline}](#Document0zzFN_B51). See Northwest Power
Planning Council, Resource Options Decision Memorandum 2 (Nov. 30, 1982)
\[hereinafter cited as Options Memorandum\]:

For the purposes of power planning, options will be investments by the
Region in the early phases of resources development or investments in
the early completion of a resource that can be sold outside of the
region with call back provisions. The Region will receive in return for
this financial assistance the right to exercise the option and provide
additional energy to meet load growth with shorter lead-time and higher
confidence or to hold the option and delay the acquisition of additional
energy.

For a helpful analysis of options using information relevant to the
Pacific Northwest, see E. MOORE, JR., R. WATTS, B. HARRER & P.
HENDRICKSON, DEVELOPMENT AND SUPPLY RESOURCE PLANNING OPTIONS (1982)
(Report submitted by Battelle Pacific Northwest Laboratories to the
Northwest Power Planning Council) \[hereinafter cited as BATTELLE
OPTIONS STUDY\]. This analysis identifies three or four \'cost nodes\'
at which project costs and schedules can be readily evaluated by
regional decision makers. Id. at 6.1-.6.

[[]{#Document0zzFN_F52
.anchor}[\[FN52\]]{.underline}](#Document0zzFN_B52). Northwest Power
Act, supra note 2, § 6, [[16 U.S.C. § 839(d) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839&FindType=L).

[[]{#Document0zzFN_F53
.anchor}[\[FN53\]]{.underline}](#Document0zzFN_B53). \'An option is an
agreement between a potential buyer and seller of a property, good or
service in which, typically, the potential buyer pays cash or other
consideration to \[the\] seller for the right to buy the property, good
or service within a particular time on specified terms.\' Options
Memorandum, supra note 51, at 2. Identical wording is used to define
\'option\' in PNUCC Options Paper, supra note 7, at 1.

[[]{#Document0zzFN_F54
.anchor}[\[FN54\]]{.underline}](#Document0zzFN_B54). WSEO II, supra note
1, at 3; PNUCC Options Paper, supra note 7, at 4.

[[]{#Document0zzFN_F55
.anchor}[\[FN55\]]{.underline}](#Document0zzFN_B55). The PNUCC Options
Paper, supra note 7, describes five general categories of resource
options, distinguishing among them on the basis of how readily available
each set is likely to be. \'Ready resources\' like combustion turbines
are available \'off the shelf\' on short lead-times and with minimal
licensing delays. \'Sales/import options\' are contractual arrangements
with owners of facilities, providing either rights of purchase (for
resources outside the Northwest) or sales (to out-of-region customers)
subject to rights of recall under specified conditions.
\'Purchased/licensed options\' have obtained relevant regulatory
clearances; the holder of the option thus controls the timing of
progress on these projects. \'Purchased/unlicensed options\' are
projects that have been included in the plan, but which still face state
and federal licensing procedures. Least reliance should be placed in the
fifth category, planned options of the kind described in the text. PNUCC
Options Paper, supra note 7, at 4-5. (Compare the five generic types of
options identified by the Council, see infra note 65.)

The PNUCC suggests that a regional policy be developed to \'identify
those types of resources which are firm enough to be considered for
optioning.\' PNUCC Options Paper, supra note 7, at 10.

Note that this categorization is most clearly applied to conventional
generating resources. Conservation is in part a \'ready\' resource,
capable of being implemented rapidly, and in part a \'planned option,\'
insofar as the conservation program is novel and untried on a large
scale. WSEO I, supra note 1, at 8.

[[]{#Document0zzFN_F56
.anchor}[\[FN56\]]{.underline}](#Document0zzFN_B56). The best known
example is the schedule slippages in the nuclear projects of the
Washington Public Power Supply System. See sources cited supra at note
24. These are not the only cases of significant disparity between
initial plans and actual performance in power plant construction,
however. The Skagit nuclear project and two units of the Colstrip
coal-fired project sponsored by Puget Power have suffered lengthy
delays. Similar difficulties have plagued Portland General Electric\'s
Pebble Springs nuclear project.

