HomeMy WebLinkAboutAgenda Packet 12/14/2010I. Call To Order
II. Roll Call
III. Approval Of Minutes For November 9, 2010
IV. Late Items
V. Discussion Items:
A. Consultant Agreement, Construction Management for First Street
Stormwater Separation, Project WW03 -2010
B. Amendment No. 9 to Brown and Caldwell Consultant Agreement
C. Bonneville Power Administration Initial Wholesale Power Rate Proposal
D. Retail Tiered Rate Methodology Study Retail Rate Design Update
(verbal report only)
E. Advanced Metering Infrastructure System Agreement
F. Western Public Agencies Group Consulting Agreement
G. Low- Income Home Heating Energy Vendor Agreement
H. Northwest Public Power Association Power Supply Planning Workshop
I. Utility Discount for Low - Income Senior Citizens and Disabled Citizens
(verbal report only)
VI. Information Only Items:
A. Conservation Loan Discounts Update (verbal report only)
B. Integrating Wind and Water Power (verbal report only)
C. Bonneville Power Administration Residential Exchange Program
Settlement Agreement
VII. Next Meeting Date January 11, 2011
VIII. Adjournment
N \uac \final \121410
Utility Advisory Committee
Jack Pittis Conference Room
Port Angeles, WA 98362
December 14, 2010 @ 3:00 PM
AGENDA
UAC Assigned
Councilmembers Present:
UAC Assigned
Councilmembers Absent:
III. Approval Of Minutes
IV. Late Items
Utility Advisory Committee
Council Chambers
Port Angeles, WA 98362
November 9, 2010
1:30 P.M.
L Call To Order
Chairman Di Guilio called the meeting to order at 1:30 p.m.
II. Roll Call
Chairman Dan Di Guilio, Cherie Kidd, Brooke Nelson
N/A
UAC Members Present: Vice Chairman Dean Reed, Paul Elliot
UAC Members Absent: N/A
Staff Present: Kent Myers (Arrived at 2:50), Glenn Cutler, Michael
Puntenney, Bill Bloor, Terry Gallagher, Dan McKeen,
Larry Dunbar, Phil Lusk, Kathryn Neal, Ernie Klimek,
Dennis McBride, Yvonne Ziomkowski, Rick Hostetler,
Teresa Pierce.
Others Present: Tom Callis — Peninsula Daily News
Chairman Di Guilio asked if there were any corrections to the minutes of October 12,
2010. Councilmember Reed moved to approve the minutes. Councilmember Nelson
seconded the motion, which carried unanimously.
A late memo titled "Combined Sewer Overflow Phase I - Update" was added to the
agenda under discussion items.
V. Discussion Items
A. Golf Course Road Waterline Repairs — Verbal Report Only
1
Ernie Klimek, Water Department Superintendent presented a PowerPoint
Presentation on recent waterline repairs of the twenty inch transmission line. The old
pipe was repaired by slip lining.
B. Equipment Purchase - Light Operations Line Trucks —
Verbal Report Only
Dennis McBride, Fleet Maintenance Manager shared information about staffs plan to
advertise the purchase of the Bucket Truck and Digger Derek early. McBride
proposed to discuss this event at the upcoming council meeting, so the bids could get
out by early January.
C. Combined Sewer Overflow Phase I — Update
Kathryn Neal, P.E., Engineering Manager, made a brief announcement of the
achievement of successfully submitting the CSO project loan application. Neal
described some of the negotiations they are discussing like the issues of handling of
potential contaminated soil and groundwater on the site, regulations outside of City
staff experience, and scope work.
D. Consultant Agreement: Combined Sewer Overflow Phase I,
Constructability Review
Michael Puntenney, P.E., City Engineer, discussed the constructible review's
complexity and the amount of savings the City should obtain. Puntenney explained
briefly the value of this review with the consultants, the length of time they will have,
and the costs. There was a brief discussion.
