HomeMy WebLinkAboutAgenda Packet 03/23/2011IV. Adjournment
City Council Special Meeting /Utility Advisory Committee
City Hall Council Chambers
Port Angeles, WA 98362
March 23, 2011 5:00 PM
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AGENDA
I. Call To Order
Roll Call
111. Information Only Items:
A. Bonneville Power Administration Residential Exchange Program
Settlement Agreement Workshop
PORTANGELES
W A S H I N G T O N U. S. A
Utility Advisory Committee Memo
Date: March 23, 2011
To: City Council and the Utility Advisory Committee
From: Larry Dunbar, Deputy Director of Power Systems
Subject: Bonneville Power Administration Residential Exchange Program Settlement
Agreement Workshop
Summary: A settlement agreement has been offered for City Council consideration regarding the
Bonneville Power Administration's Residential Exchange Program. A workshop will be held this
evening with presentations by the Western Public Agencies Group and the Bonneville Power
Administration.
Recommendation: For information only, no action requested.
Background /Analysis: The Bonneville Power Administration (BPA) Residential Exchange
Program (REP) was established by Congress under the Pacific Northwest Electric Power Planning
and Conservation Act of 1980, which was intended to provide rate relief to residential and small
farm customers served by higher -cost electric utilities. Its roots go back to the 1970s when
electricity rates between public and private utilities began to diverge sharply. Public preference to
the low -cost power from the federally based generation system was at the heart of the debate. The
City is one of numerous electric utilities that is a stakeholder in the program, since it shares the
cost of providing the benefits to higher -cost utilities that are eligible to participate in the program.
The settlement agreement is a very complicated and significant issue for the City's Electric Utility
and will affect future wholesale power costs for the next 17 years. A workshop will be held this
evening and the presenters include Mr. Terry Mundorf with the Western Public Agencies Group
and Mr. Chuck Foreman with the Bonneville Power Administration. The presentations will
include background information on the program and a summary of the advantages and
disadvantages of the proposed settlement agreement. A factsheet titled "A history of BPA's
Residential Exchange Program" is attached for additional information.
The deadline set by the BPA to accept or reject the settlement agreement is April 15, 2011. A
special Utility Advisory Committee meeting has been scheduled on March 28, 2011 to consider a
recommendation to City Council on the settlement agreement. The City Council will be asked to
either accept or reject the settlement agreement at its April 5, 2011 regular meeting.
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B O N N E V I L L E P O W E R A D M I N I S T R AT I O N
fact
e
A history of BPA's
Residential Exchange Program
On May 3, 2007, the U.S. Ninth Circuit Court of
Appeals ruled on two lawsuits that have significant
implications for the Bonneville PowerAdrninistra-
tions Residential Exchange Program (REP). In
light of the Court's decision and the heightened
interest it has created over -the REP BPA has pre-
pared this history_and background of the REP.
The REP was established in Section 54) of the
Pacific Northwest Electric Power Planning and
Conservation Act of 1980 (known commonly as the
Northwest Power Act). The goal of the program has
been,lo provide rate 'relief to.Northwest residential
andsmall -farm customers served by high -cost
investor -owned utilities, as well as to residential
and small -farm customers served by high -cost
utilities with preference rights. At the same tithe,
Congress intended to limit the financial exposure of
public utilities to certain costs occurring under the
Northwest Power Act.
In crafting Section (5), ..Congress directed that the.
benefits ofthe Federal Columbia River. Power
System (FCRPS) would be shared with those
Northwest utilities:whose average system cot or
ASC (average cost ofre.sources)- -was high: relative
to BPA.s applicable Priority Firm Exchange rate.
The benefits BPA provides through the program
must be passed on to each utility's residential and
small faun customers and cannot be used for any
other purpose, such as profits or to subsidize other
aspects ofa utility's business.
F rom its start, the Residential Exchange
Program (REP) has been a source of nearly
continuous controversy. Its roots go back to
the 1970s when electricity rates between public and
private utilities began to diverge sharply. Public
preference was at the heart of the debate between
public and private interests.
Historically, private and public utility rates had been
comparable. This changed after 1973 when, faced
with likely energy shortages. BPA halted firm power
sales to the region's investor -owned utilities. The
rates of some IOUs then began to rise sharply.
Oregon drafts DRPA legislation
At that point, Oregon's Public Utility Commissioner
awarded a 90 -day contract "to find a legal way to
overturn the preference clause,' thus qualifying
Oregon's private utility customers for the same
June 2007
electricity rates that public power customers enjoy."
When it appeared preference could not be overturned
legally, the state turned to an innovative solution.
In 1977, the Oregon state legislature approved form-
ing the entire state into a Domestic and Rural Power
Authority (DRPA), which was to lay claim as a
publicly owned utility to federal hydropower to
benefit all of the state's citizens. DRPA was to be-
come effective March 1, 1979, if no federal energy
bill addressing the problem had been passed. The
deadline later elapsed because, by that time, it
appeared national legislation was imminent.
1 Section 4 of the Bonneville Project Act of 1937 grants public
bodies and cooperatives priority access to federal power.
This is known as the preference clause.