[[]{#Document0zzFN_F57
.anchor}[\[FN57\]]{.underline}](#Document0zzFN_B57). The PNUCC Options
Paper, supra note 7, recommends that the Council and the BPA endorse
requests for flexibility by utilities and other resource sponsors. Id.
at 8-9 & 46-47. Such a posture seems sensible in general, although each
proposal, regarded as either a resource or a planning option, needs to
be evaluated on its merits.

[[]{#Document0zzFN_F58
.anchor}[\[FN58\]]{.underline}](#Document0zzFN_B58). For a discussion of
the technical problems of coal power plant gas scrubbers, see Ackerman &
Hassler, Beyond the New Deal: Coal and the Clean Air Act, 89 YALE L.J.
1466 (1980).

[[]{#Document0zzFN_F59
.anchor}[\[FN59\]]{.underline}](#Document0zzFN_B59). A project whose
schedule can be changed by regional authorities may encounter
difficulties in maintaining a high-quality work force. PNUCC Options
Paper, supra note 7, at 10. The timing of schedule changes is
accordingly important.

[[]{#Document0zzFN_F60
.anchor}[\[FN60\]]{.underline}](#Document0zzFN_B60). Options thus become
a significant new rationale in the utilities\' pursuit of regulatory
relief. PNUCC Options Paper, supra note 7, at 13-15.

[[]{#Document0zzFN_F61
.anchor}[\[FN61\]]{.underline}](#Document0zzFN_B61). In a review of cost
estimates for a wide spectrum of conservation and generation
alternatives, the BATTELLE OPTIONS STUDY, supra note 51, concludes that
\'for all resources except geothermal and nuclear, acquisition costs at
any of the specified points before construction are less than 15% of the
total capacity costs.\' Id. at 6.7. Costs for geothermal are high near
the beginning of a project because of the expense of site investigation
and preliminary development. Id. at 6.35. In any event, the costs of
geothermal energy are still uncertain, given the limited field work done
in the region to date. Pre-construction costs for nuclear are high
because of the expense of detailed safety analyses required by the
Nuclear Regulatory Commission, and because the steam supply system is
normally procured prior to the start of construction. Id. at 6.65-.66.

The cost of delaying development of a project is also modest: if the
interruption occurs before construction starts, the cost of the first
year of delay is \'less than \$15 per kilowatt of capacity.\' Id. at
6.7. As delay increases, however, changes in regulation, financing, and
other conditions will affect the viability of the project as originally
defined. \'\[A\] delay of greater than five years in exercising a
resource option will almost certainly necessitate some changes . . ..\'
Id. at ES.22.

[[]{#Document0zzFN_F62
.anchor}[\[FN62\]]{.underline}](#Document0zzFN_B62). In a comparison of
15 categories of power resources, the BATTELLE OPTIONS STUDY, supra note
51, finds that pre-construction activities account for a minimum of 36%
(light-water nuclear reactor) and a maximum of 77% (wind farm) of the
total time needed to develop the resource. Id. at 5.3. These percentages
are substantially larger than the fractional cost commitments of
pre-construction activities.

[[]{#Document0zzFN_F63
.anchor}[\[FN63\]]{.underline}](#Document0zzFN_B63). WSEO II, supra note
1, at 8-15.

[[]{#Document0zzFN_F64
.anchor}[\[FN64\]]{.underline}](#Document0zzFN_B64). The Northwest Power
Act provides that the BPA may \'provide for the reimbursement of the
sponsor\'s investigation and preconstruction expenses.\' Northwest Power
Act, supra note 2, § 6(f)(1)(B), [[16 U.S.C. § 839d(f)(1)(B) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839D&FindType=L).
This language provides a means for authorizing payment for options.

[[]{#Document0zzFN_F65
.anchor}[\[FN65\]]{.underline}](#Document0zzFN_B65). The Council has
identified five generic types of options for planning: (1) resource
options, which are funded on a regional basis up to the point where
construction begins; (2) acquisition of a resource, together with a
contract for (contingent) sale of the resource outside the region; (3)
demonstration projects intended to verify the costs and magnitude of a
resource (expected to be of major importance in planning for
conservation); (4) resources whose costs of operation can be met through
regional purchase (combustion turbines used to meet short term
unanticipated demand fall in this class); and (5) rate designs, approved
in advance, that can be used to recover temporarily high running costs
or to signal imminent scarcity of supply. Options Memorandum, supra note
52, at 2, 4.