Paul Elliot moved that City Council should authorize the City Manager to sign a
consultant agreement for a constructability review for the Combined Sewer
Overflow Phase 1 project design. Dean Reed seconded the motion, which carried
unanimously.
E. Proposed Medic I Utility Rate Adjustments
Dan McKeen, Fire Chief, explained a brief background of the Medic I Utility Rate
Adjustments. McKeen described how the funding is established between the
transportation fees, monthly utility fee, and a general fund contribution. A cost of
service study was broken down into nine different Medic I usages between business
and residential information, this was done to determine the cost allocations for rate
adjustment for the 2011 budget. McKeen described the proposal that will be
announced at the City Council Meeting.
Dean Reed moved to recommend to the City Council to:
1) Conduct a public hearing then provide a first reading of the proposed
ordinance on November 16, 2010, and
2
2) Continue the public hearing on December 7, 2010, close the public hearing,
then provide a second reading and adopt the proposed ordinance.
Councilmember Nelson seconded the motion which carried, with
Councilmember Kidd in opposition.
F. Bonneville Power Administration Commercial and
Industrial Demand Response Grant Acceptance
Phil Lusk, Power Resources Manager, stated that Bonneville has issued a formal
grant award notification to the city and discussed the scopes, project development,
and contractual services. Lusk distributed a revised Utility Advisory Committee
Memo which included a new staff advised recommendation. A lengthy discussion
followed.
Councilmember Nelson moved to recommend that City Council authorize the
City Manager to sign a Memorandum of Understanding with the Bonneville
Power Administration and subsequent contract with the Bonneville Power
Administration or Global Energy Partners acting as a general contractor for the
Bonneville Power of Administration for up to $384,520 for the City's
Commercial and Industrial Demand Response Pilot Project, and make minor
modifications to the agreement, if necessary. Dean Reed seconded the motion,
which carried with Councilmember Elliot abstaining.
G. Energy Conservation Program Increase
Larry Dunbar, Deputy Director of Power Systems reviewed the past and future
planning for this program; he recommended that there be a staff member increase for
the conservation program beginning 2011 and the term of the employee will be
reviewed at the year end of 2013. There was a thorough discussion on staff funding,
job detail, work load, and operations.
Dean Reed moved to recommend that City Council add one full time equivalent
employee needed to support increased activities under the energy conservation
program as part of the 2011 proposed budget beginning January of 2011. Paul
Elliot seconded the motion, which carried unanimously.
H. Bonneville Power Administration Residential Exchange
Program Settlement Agreement"
Larry Dunbar, Deputy Director of Power Systems informed the UAC about the
ongoing issues with the settlement agreement, yet there is an meeting opportunity that
has been arranged on December 15 2010 to discusses and clarify the advantages
and disadvantages. There was a discussion about which councilmember's, UAC
members, and staff should attend; staff was directed to invite all council and UAC
members to attend.
3
I. Amendment No. 2 to Telecommunications Consultant
Agreement
Larry Dunbar, Deputy Director of Power Systems reviewed the recent replacements
and future schedule for redundant fiber optic plans and specifications. Dunbar
recommends that Columbia Telecommunications Corporation is used to review the
design and perform construction inspections. There was a brief discussion.
Councilmember Nelson moved that the City Council authorize the City Manager
to sign Amendment No. 2 to the Agreement with Columbia Telecommunications
Corporation in an amount not to exceed $9,900 for consulting services in support
of the Metropolitan Area Network, and authorize the City Manager to make
minor modifications to the Agreement, if necessary. Paul Elliot seconded the
motion, which carried unanimously.
J. Advanced Metering Infrastructure System Communications
Plan Consultant Agreement Amendment No. 1
Phil Lusk, Power Resources Manager, explained how Parker LePla is now positioned
to complete remaining tasks for developing a communications plan for the specific
residential demand response pilot project and implementing media materials for the
plans. There was an in -depth discussion about the specific costs and details of these
plans.