In 1977, the Pacific Northwest Utilities Conference
Committee (PNUCC), which includes both public
and private utilities, presented draft legislation "for
discussion purposes" to the region's congressional
delegation to address multiple issues precipitated by
growing concern about power shortages. Fearing their
right to first call on federal power would be curbed,
Snohomish PUD and Seattle City Light broke ranks
and opposed the draft. Snohomish introduced rival
legislation aimed at protecting public preference.
Public preference challenged
As various proposals emerged, the fight over prefer-
ence heated up. Washington Governor Dixie Lee Ray
dubbed it "a regional civil war."
Idaho threatened to follow Oregon's lead to create a
domestic and rural power authority. The executive
director of the Washington Public Utility District
Association declared DRPA "nothing but a facade to
protect the profits of private power companies serving
his [Oregon governor's] state."
In February 1978, the governors of Oregon and Idaho
declared BPA "must honor the commitments in acts
of Congress that domestic and rural customers have
first call on energy from the Federal dams that are
even more basic than those of what BPA calls prefer-
ence customers."
BPA Administrator Sterling Munro strongly defended
preference. His view was that the way to get cheap
federal power to the three "have -not states was to
increase the size of the resource pie, rather than do
away with preference. Oregon Congressman Robert
Duncan responded, "If the preference clause isn't
changed. then we'll bust the sonofabitch in a lawsuit.
The people of the Northwest, all of the people of the
Northwest, are entitled to similar energy rates, and
they should share the burden of those costs."
By the late 1970s, a number of proposals were
coalescing into what eventually would culminate in
the Northwest Power Act. Any legislation would have
to pass through the Senate Energy and Natural
Resources Committee, headed by Senator Henry
"Scoop" .lackson. Jackson, who was from Washington
2
state, was an advocate of public power and not overly
sympathetic to the public private power rate disparity
arguments. Eventually, however, he realized that, if
the legislation was to have any chance, it had to deal
with the issue. Otherwise, the principle of preference
would be at risk.
DSI "subsidy" paves way
for exchange
A breakthrough came when the direct service indus-
tries, facing expiration of their contracts, agreed to
pay significantly higher rates for a limited period in
return for new 20 -year contracts. At the time "assured
supply" was more important to them than price. Under
this arrangement, public power would continue to get
first call on federal power, but a "subsidy" from the
DSIs (the higher rates the industries were willing to
pay) would offset and lower IOU rates. This `money
deal," which only covered five years, paved the way
for an "exchange clause" in the new legislation.
The exchange provision allowed BPA to offer IOUs
and certain public power entities that owned higher
cost generating facilities a quantity of power at BPA's
standard rates equivalent to the total needs of those
utilities' residential and small -farm customers. In
exchange, BPA would accept from these utilities an
equal quantity of power at their average system costs.
No power needed to change hands; in reality, it was
primarily a monetary paper transaction. Under the
exchange, the utilities were required to pass on the
benefits to their residential and small -farm customers
in the form of lower rates.
Section 7(c)(1) of the Act addressed the DSI provi-
sion saying that DSI rates shall be established for the
period prior to July 1, 1985, at a level sufficient to
recover the costs of resources required to serve the
DSIs' loads and "the net costs incurred by the Admin-
istrator pursuant to Section 5(c) of this Act." Section
5(c)(1) stipulates the exchange of power with eligible
utilities requesting such an exchange.
2 The "have -not states" refers to Oregon, Idaho and western
Montana, which, unlike Washington, are served primarily by
investor -owned utilities that do not have preference to BPA
power.
Not all the DSIs were happy with the arrangement.
In August 1978, Reynolds Metals objected, saying the
draft bill language placed too much of the burden of
exchange costs on the DSIs. At the time, the alumi-
num industry had a great deal of leverage as it was
providing enormous benefits to the region in terns
of wages, freight services and state and local taxes.
The industry had provided about 30 percent of BPA's
revenues.
NW Power Act changes
regional landscape
After several stops and starts, the Northwest Power
Act finally emerged and was signed into law in
December 1980. The Act's exchange provision
extended benefits of the federal system "at cost" to
2.5 million residential and small -faun consumers of
IOUs and a handful of consumer -owned utilities that
had relatively high ASCs.
To win public power support while the Northwest
Power Act was being developed, or at least to counter
opposition, an amendment had been added in the
form of a rate test to provide some cost protection to
the preference customers' rates. This is the 7(b)(2)
test. which compares costs developed pursuant to the
Act with costs reflecting five specified assumptions
listed in Section 7(b)(2). In very general terms, it was
designed to ensure public customers would pay BPA
no more than if their rates had been developed based
on the five assumptions.
BPA is required to formulate a hypothetical case to
assess what costs would have been by using the five
assumptions in Section 7(b)(2). if the rate test shows
preference customers would have to pay more for
firm power under actual rates than under the hypo-
thetical case, the Administrator must lower the rates
of public utilities to eliminate the excess costs and
shift the burden to BPA's other customers. The Act
contains five assumptions under Section 7(b)(2) to
be used in determining what the hypothetical world
would look like.