[[]{#Document0zzFN_F66
.anchor}[\[FN66\]]{.underline}](#Document0zzFN_B66). PNUCC Options
Paper, supra note 7, at 21-22.

[[]{#Document0zzFN_F67
.anchor}[\[FN67\]]{.underline}](#Document0zzFN_B67). The utilities judge
small hydro and cogeneration to be \'\[t\]he best candidates for an
options portfolio of some security.\' PNUCC Options Paper, supra note 7,
at 36. The complexities facing the development of cogeneration are
discussed in id. at 50-56.

[[]{#Document0zzFN_F68
.anchor}[\[FN68\]]{.underline}](#Document0zzFN_B68). Id. at 40-41.

[[]{#Document0zzFN_F69
.anchor}[\[FN69\]]{.underline}](#Document0zzFN_B69). The PNUCC expresses
skepticism about geothermal and wind as resource possibilities. Id. at
36-39.

[[]{#Document0zzFN_F70
.anchor}[\[FN70\]]{.underline}](#Document0zzFN_B70). Id. at 39-40.

[[]{#Document0zzFN_F71
.anchor}[\[FN71\]]{.underline}](#Document0zzFN_B71). The difficulties of
site banking and advance licensing are summarized in id. at 42-47.

[[]{#Document0zzFN_F72
.anchor}[\[FN72\]]{.underline}](#Document0zzFN_B72). Id. at 17-21.

[[]{#Document0zzFN_F73
.anchor}[\[FN73\]]{.underline}](#Document0zzFN_B73). See ELECTRIC POWER,
supra note 5, at 55.

[[]{#Document0zzFN_F74
.anchor}[\[FN74\]]{.underline}](#Document0zzFN_B74). PNUCC Options
Paper, supra note 7, at 16-17.

[[]{#Document0zzFN_F75
.anchor}[\[FN75\]]{.underline}](#Document0zzFN_B75). See WSEO I, supra
note 1, at 10.

[[]{#Document0zzFN_F76
.anchor}[\[FN76\]]{.underline}](#Document0zzFN_B76). Unusually cold
winter weather can suddenly increase demand for electric heat, while a
period of below-average precipitation in the Columbia basin can decrease
supplies of hydropower. Sudden changes in demand or supply have been met
in two ways: through out-of-region purchases of wholesale power, with
utilities sometimes paying premium prices on the spot market; or through
reductions in use, both voluntary and pursuant to BPA\'s contracts with
its direct-service industrial customers. In periods of severe drought,
spot market purchases have necessitated rate surcharges, to cover the
costs of imported power.

What is suggested here is a means to signal short-run changes in the
supply- demand balance via electric rates. The historical experience
described above, as well as experience in other regions, indicates that
demand can be changed in the short run by up to 10%, through a
combination of public appeals and temporary rate adjustments. It is hard
to estimate precisely, however, how much of this short-run change can be
produced initially and how long the lowering of demand can be sustained.

[[]{#Document0zzFN_F77
.anchor}[\[FN77\]]{.underline}](#Document0zzFN_B77). WSEO II, supra note
1, at 14.

[[]{#Document0zzFN_F78
.anchor}[\[FN78\]]{.underline}](#Document0zzFN_B78). See G. Hill, The
Public Interest and the Evaluation of Public Policy 288-90 (1981)
(unpublished Ph.D. dissertation) (copy on file with the Washington Law
Review).

[[]{#Document0zzFN_F79
.anchor}[\[FN79\]]{.underline}](#Document0zzFN_B79). For a discussion of
interruptible power and its most effective uses, see Redman, [[Nonfirm
Energy and BPA\'s Industrial Customers, 58 WASH. L. REV. 279
(1983)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1281&FindType=Y&SerialNum=0101495209).

[[]{#Document0zzFN_F80
.anchor}[\[FN80\]]{.underline}](#Document0zzFN_B80). See WSEO I, supra
note 1, at 2-3.

[[]{#Document0zzFN_F81
.anchor}[\[FN81\]]{.underline}](#Document0zzFN_B81). Id.