Councilmember Nelson moved that the City Council authorize the City Manager
to sign Amendment No. 1 to the Agreement with Parker LePla in an amount not
to exceed $69,801, and to make minor modifications to the agreement, if
necessary. Dean Reed seconded the motion, which carried unanimously.
VI. Information Only hems
A. Retail Tiered Rate Methodology Study New Large Single
Load
Phil Lusk, Power Resources Manager, explained the Electrical Utility retail rates and
how different policies for new large single loads would impact all rate payers. There
was a lengthy discussion on the future policy, what other agencies policies are, and
what needs to be prioritized.
B. Wireless Mobile Data System Grant Business Case
Evaluation Update
Larry Dunbar, Deputy Director of Power Systems, gave a power point presentation
reviewing the costs of operating and maintaining a wireless mobile data system for
public safety. Different mobile systems were introduced with examples from other
cities within the United States, for cost and program specifications.
4
C. Advanced Metering Infrastructure System Communications
Plan Presentation
Phil Lusk, Power Resources Manager, introduced Lynn Parker and Beth Woolley
from Parker LePla, to present the draft communications plan. A lengthy discussion
followed.
D. Advance Metering Infrastructure System Update
Larry Dunbar, Deputy Director of Power Systems, discussed about the acceptance,
communication plans, activities to evaluate and a presentation. Revised proposals
from Parker LePla have been received, a discussion about how the residential aspects
of this change need to be gathered and discussed. A brief discussion was followed.
E. Electric Utility Grant Status Report
Phil Lusk, Power Resources Manager, reviewed the grants provided to the Electric
utility in the last two years, which have been highly successful.
VII.
VIII.
Next Meeting Date:
Adjournment:
5
December 14, 2010 @ 1:30 p.m.
4:30 p.m.
Dan Di Guilio, Mayor Janessa Hurd, City Clerk
Dean Reed, Vice Chairman Sondya Wray, Administrative Specialist
PART NGELES
W A S H I N G T O N , U.S.A.
Utility Advisory Committee Memo
Date: December 14, 2010
To: Utility Advisory Committee
From: Kathryn Neal, P.E., Engineering Manager
Subject: Consultant Agreement, Construction Management for First Street Stormwater
Separation, Project WW03 -2010
Summary: Design is nearly complete for the First Street Stormwater Separation project.
Construction is scheduled to begin in downtown Port Angeles in February, 2011. The City issued a
Request for Proposals for construction management consultants, with Statement of Qualifications
due December 10, 2010. The proposals will be reviewed by the selection committee in December,
and a recommendation to authorize a contract will be brought to Council at the first meeting in
January. This project is funded by the National Park Service.
Recommendation: Forward a favorable recommendation to Council to authorize the City
Manager to sign a consultant agreement for construction management services for the First
Street Stormwater Separation project, and to make minor modifications to the agreement, if
necessary.
Background /Analysis: The First Street Stormwater Separation project is a component of the
Elwha River Restoration Project, and is funded by the National Park Service (NPS). Under an
agreement with NPS, wastewater from the Lower Elwha will be treated at the City's wastewater
treatment plant. The goal of the First Street Stormwater Separation project is to offset wastewater
flows in the City's system to ensure that Combined Sewer Overflows (CSOs) are not increased.
The project will collect stormwater from a four -block area of downtown Port Angeles which
presently discharges into the City wastewater system. This stormwater runoff will be redirected
through a new storm drain system into Valley Creek in order to reduce discharge during high flow
events that presently contributes to CSOs. The project includes construction of approximately
1,750 lineal feet of buried 18 -inch diameter storm pipe on First Street from Laurel to Valley Street
and adds new stormwater treatment to reduce pollutants delivered to Valley Creek. The project
will also reconstruct portions of the road surface between Laurel Street and Valley Creek.