The language in Section 7(b)(2) is complex and has
been subject to differing interpretations. Former BPA
3
he_7(b)(2) rate test_
The Northwest Power Act provides thr ough
cUn 7(b) a co m
formula (rate tes
that, O in:general t erms shields pr
ers from certain impacts of the Northwest Power.
Act. Basically; this rate testis designed to ensure
that the cost of the Residential E' change "Pro
gram and other factors wherrconsidered to'geth
er do notraise the rates of public, utilities beyond
what they would have been,absent the Northwest
Power Act.
Section 7(b)(2)_ineludes five assumptions; the'
Administrator uses to develop.a,set of Costs'
s 'compared with a ,set of costs reflecting they
Northwest, Act. This compari is use
io setting'preferencc.rates (See ;box on five' i
assumptions.)
I Section 7(b)(2) triggers th an amount
ofcosts isallocated.to rates'other than the PF.
(Priority Finn) power rate .which is the raietla
applies to: preference: customers'. requirements
roads
Consequei tiv BPA develops a PF Exchange
rate ter'RE loa d s. that inc l u des costs fr any
Section 7(b)(2) trigger amount. if there =i's a
trigger, the PF Exchange rate is i than the
PFPreference rate,:and th di
t hePF Excha rate a nd the utility s ASC, j
multiplied the u tilit y s resident al andsma'
f arnt load, determines the RE,P benefi
lualifying'
Administrator Peter Johnson said of this section,
I know how Alice felt when she stepped through
the mirror. We seem to have entered an unreal world.
The assumptions direct BPA to hypothesize power
supply arrangements between itself and its customers
arrangements that are quite different from reality.
The Act bounces us back and forth between what
might have been had the Act not been passed and
what is."
he five
Sectioh 7(b)(2) includes five assumptions the
Administrator is to observe in setting preference.
ates. These assumptions envision a world that
contrasts with the world under, the Northwest Power
Act. In other words the Administrator must assume
that in this hypothetical world:
1. BPA is not engaging in an exchange of power
with IOUs and consumer -owned utilities to provide:
rate relief tothose utilities' residential and small-
farm customers.
2. 13PA's pub cus tomers wou serve certain
Of Of the direct service mdustries with 1 00, per fine
t h e The indush ies that: Would" served by tlic
public utilities are (a) those served by BPA
and (b) those that are `situated within or adjacent to
t he serv terr of the public custom
assumptions
preference customers load;including'tfie;'
DSI loads' mentioned in the second assumption.
ould be served first with Federal Base System"
power.
4. ff. the, preference customers require more power:
to serve their loads than'.federal resources can`
supply, the additional power to meet these needs
would be acquired"from "certain specified sources
This additional power, would be provided in a least
cost -first manner. y
.`There are.no dollar: savings to the preference
customers as-a result of reduced financing costs due
to'BPA backing' of resource acquisitions, and no
reserve benefits due to the'Administrator's actions
-Under the Act accrue to them.
In 1983, BPA sought to clarify Section 7(b)(2) and,
after an initial round of comments, published a
"Notice of Proposed Legal Interpretation of Section
7(b)(2)." After adopting the legal interpretation, BPA
developed a Section 7(b)(2) Implementation Method-
ology. BPA published the Implementation Methodol-
ogy, which reflected its legal interpretation of 7(b)(2),
in the Federal Register in March 1984. Subsequently,
BPA developed computer models,' in consultation
with customers, for the rate test.
The 7(b)(2) rate test has triggered several times. In
BPA's 1996 and 2002 power rate cases, the upward
pressure on the PF Exchange rate was significantly
more than in previous years. In the WP -96 and
WP -02 rate cases, due to high 7(b)(2) triggers, the
PF Exchange rate was 8.3 mills per kilowatt -hour and
13.7 mills per kilowatt -hour higher, respectively, than
the PF Preference rates.
ASC Methodology established
BPA established its initial Average System Cost
Methodology in 1981, issuing a Record of Decision
on Aug. 26 of that year and filing the methodology
with the Federal Energy Regulatory Commission
4
the following day. FERC granted interim approval
effective Oct. 1, 1981. and final approval of the ASC
Methodology on Oct. 6, 1983 (retroactive to 1981).
At its inception, the REP was implemented through
Residential Purchase and Sale Agreements (RPSA)
first executed in 1981. These contracts established
exchange benefits only through July I, 2001. Between
1981 and BPA's Subscription Strategy proposal, all of
the RPSAs held by the utilities that had received REP
benefits had been settled, except for one, which was
in "deemer" status.'
BPA's 1981 RPSAs did not require a customer to own
generation or transmission facilities to qualify for an
RPSA. Utilities were able to include wholesale
purchase power expenses and wheeling contracts with
third parties as costs to establish an ASC. Distribution
costs were excluded from the ASC calculation.
3 BPA used a computer based model known as the Supply Pricing
Model (SPM). The model simulated the rate setting process.
4 BPA's 1981 RPSAs included a provision described as a deemer
account. Deemer referred to a status wherein a utility sets its
ASC equal to BPA's PF Exchange rate and does not receive
positive monetary benefits but accrues a negative balance that
must be worked off before resuming receipt of additional
monetary benefits.