[[]{#Document0zzFN_F82
.anchor}[\[FN82\]]{.underline}](#Document0zzFN_B82). Tobin, supra note
50.

[[]{#Document0zzFN_F83
.anchor}[\[FN83\]]{.underline}](#Document0zzFN_B83). The PNUCC maintains
that \'the most probable load forecast\' should be used as a planning
target. PNUCC Options Paper, supra note 7, at 6.

[[]{#Document0zzFN_F84
.anchor}[\[FN84\]]{.underline}](#Document0zzFN_B84). See supra notes
31-32 and accompanying text (discussing attainable accuracy of
forecasts). The BPA 1982 FORECAST, supra note 9, was one of the first
forecasts in the region to attempt a systematic specification of a range
within which demand is very likely to be found.

[[]{#Document0zzFN_F85
.anchor}[\[FN85\]]{.underline}](#Document0zzFN_B85). BPA 1982 FORECAST,
supra note 9, at 21-22.

[[]{#Document0zzFN_F86
.anchor}[\[FN86\]]{.underline}](#Document0zzFN_B86). The PNUCC
identifies three approaches: 1) a \'lower jaw tactic,\' in which
resources would only be acquired to meet the lower bound forecast, with
options to fill the gap between the lower and upper bounds; 2) an
\'upper jaw tactic,\' relying on sales options to manage excess
capacity; and 3) a \'between the jaws tactic\' in which a most probable
load forecast\' is used as the basis of an options approach. PNUCC
Options Paper, supra note 7, at 6.

These analysts misconstrue the argument of this article as one favoring
the \'lower jaw tactic.\' PNUCC Options Paper, supra note 7, at 5. I
argue three related points. First, that the degree of uncertainty is, as
a practical matter, too large to permit reliance upon a \'most probable
load forecast.\' Second, that a balanced approach to the circumstances
facing the region would utilize both resource acquisitions above the
lower bound forecast and sales options. But third, that the mix of these
alternatives with resource options should be biased toward retaining as
much fiexibility as affordable, rather than carrying on with the
traditional single-forecast framework. My reading of the situation of
this region is rooted in the perception that Northwest power supply is
not operable as a single utility system; this leads me to emphasize a
shift toward flexible planning.

[[]{#Document0zzFN_F87
.anchor}[\[FN87\]]{.underline}](#Document0zzFN_B87). This expected cost
should include measures of the technical, environmental, and
institutional differences among resource alternatives. Some of these
factors cannot be measured in monetary terms, however, although they are
clearly relevant to a decision. For example, where a given resource is
located can affect its accessibility to the regional grid, its
financing, and the political acceptability to local populations of
proceeding with the project. These factors are put aside in this
simplified example. The concept of expected cost is discussed in WSEO
II, supra note 1, at 8-9.

[[]{#Document0zzFN_F88
.anchor}[\[FN88\]]{.underline}](#Document0zzFN_B88). WSEO II, supra note
1, at 11-12.

[[]{#Document0zzFN_F89
.anchor}[\[FN89\]]{.underline}](#Document0zzFN_B89). Northwest Power
Act, supra note 2, § 4(e)(1), [[16 U.S.C. § 839b(e)(1) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839B&FindType=L).

[[]{#Document0zzFN_F90
.anchor}[\[FN90\]]{.underline}](#Document0zzFN_B90). See supra note 43
(discussion of System Analysis Model).

[[]{#Document0zzFN_F91
.anchor}[\[FN91\]]{.underline}](#Document0zzFN_B91). Note that the
record of forecasting provides only limited support for the hypothesis
that uncertainty decreases as one approaches the point of actual use.
See supra note 31 (discussing track record of PNUCC forecasts).

[[]{#Document0zzFN_F92
.anchor}[\[FN92\]]{.underline}](#Document0zzFN_B92). See Lee, supra note
24.

[[]{#Document0zzFN_F93
.anchor}[\[FN93\]]{.underline}](#Document0zzFN_B93). See BPA 1982
FORECAST, supra note 9, at 21-22.

[[]{#Document0zzFN_F94
.anchor}[\[FN94\]]{.underline}](#Document0zzFN_B94). Under existing rate
structures (for surplus) and curtailment rules (for shortage) imbalances
between supply and demand are not allocated to minimize economic impact.
See WSEO II, supra note 1, at 13-14; ICF, INC., RESERVE-RELIABILITY
ANALYSIS, STUDY MODULE V ch. 3 (Aug. 1982) (final report to the
Northwest Power Planning Council).