N \UAC \Final \First Street Stormwater Separation Construction Management Consultant Agreement doc
Consultant Agreement, Construction Management for First Street Stormwater Separation, Project WW03 -2010
December 14, 2010
Page 2
The construction management consultant will assist the City in the selection and award process for
the construction contract as well as managing construction of the project. This includes inspection
and contract documentation as required by the Washington State Department of Transportation and
the American Resource and Recovery Act.
The City issued a Request for Proposals for construction management consultants in the Clallam
and Jefferson County area, with Statement of Qualifications due December 10, 2010. The
proposals will be reviewed by the selection committee in December, and a recommendation to
authorize a contract will be brought to Council at the first meeting in January.
Staff requests that the Utility Advisory Committee forwards a favorable recommendation to
Council to authorize the City Manager to sign a consultant agreement for construction
management services for the First Street Stormwater Separation project, and to make minor
modifications to the agreement, if necessary.
Date:
To:
From:
Subject:
• December 23
• January 10
• January 15
• January 20
• February 1
• February 15
• February 20
• March 14
• July 18
pORTANGELES
W A S H I N G T O N , U.S.A.
Utility Advisory Committee Memo
December 14, 2010
Utility Advisory Committee
Kathryn Neal, P.E., Engineering Manager
Amendment No. 9 to Brown and Caldwell Consultant Agreement
Summary: The detailed design of Phase 1 of the Combined Sewer Overflow (CSO) project is
approximately 90% complete. Additional elements of work critical to completing the design have
been identified and an amendment to Brown and Caldwell's contract is needed to complete the
design work.
Recommendation: Forward a favorable recommendation to the City Council to authorize
the City Manager to sign Amendment No. 9 to the Consultant Agreement with Brown and
Caldwell, in an amount not to exceed $178,100, which increases the maximum compensation
under the agreement from $3,742,791 to $3,920,891, and to make minor modifications to the
agreement, if necessary.
Background /Analysis: The detailed design of Phase 1 of the Combined Sewer Overflow
(CSO) Project is approximately 90% complete. Important project milestones were accomplished
recently, including Department of Ecology (DOE) approval of the 90% plans and specifications, a
Purchase and Sale Agreement of a portion of the Rayonier property to enable project construction,
initial consultation with Rayonier and DOE on environmental issues related to handling potentially
contaminated soils and groundwater at the site, and submittal for a State Revolving Fund low -
interest loan in the amount of $10 million. In response to DOE comments, and to support
completion of the design, additional work elements have been identified.
Upcoming project schedule milestones are:
Constructability Review comments to Brown and Caldwell
Phase I Environmental Assessment complete
Finalized Materials Management Plan from DOE and Rayonier
Final design submission from Brown and Caldwell
Preliminary notification of funding availability
Final Design signed and issued (after City review)
Advertise construction contract and construction management contract.
Notice to Proceed will be contingent on funding finalized.
Archaeological exploration and pre- construction sampling begins
Begin construction
N \UAC \DepDir \Consultant Agreement - Amendment 9 to BC - CSO Phase 1 doc
Consultant Agreement - Amendment 9 to BC - CSO Phase 1
December 14, 2010
Page 2
A description of additional design work needed from Brown and Caldwell to complete the design
phase, through contract advertisement and bid award, is provided below.
1 Description
Task 11.1 1 Project Management — through June 2011
Task 11.2 Property Description and Mapping — Local surveying firm work to
describe and survey the sale parcel and the easements on the
Rayonier site. Includes research, boundary line adjustment support
and recorded survey. This item is partially reimbursable by
Rayonier, under terms of the Sale Agreement.
Task 11.7 Standby Power Generation — DOE requires a permanent standby 10,000
generator for emergency power to the influent diversion structure
rather than a portable generator.
Task 11.12 Funding Assistance — Additional budget for assistance with securing
funding. Original estimate at $32,000 was funded for $10,000.
Final cost was $5,500.