Average System' Cost
A n sA C(' ran, »conic tha aver c resourc
wen utIlltY
An AS can of by Iaw;t
source costs to,serve ne
ra- regional toad or the:..`
cos Th dca c mated prior to commer
alation includes a
etierally, power costs''
d certain an ASC, a i costs are currently
d in the hough `distribution costs
s with marketpurebases:
own ge are most
C are higher neration than BPA's
many ofthe North
itilities own coal or gas-
they have had higher
change rate.
BPA's 1981 RPSAs included a number of contractual
terms and conditions describing EPA's right to
purchase power in lieu of the utility's resources
priced at its ASC. These reflected the electric power
industry of the period and assumed that a utility
would be developing its own resources or entering
long -term purchase power contracts to serve its loads.
BPA revises ASC Methodology
From the start, things did not go smoothly. The DSIs,
who were bearing the cost of the exchange through
1985, complained that the IOUs were including
inappropriate costs and overhead in their average
system costs. In 1983, Northwest Aluminum News
wrote, "The main problem and a monumental
one is that some participating utilities are using
the exchange to recover costs other than 'resource'
costs Some of the questionable costs include items
such as taxes, overhead, and expenses related to
uncompleted or discontinued power plant projects."
The IOUs denied the costs were improper. At the
same time, public utilities that weren't participating
in the exchange complained that attempts to include
inappropriate costs in the ASC calculation were driv-
ing up the costs of power they were buying from BPA.
5
Beginning in 1983, the DSIs and public agency
customers sought a change in the ASC Methodology.
They had a number of concerns, including perceived
abuses to the system related to the attempted inclu-
sion of terminated plant costs. BPA had previously
removed terminated plant costs from an ASC filing
made by an exchanging utility.
BPA Administrator Peter Johnson agreed that the
exchange was "not working as Congress intended."
A BPA issue alert described the existing methodology
as "unworkable, expensive. time consuming, and
difficult to administer." Consequently, BPA staff
recommended tighter procedures for computing
the ASC.
Section 5(c) of the Northwest Power Act provides
that the Administrator shall develop an ASC Method-
ology in consultation with the Northwest Power and
Conservation Council, the Administrator's customers
and appropriate state regulatory bodies. BPA initiated
a consultation process open to the public to begin
revising its ASC Methodology to address multiple
issues.
These issues included the source data for the method-
ology, determination of whether transmission costs
should be treated as resource costs, subsidization of
construction work in progress, treatment of equity
return, treatment of income taxes, determination of
generating resources that could be included in com-
puting ASC, treatment of affiliated fuel costs, includ-
able conservation costs and functionalization between
subsidized and nonsubsidized accounts. A Federal
Register notice on the consultation process was issued
in October 1983.
5
In the context of the REP, "in lieu' comes up when the market
price of power (or the price of other resources) is less than the
exchanging utility's average system cost. In that case, the
Northwest Power Act allows BPA to purchase power in lieu" of
exchanging at the utility's ASC. BPA would buy power at the
market or resource rate and sell to the exchanging utility at the
PF Exchange rate, thus reducing the level of benefits to the
difference between the market price and PF Exchange rate.
The utility would then have to find something else to do with the
high -cost resources that have been "in lieued." Or, instead of
being stuck with unwanted power, it could deem its ASC to be
equal to the cost of the resource BPA would have acquired and
sold to the utility. Either way. BPA saves on a unit basis the
difference between the utility's ASC and the lower in -lieu
resource cost.
After taking regional comment, BPA published a
proposal on a revised ASC Methodology in February
1984 and, after a public comment period, issued a
record of decision on its revised ASC Methodology in
June 1984. In that year, nine IOUs and 16 public
utilities were participating in the exchange.
IOUs challenge ASC revisions
Although the IOUs challenged the ASC Methodology
change in the FERC proceeding, FERC approved the
revised methodology. A number of IOUs challenged
the change in the Ninth Circuit Court of Appeals, but
the Court upheld BPA's decision (PacfiCorp v. Fed.
Energy Regulatory Comm 'n, 759 R2d 816 ((9th Cir.
1986)) in 1986. While the Court's opinion upheld the
revised ASC Methodology, it held that it did not
"sanction any permanent implementation of these
exclusions." Id. at 823. Since then, the IOUs have
argued that the Court upheld the 1984 ASC Method-
ology as a `temporary" change to address terminated
plant cost issues and did not intend a permanent
change.
The ASC Methodology provides for future changes.
Under the ASC Methodology, the Administrator may
initiate a consultation process to determine whether to
change the existing ASC Methodology at his discre-
tion or upon request from three quarters of utilities
with Residential Exchange contracts, three quarters
of BPA's preference customers or three quarters of
BPA's DSIs (which was relevant at the time).
Arguments continued into the 1990s as IOUs disputed
BPA's calculation of the ASCs and other determina-
tions related to the REP. Throughout the decade the
disputes were essentially continuous. Key elements of
the disputes included benefits under the RPSAs not
enough in the IOUs' opinions and too much accord-
ing to the publics and DSIs as well as BPA's ASC
Methodology, utilities' ASCs, deemer balances, `in
lieu" transactions and BPA's PF Exchange rate.