[[]{#Document0zzFN_F95
.anchor}[\[FN95\]]{.underline}](#Document0zzFN_B95). ICF, Inc., has
performed an analysis of how shortages could be allocated to minimize
economic impact. Id. ch. 4. Were such an approach politically feasible,
this analysis could be supplemented by a study of how the burden of a
surplus could be similarly allocated.

[[]{#Document0zzFN_F96
.anchor}[\[FN96\]]{.underline}](#Document0zzFN_B96). See, e.g., ELECTRIC
POWER, supra note 5, at 136 figure 16 (illustrating that power demand
projections correlate strikingly with ideology).

[[]{#Document0zzFN_F97
.anchor}[\[FN97\]]{.underline}](#Document0zzFN_B97). The Council\'s
planning philosophy contemplates a more detailed seven-step analysis:
(1) Develop a range of forecasts. (2) Develop alternative resource
portfolios. (3) Using the PNUCC Systems Analysis Model (see supra note
44) and other simulation techniques, assess the probable performance of
alternative portfolios. (4) Assess the implications of the uncertainty
in load forecasts in each of the alternative portfolios. (5) Revise
portfolios in light of insights developed by earlier steps. (6) Evaluate
alternative portfolios, incorporating judgmental factors such as the
tradeoff between cost and lead- time. (7) Examine the effect of the
selected portfolio on rates, and thereby reconsider the range of
forecasts used to initiate the analysis. Options Memorandum, supra note
51, at 5-11.

[[]{#Document0zzFN_F98
.anchor}[\[FN98\]]{.underline}](#Document0zzFN_B98). See Northwest Power
Act, supra note 2, § 5(g)(1)(D), [[16 U.S.C. § 839c(g)(1)(D) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839C&FindType=L);
H.R. REP. NO. 976, 96th Cong., 2d Sess., 28-29 (1980), reprinted in
LEGISLATIVE HISTORY, supra note 3, at 333.

[[]{#Document0zzFN_F99
.anchor}[\[FN99\]]{.underline}](#Document0zzFN_B99). WSEO II, supra note
1, at 14.

[[]{#Document0zzFN_F100
.anchor}[\[FN100\]]{.underline}](#Document0zzFN_B100). See Lipsey &
Lancaster, The General Theory of Second Best, 24 REV. ECON. STUD. 11
(1958).

[[]{#Document0zzFN_F101
.anchor}[\[FN101\]]{.underline}](#Document0zzFN_B101). It is noteworthy
that the PNUCC urges utilities to \'participate with BPA in contract
development for optioning resources.\' PNUCC Options Paper, supra note
7, at 9.

[[]{#Document0zzFN_F102
.anchor}[\[FN102\]]{.underline}](#Document0zzFN_B102). Northwest Power
Act, supra note 2, § 6(f), [[16 U.S.C. § 839d(f) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839D&FindType=L).

[[]{#Document0zzFN_F103
.anchor}[\[FN103\]]{.underline}](#Document0zzFN_B103). See PNUCC Options
Paper, supra note 7, at 30-31.

[[]{#Document0zzFN_F104
.anchor}[\[FN104\]]{.underline}](#Document0zzFN_B104). Using the billing
credits provisions of the Northwest Power Act, supra note 2, § 6(h),
[[16 U.S.C. § 839d(h) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839D&FindType=L),
may provide a means for reimbursing utilities for options as well, PNUCC
Options Paper, supra note 7, at 11.

[[]{#Document0zzFN_F105
.anchor}[\[FN105\]]{.underline}](#Document0zzFN_B105). See BATTELLE
OPTIONS STUDY, supra note 51, § 4.0 (discussing legal and institutional
complexities in developing options). The Council has concluded that:

it is unlikely that all of the regulatory, legal, and institutional
difficulties with the option concept can be resolved \[before the first
regional energy plan is completed in April 1983\]. The Council\'s Plan
will provide incentives to assist option developers to bring the concept
of options to the point where the region can purchase an options
portfolio. These incentives will include preconstruction financing,
power marketing assistance, long-term power sales contract\[s\], and
assistance from the Council in regulatory proce\[e\]dings and regulatory
reform. It is important that the Council\'s plan commit to working with
the region\'s utilities and resource developers to fully operationalize
the options concept.