Region conducts
Comprehensive Review
The advent of deregulation of the electric power
industry in the 1990s changed the industry dramati-
6
cally. Utilities no longer solely constructed generation
or made long -term purchases. Increasingly, they
purchased power on the wholesale market from
independent producers, wholesale marketing entities
and others, and some purchases were short-term. BPA
began to face tough competitive challenges, and some
questioned the agency's ability to fit into the newly
deregulated world.
In the mid- 1990s, the Department of Energy, BPA and
the governors of the four Northwest states all called
for a Comprehensive Review' of BPA's future role in
the Northwest. One of the things that came out of the
Comprehensive Review recommendations was a pro-
posed Subscription process that would set parameters
for allocating federal system benefits. This was pre-
cipitated by the fact that power sales contracts custom-
ers had signed with BPA were due to expire in 2001.
The Comprehensive Review, which published a final
report in December 1996, took the opposite stance of
an earlier BPA Administrator, Sterling Munro, who
had said the way to spread the benefits of the federal
system was to increase the size of the pie. Instead, the
Comprehensive Review said BPA should get out of
the business of acquiring new resources to meet
customers' load growth, except in those cases where
the customer would bear the additional costs.
The Comprehensive Review Steering Committee
encouraged BPA and other parties in the region to
explore a settlement of the REP with the region's
IOUs based in part on a sale of power to them rather
than the historic practice of monetary payments.
Congress helps stabilize exchange
By the mid- 1990s, deregulation of the electric utility
industry, spiraling fish costs brought by Endangered
Species Act filings and reduced hydro supply had
pushed BPA rates up. The most important factor,
however, was the decrease in market price of power
due largely to the entry of independent power produc-
ers selling gas -fired generation. As market prices
6 The formal name of the review was the Comprehensive Review
of Northwest Energy Systems.
dropped, some BPA customers removed load from
BPA. For the first time, BPA's PF Exchange rate was
higher than many of the utilities it was exchanging
power with. As public power customers sought to exit
contracts, concerns arose over whether BPA would
have adequate customers to cover its costs.
In August 1995, BPA reported "The calculation
7(b)(2) required by the law has forced BPA to
make the most significant reduction in Residential
Exchange benefits in 11 years. The proposed reduc-
tion could cause up to 45 percent of the region's
residential and small -farm customers to see an
increase in rates." BPA cited increased competition,
especially from natural gas, and said for the first
time in its history, BPA has lost wholesale customers
to private utilities. At the time, BPA had been
paying approximately $200 million a year to utilities
participating in the REP.
BPA's Initial Proposal in its 1996 power rate case
indicated a large reduction of benefits under the REP
starting in fiscal year 1997. BPA was assuming REP
benefits of about $65 million a year. Concern about
reduced benefits prompted Congress to take action.
The Energy and Water Development Appropriations
Act of 1996 specified setting 1997 exchange benefits
at the 1996 level of $145 million for the one -year
period. BPA was to distribute the benefits to each
participating utility at the percentage share each
received in fiscal year 1995.
In the 1996 Conference Report of the Energy and
Water Development Appropriations Act, Congress
recognized BPA's authority to implement in lieu
transactions, among other actions, which could effect-
ively terminate the residential exchange after 2001."
The report went on to say, "Consistent with the
regional review, Bonneville and its customers should
work together to gradually phase out the residential
exchange program by October 1, 2001." BPA,
however, could not eliminate implementing the REP
without direct action by Congress to change the law.
In September 1997, BPA and the Northwest Power
and Conservation Council jointly launched a review
of BPA's costs. The purpose was to set the stage for a
7
successful Subscription process by providing further
cost cutting recommendations to build customer
confidence that BPA was doing all it could to contain
costs. Among the recommendations, the Cost Review
said the REP made no sense in the current market-
place and should be eliminated, although this could
not be accomplished without legislative change.
In early summer 1996, Puget Sound Energy, Pacific
Power and Portland General Electric expressed
interest in a possible settlement of REP disputes. BPA
entered negotiations with the three IOUs regarding a
settlement of such disputes but deferred negotiations
after failing to reach agreement on the total dollar
settlement. Eventually, BPA settled with Puget in
January 1997 and with Pacific in April of that year.
BPA settled with PGE, then owned by Enron, a year
later in April 1998. These agreements specified that
they did not set precedents for how the Residential
Exchange would be handled after 2001. Payments
to the IOUs for the 1998 -2001 period averaged
$59 million annually.
As it turned out, 1996 was the last year that exchange
benefits were determined through the traditional REP
process (i.e., Appendix 1 filings, calculation of ASCs
and PF Exchange rates). Congress set the level of
exchange benefits for 1997. Following that, benefits
were determined through the settlement agreements.
Such settlements had been recommended by the
Comprehensive Review and Congress. These settle-
ments had the advantage of being far less labor
intensive. Running the regular REP required about
50 BPA staff as well as significant numbers of staff
from utilities.
In February 1995, BPA listed four key pressures driving up
its rates: 1) protracted drought; 2) increased salmon costs;
3) generation debt service due to the way refinancing for Wash-
ington Public Power Supply System bonds had been structured;
and 4) additional generation costs due to short-term purchases
and new generation projects including Tenaska, a gas -fired
combustion turbine.
a Puget had a Periodic Rate Adjustment Mechanism (PRAM) to
true up rates two years after the end of each rate period. In
1991, BPA and Puget formulated a "true -up" mechanism to
permit an accurate determination of Puget's ASC benefits in
conjunction with the Washington Utility and Transportation
Commission's PRAM. PRAM true -up benefits were to be paid
two years after the end of the exchange period.
2000 REP Settlements crafted
In the late 1990s, the market began to change as
natural gas prices began to rise. BPA's Competitive-
ness Project, launched in 1993. was paying off in
terms of improved financial performance and cus-
tomer confidence. BPA's net revenues for 1997 were
the best since 1991. In 1998, BPA launched a Sub-
scription process generally consistent with recom-
mendations from the Comprehensive Review. It was
designed to culminate in new 10 -year power sales
contracts for the post -2001 period.
As part of the Subscription Strategy, BPA proposed to
either continue the traditional REP through agree-
ments known as Residential Purchase and Sale Agree-
ments (RPSA) or enter into negotiated settlements of
REP disputes for the FY 2002 -2011 period. Such
settlements were intended to provide benefits for the
IOUs in return for their waiver of claims. In the
settlements, the benefits reflected possible outcomes
of ASC determinations and the effect of Section
7(b)(2) on BPA's PF Exchange rate.
Key Issues can swing R
f
When BPA does a 7(b)(2) test it must develop a
.,hypotheticalcase to determine what the costs to
preference customers would have been under the.
five 7(b)(2) assumptions There are manyiarcanei.
issues embedded in this calculation that have a
significant impact on the potential level of REP
payments
One assumption (see five assumptions box) is that,
if preference customers require more power,than"
federal resources can supply BPA would,acquire;
the'additional power to-meet these needs from a
resource stack:in a least cost first sequence This,
bring the question of w
up hat can beiincluded in
"EPA's iesource.staek in this hypothetical iwOrl d.
The issue ofwhether the-Mid-Columbia resources':.
uld be'included in the =BPA resource stacki carne'
up. in 1996 but e turned out to be moot since at the
trine there.wer enugh _Federal Base System
re to'imeet p without these.
Fv
additional resources At the time BPA assumed
that _only the'resourcesexpo could be. included"
in t he resource stac
The issue next arose in 2002 where it once again,+
became moot.. During the Ave -2007 power rate
case the issue was not litigated because of a.partial
settlement. However the next time; BPA develops
rates this is likely to bean i ssue as it remains an
open question.,
y r
BPA has calculated thatithis issue alone would`
create a difference between the IOUs receiving
$30 million annually, versus $260 million annually,;
There are other similarly arcane issues that canF
swing the benefit levels; substantially
An example is. the Mid Columbia resources not
dedicated to. public load,(approximately 800 MW
of hydropower which are relatively cheap) The'= LA' AA
publics that own t Mid Columbia dams sold' a
significant amount of the power to the IOUs by
a
contract It the Act is interpreted-To mean that these
Mid Columbia'resources sold to the IOUs can be
included in BPA s resource_stack in the hypothetical
BPA'slresodree costs would be compara
tively low That would mean a surcharge ismore
likely to beadded to the PF Exchange rate to ensure
the publics aren't paying more t t woul
haveln circumstance the f iv e 7(b
assumptions.. This would' r REP benefits
payments substantially
If;;however;,the Act means that'in the hypothetical
case those Mid Columbia resources dedicated'.to
IOU load areunavailable to BPA, then BPA would
have to go tgithe next cheaPeStiesourcelsin the
resource stack, which =much more expensive
the Mid Coimbra hydro This` makes,7(b)(2) iess
likely to trigger andtlierefore means higher REP
benefits ifor the IOUs
8
The concept of substituting a power sale for the
"paper" exchange was discussed extensively during
BPA's public involvement process for Subscription
and was supported by many public utilities and other
interests, as well as IOUs.
BPA's proposed settlement of REP issues had a value
of $140 million a year to be provided in the form of'
both a power sale and money. BPA estimated that,
under its traditional calculation of REP benefits, the
IOUs would receive $48 million annually for the
FY 2002 -2006 period. The IOUs were advancing a
position under which payments could be $323 million
or more annually. The IOUs' agreements, which were
for 10 years, provided power at a specified rate to
be determined in a Section 7(i) rate hearing and
stipulated monetary benefits were to be paid based on
a comparison of the REP settlement power rate and at
a rate related to market prices.
BPA offered the IOUs 1,800 aMW for the FY 2002-
2006 period with 1,000 aMW in the form of power
and the rest as cash payments. BPA also offered to
IOU and Public Agency Residential Exchange Benefits
(2005
O
O
O
d3
450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
rot r ^3 °s -/sPit r ho s rs %V0s WD'n 4t'it'ilz:V&` j n %bo
Fiscal Year
FYs 2007 through 2011 benefits were computed prior to the May 3, 2007, 9th Circuit decision.
9
provide 2,200 aMW during the 2007 -2011 period.