Options Memorandum, supra note 51, at 4.

[[]{#Document0zzFN_F106
.anchor}[\[FN106\]]{.underline}](#Document0zzFN_B106). See [[IDAHO CODE
§ 61-528
(1976)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000007&DocName=IDSTS61-528&FindType=L);
MONT. CODE ANN. § 75-20 (1981); [[OR. REV. STAT. § 469.300
(1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000534&DocName=ORSTS469.300&FindType=L);
[[WYO. STAT. §
37-2-205]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000377&DocName=WYSTS37-2-205&FindType=L).
See also PNUCC Options Paper, supra note 7, at 13-14. Of course, the
need for power test applies only to the large facilities specified in
these laws. Conservation, some renewable resource projects, and some
high-efficiency resources like fuel cells therefore do not face this
regulatory complication.

[[]{#Document0zzFN_F107
.anchor}[\[FN107\]]{.underline}](#Document0zzFN_B107). See id. at 14.
For example, the requirements of the Clean Air Act, Pub. L. No. 91-604,
84 Stat. 1676 (1970) (codified as amended in scattered sections of 42
U.S.C.), include re-evaluation of the \'best available control
technology\' for projects that are delayed. [[40 C.F.R.
§]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000547&DocName=40CFRS52.21&FindType=L)
[[52.21(j)(4)
(1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000547&DocName=40CFRS52.21&FindType=L).

[[]{#Document0zzFN_F108
.anchor}[\[FN108\]]{.underline}](#Document0zzFN_B108). A hydroelectric
project licensed by the Federal Energy Regulatory Commission (FERC) is
bound by provisions of § 13 of the Federal Power Act, 41 Stat. 1071
(1920) (codified as amended at [[16 U.S.C. § 806
(1976)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS806&FindType=L));
construction must begin within two years, unless FERC grants a two-year
extension. Even small hydro projects (generally, under five megawatts of
electric capacity), which are exempted from FERC regulation, must begin
construction 18 months from the time an exemption is granted. [[18
C.F.R. §
4.106(c)(1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000547&DocName=18CFRS4.106&FindType=L).
See PNUCC Options Paper, supra note 7, at 14-15, 42-46.

[[]{#Document0zzFN_F109
.anchor}[\[FN109\]]{.underline}](#Document0zzFN_B109). See BATTELLE
OPTIONS STUDY, supra note 51, § 6.0 (discussing costs of acquisition of
electric power conservation and supply resources); WSEO I, supra note 1,
at 8-11.

[[]{#Document0zzFN_F110
.anchor}[\[FN110\]]{.underline}](#Document0zzFN_B110). See PNUCC Options
Paper, supra note 7, at 48 (discussing the value of an option to its
sponsor).

[[]{#Document0zzFN_F111
.anchor}[\[FN111\]]{.underline}](#Document0zzFN_B111). The price
allowable under federal statute may be uncertain. Id. at 47. The
negotiating stance of BPA is also affected by considerations of how
purchase of options will affect the stability of and increases in
consumer rates. Id. at 31-34.

[[]{#Document0zzFN_F112
.anchor}[\[FN112\]]{.underline}](#Document0zzFN_B112). The PNUCC notes
the importance of according optioned projects the same priority in
processing regulatory clearances as for projects that are acquired.
PNUCC Options Paper, supra note 7, at 15.

[[]{#Document0zzFN_F113
.anchor}[\[FN113\]]{.underline}](#Document0zzFN_B113). See Redman, supra
note 79.

[[]{#Document0zzFN_F114
.anchor}[\[FN114\]]{.underline}](#Document0zzFN_B114). For instance,
flexibility can be enhanced by choosing technologies that have low
capital costs and high running costs. That way, a project that is little
used does not exact a high penalty. So risk management may be an
unrecognized argument for burning oil in combustion turbines, a resource
possibility that conflicts with the national goal of limiting dependence
on imported petroleum. Powerplant and Industrial Fuel Use Act of [[1978,
Pub. L. No.
95-620]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000819&DocName=USPL95-620&FindType=L),
92 Stat. 3289 (codified at scattered sections of 15, 19, 42, 45 & 49
U.S.C. (1976)). For a general discussion see Herzog, The Coverage of the
Fuel Use Act: How to Avoid Unpleasant Surprises, 13 NAT. RES. L. 553
(1981).