The intent at the time was that the 2,200 aMW would
be entirely physical power deliveries, although
whether the benefits would be power, monetary or a
mixture was not decided. BPA felt that such power
deliveries would be possible due to the expiration of
existing long -term surplus sales and public power's
interest in diversification due to market conditions.
This theory did not anticipate the West Coast energy
crisis along with its impact on the value of power,
public power's willingness to buy from BPA and the
impacts on IOU and BPA rates.
Through the settlement, BPA hoped to resolve long-
standing REP disputes, eliminate the administrative
burden of implementing the REP (i.e., processing
average system costs, filings, etc.) and align the
interests of the IOUs with BPA and its other custom-
ers by providing them benefits comparable to what
would have been provided within the range of
possible REP outcomes. BPA also hoped to provide
longer -term certainty through the settlements.
❑AII IOUs
All Publics
MI Puget Sound Energy
o PGE
PacifiCorp (UP &L)
PacifiCorp (PP &L)
NorthWestern Energy
Cl Montana Light Power
Idaho Power
M CP National
Avista Corp.
All six IOUs elected to execute 2000 REP Settlement
Agreements. The state public utility commissions
recommended how the benefits of the settlement
would be allocated among the IOUs and asked for
an additional 100 aMW for FY 2002 -2006. BPA's
decision making leading to adoption of these recom-
mendations involved extensive public review.
The publics go to court
Within 90 days of the execution of the 2000 REP
Settlement Agreements, a number of Northwest
public power entities challenged the agreements in
the Ninth Circuit Court of Appeals. Some IOUs filed
petitions, but the basis for such petitions was resolved
shortly thereafter. The petitions were consolidated
into Portland General Electric Co. v. Bonneville
Power Administration.
The public agencies alleged the settlements provided
more benefits to the IOUs than the Northwest Power
Act allowed. The parties argued that BPA lacked
statutory authority to settle disputes under the REP as
proposed and that the 2000 REP Settlement Agree-
ments must comply with Sections 5(c) and 7(b) of the
Northwest Power Act. They said that, by executing
the settlements, BPA did not comply because it failed
to implement the ASC Methodology, in lieu transac-
tions and BPA's PF Exchange rate based on the
7(b)(2) test. BPA believed it complied with the law
because it considered all of these factors in establish-
ing the REP settlements.
West Coast power crisis
shocks region
By the summer of 2000, West Coast power prices
were escalating rapidly. As a result, public power
customers were showing increasing interest in placing
substantial amounts of load on BPA for the post -2001
period. By the time contracts were signed in October
2000, it was apparent that BPA would need to acquire
approximately 3,000 aMW beyond its existing supply
to meet its contractual commitments to public utili-
ties, IOUs and DSIs with deliveries to begin in
October 2001.
1 0
In the winter of 2001, wholesale power prices explod-
ed. BPA estimated that it would need to raise rates
250 percent if it were to acquire the full 3,000 aMW
at the then current prices. In the first six months of
FY 2001 alone, BPA spent more than $1 billion
buying power. Facing this extreme situation, BPA
developed a three pronged load reduction program
that included conservation, reductions in power
demand by utilities and load curtailments by DSIs.
In May and June of 2001, BPA executed 2001 Load
Reduction Agreements with Pacific and Puget,
eliminating BPA's obligation to deliver power for the
FY 2002 -2006 period in exchange for cash payments.
The IOU agreements were structured so that BPA's
payment in FY 2002 was lower than the FY 2003-
2006 annual payments. These agreements to forego
power deliveries in exchange for a cash payment
eliminated BPA's need to buy large amounts of more
costly power on the market.
While the efforts to reduce BPA costs were largely
successful. public power utilities still saw their rates
go up 45 percent in October 2001. At the same time,
IOU REP benefits to Pacific and Puget increased
substantially as a result of the load reduction agree-
ments. Some public utilities whose rates historically
had been much lower than those of neighboring IOUs
suddenly found themselves having to raise their
residential rates above those of IOUs. Total benefits
flowing to the IOUs' residential and small -faun
consumers, including payments to reduce load on
BPA, rose to about $370 million annually, compared
to $58 million annually in the previous rate period.
BPA moves to lower public rates
An extended drought in the Northwest made it
difficult for BPA to recover financially from the West
Coast energy crisis and thus to lower power rates for
public utilities. BPA looked for new initiatives that
could further lower its costs and bring about rate
reductions.
Such cases are often referred to by the name of the first
petitioner.
In 2003, BPA proposed a global REP litigation
settlement with all BPA customers that was designed
to provide rate relief for public utilities. The settle-
ment was fragile from the start because it required
support of nearly 100 preference customers that were
parties to various lawsuits. The 2003 Litigation
Settlement ROD provided that, among other things,
if any preference customer failed to sign the stipula-
tion and other settlement documents within 90 days
after the effective date (Jan. 21, 2004), the proposed
settlement would be void.
The proposed settlement would have decreased
FY 2004 rates for public utilities by 7 percent (from
what they otherwise would have been) by eliminating
$200 million in IOU REP benefits and deferring
another $270 million of benefits into the five -year rate
period beginning in 2007. The proposed settlement
also would have settled lawsuits brought by public
utility customers regarding the level of benefits going
to IOU customers.