[[]{#Document0zzFN_F115
.anchor}[\[FN115\]]{.underline}](#Document0zzFN_B115). The insurance
value of an option should decrease as the cost of power from that option
increases. A low-cost option is likely to be developed anyway, and thus
the ability to delay or terminate it is less valuable than for an option
that would produce power at higher cost. The cost of an option may rise,
however, for projects deferred into the future. PNUCC Options Paper,
supra note 7, at 11.

The PNUCC also observes that the value of an option to the region must
also be weighed against the budgetary and financial constraints facing
the Bonneville Power Administration. Id. at 28-30.

[[]{#Document0zzFN_F116
.anchor}[\[FN116\]]{.underline}](#Document0zzFN_B116). The Northwest
Power Act was written in the face of fears of imminent power supply
shortages during the 1980\'s. S. REP. NO. 272, 96th Cong., 1st Sess. 17
(1979), reprinted in LEGISLATIVE HISTORY, supra note 3, at 445. The
publication of the WERC FINAL REPORT, supra note 11, and the BPA 1982
FORECAST, supra note 9, has led to a substantial revision of
expectations in the region and among investors in the national capital
markets. The prospect of a period of electricity surplus has also
affected the outlook for the Council\'s regional energy plan, in that
utilities are no longer under immediate pressure to propose projects for
the plan.

[[]{#Document0zzFN_F117
.anchor}[\[FN117\]]{.underline}](#Document0zzFN_B117). The possibilities
of rapid change are illustrated by the residential power-exchange
authorized in the Northwest Power Act, supra note 2, § 5(c)(1), [[16
U.S.C. § 839c(c)(1) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839C&FindType=L).
Perhaps the most powerful impetus to passage of the Northwest Power Act
was the perception that large rate disparities between the wholesale
power costs of publicly and privately owned utilities had to be
ameliorated in substantial degree. (The disparities arose from the
preference and priority provisions of the Bonneville Project Act, [[16
U.S.C. § §
832d]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS832D&FindType=L)
& [[832f (1976 & Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS832F&FindType=L).
This is accomplished in the Act by providing for an exchange of power
between a utility and BPA; in this exchange, the utility surrenders
power at its average cost of generation (\'average system cost,\'
defined in section 5(b)(7) of the Northwest Power Act, [[16 U.S.C. §
839c(b)(7) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839C&FindType=L)
and receives power at the Bonneville Administrator\'s cost. The quantity
of power eligible for the exchange is limited to that sold to
residential customers, under § 5(c)(1) of the Act, [[16 U.S.C. §
839c(c)(1) (Supp. V
1981)]{.underline}](http://www.westlaw.com/Find/Default.wl?rs=++++1.0&vr=2.0&DB=1000546&DocName=16USCAS839C&FindType=L).
This exchange provision was written under the assumption that BPA
wholesale costs would continue to be lower than those experienced by
investor-owned utilities. That has not turned out to be the case,
however, and several utilities have now discontinued their exchanges
with BPA. Similarly, I have assumed in this article that an option
developed within the riskmanagement framework will continue to be
desirable to all affected parties, including the project sponsor, BPA,
and the Council. Rapidly changing relative costs and shifts in demand
forecasts\--both common during recent years\--could readily invalidate
this assumption.

[[]{#Document0zzFN_F118
.anchor}[\[FN118\]]{.underline}](#Document0zzFN_B118). See ELECTRIC
POWER, supra note 5, ch. 3, for a parallel analysis of the Hydro-Thermal
Power Program, which faltered, in part, because it sought region-scale
objectives without adequate commonality of interest among its autonomous
participant utilities.

[[]{#Document0zzFN_F119
.anchor}[\[FN119\]]{.underline}](#Document0zzFN_B119). Id. ch. 2-3.

END OF DOCUMENT