The settlement proposal failed for lack of sufficient
signatures. BPA received support from 86 customers,
while six opposed the settlement and others did not
respond formally.
Settlement "lite" offered
After the failure of the proposed global litigation
settlement, in 2004 BPA proposed contract amend-
ments to the underlying IOU settlements. This came
to be known as "settlement lite."
In April 2004, BPA sent a letter asking for comment
on a proposal in which Pacific and Puget would
waive S160 million of payments between 2004 -2006
and defer another $l00 million, plus interest, until
FY 2007 -2011 when BPA expected to be on better
financial footing. The amendments offered similar
terms to the other IOUs, and all six signed agree
ments. In return, the IOUs would receive greater
certainty about their benefits. The benefits were
defined as financial payments, not power deliveries.
The proposed agreement established a floor of
$100 million a year with an annual cap of $300 mil-
lion for FY 2007 -2011. By removing the $200 million
11
from power costs, FY 2005 -06 power rates were
6 percent lower than they otherwise would have been.
The majority of commenters approved the proposal.
The IOUs agreed to the new settlement primarily
because it gave them greater certainty as to how post
2006 benefits would be calculated. On May 25, 2004,
BPA published the 2004 Agreements Regarding
Payment ROD adopting the proposal to amend the
underlying agreements.
Clark requests exchange
In June 2005, Clark Public Utilities, headquartered
in Vancouver, Wash., sent BPA a letter requesting
exchange benefits. Clark had experienced a sharp rise
in its fuel costs for its gas -fired plant. Historically,
while the bulk of exchange benefits had gone to
IOUs, over the years more than 30 publicly owned
Northwest utilities had participated in the program.
All previously participating publics either had
terminated contracts or settled the amount of their
benefits.
BPA offered Clark an RPSA, which Clark signed in
August 2005. This initiated the analysis to determine
the utility's REP benefits. The following December,
BPA and Clark reached a settlement, with exchange
benefits scheduled to go into effect in January 2006.
As part of the settlement, Clark returned to BPA's
control area and replaced its power purchase contract
with a partial service product.
REP discussed as part of
Regional Dialogue
Since 2002, BPA has engaged with the region in a
Regional Dialogue aimed at defining BPA's future
power sales role after 2011 when current wholesale
power contracts with preference customers expire.
The future of the REP has been a prominent part of
these discussions involving both public and investor
owned utilities. These discussions, extending over
five years, focused on forging a regional consensus on
10 Certain provisions for Avista, Idaho Power, Northwestern and
PGE were different from those in Pacific's and Puget's contracts.
nttt t.:. it" fattlInntr4flttgrantrenWtTaillta
a new financial formula to settle REP disputes for the
2012 -2027 period. While no agreement was reached,
the parties did narrow their differences and were
prepared to continue discussions. BPA and the IOUs
agreed on principles for a new settlement, but further
progress was put on hold after the Ninth Circuit
decision on May 3, 2007.
Ninth Circuit weighs in
On that date, the U.S. Ninth Circuit Court of Appeals
ruled on two lawsuits that had Residential Exchange
implications. The first suit is known as the PGE
(Portland General Electric) suit and was filed against
BPA by numerous parties challenging BPA's 2000
REP Settlement Agreements with six IOUs (for the
FY 2002 -2011 contract period). Public utilities were
the primary petitioners, although investor -owned
utilities and industrial customers also filed petitions.
In the PGE case, the Court held that BPA exceeded its
settlement authority and concluded that the settlement
was not consistent with Sections 5(c) and 7(b) of the
Northwest Power Act, which established the Residen-
tial Exchange Program. The Court also said BPA
avoided the full statutory scheme of protecting
preference customers under Section 7(b)(2).
The second lawsuit, known as the Golden Northwest
suit, addressed, among other things, BPA's FY 2002-
2006 power rates. In this case, the Western Public
Agencies Group, Public Power Council and Grays
Harbor PUD had contended BPA improperly allo-
cated costs of the REP settlements to the PF Prefer-
ence rate. The Court referred to its ruling in the PGE
case, noting that the IOU settlements were unlawful.
The Court held BPA should not have allocated costs
of the settlement as business costs under Section 7(g)
of the Northwest Act.
BONNEVILLE POWER ADMINISTRATION
DOE /BP -3811 JUNE 2007
12
At the time of the Court's decision, the IOUs had
collectively been receiving about $327 million in
annual benefits. As a result of the Court's hearing,
BPA formally notified the IOUs" in writing of its
decision to suspend REP settlement payments imme-
diately due to the uncertainty created by the recent
Ninth Circuit Court rulings. BPA certifying officials
are personally liable if payments are made that are not
consistent with law, and, in this case, the Court's
rulings created substantial questions over whether
additional settlement payments are consistent with the
law. These payments amounted to about $28 million
each month to investor -owned utilities for their
residential and small -farm consumers.
11 The IOUs involved include Portland General Electric, Pacific
Power, Rocky Mountain Power, Avista, Puget Sound Energy,
Idaho Power and Northwest Energy. At the time of the settle-
ment, Rocky Mountain Power was part of PacifiCorp, parent of
Pacific Power.