Amount 1
$92,500
70,100
Funding is available from CSO reserves accumulated through rates and the Washington State
Public Works Trust Fund Loans.
5,500
TOTAL 1 $178,100 1
Staff requests that the Utility Advisory Committee forward a favorable recommendation to the
City council to authorize the City Manager to sign Amendment No. 9 to the Consultant Agreement
with Brown and Caldwell, in an amount not to exceed $178,100, which increases the maximum
compensation under the agreement from $3,742,791 to $3,920,891, and to make minor
modifications to the agreement, if necessary.
pORT NGELES
W A S H I N G T O N , U.S.A.
Utility Advisory Committee Memo
December 14, 2010
Date:
To: Utility Advisory Committee
From: Larry Dunbar, Deputy Director of Power Systems
Subject: Bonneville Power Administration Initial Wholesale Power Rate Proposal
Summary: The Bonneville Power Administration recently announced a proposal to increase
wholesale power rates by 8.3 %, which could increase the City's wholesale power costs by 14.2%
beginning October 1, 2011. There are no proposed increases to wholesale transmission rates
planned that affect the City.
Recommendation: For information only, no action requested.
Background /Analysis: On November 18, 2010, the Bonneville Power Administration
(BPA) announced its initial proposal under the new Tiered Rate Methodology (TRM) for an
overall average 8.3% increase to wholesale power rates beginning October 1, 2011, which would
continue through September 30, 2014. On December 7, 2010, BPA analyzed how their proposal
would affect the City and calculated a 14.2% wholesale cost increase. BPA's main costs driving
the proposed increase include maintenance and upgrades to the federal hydroelectric system, fuel
purchases and repairs at Columbia Generation Station, and improvement to dams and habitat
restoration to protect salmon and steelhead. Ms. Shannon Greene, BPA's account executive for
the City, was not available to attend to today's meeting to further explain the proposal.
BPA has also indicated that their initial proposal includes significant revenue risk and there is a
high probability that it may invoke the cost recovery adjustment clause (CRAC) which could
further increase the City's wholesale power costs beyond 14.2 %. Depending on several factors,
final wholesale power rates are normally much different than those initially proposed. There are
no proposed increases to wholesale transmission rates that affect the City.
Staff won't be able to verify the impact the proposed wholesale power rates will have on the City's
Electric Utility until March of 2011, when BPA is expected to provide the City its contract high
water mark, monthly quantity of demand at no charge, and the monthly quantity of heavy and light
load hour energy at no charge under the TRM. There are major differences between today's
wholesale power rate design and the TRM. Major differences include:
• The TRM includes a new take or don't take but pay fixed charge for 80 -90% of BPA costs.
• Under the current rate design peak demand is coincident with BPA and the City pays for each
kilowatt of peak demand, and under the TRM demand will be based on the City's peak and the
City will be provided a monthly quantity of demand at no charge.
• Heavy and light load hour charges and credits for consumption above and below the monthly
quantity of heavy and light load hour energy consumption provided at no charge.
N \UAC \Final \BPA Wholesale Power Initial Rate Proposal docx
Bonneville Power Administration Initial Rate Proposal
December 14, 2010
Page 2
The following information illustrates there are significant differences between current wholesale
power rates and the initial proposal under the TRM.
BPA's initial proposal for demand rates
Current Proposed; Increase , Current' Proposed' Increase,
January 1 $1.961 $9.74 397% July $1.61 __ $10.55 555%;
:February 1.99 9.75i 390% August 1.89 _ 10.99 481%;
r - -
March 1.85 9.36 406%; September , 1.96 ,iii.i8,,_ 430%j
,
April 1.74' 8.57' 393% =October 2.05, 9.35 356%
- - - - :
May 1.44 8.15' 466%1 November ' 2.19 9.45 332%1
June ' 1.32i 8.39: 536% 'December i 2.0' 10.6 i46
BPA's initial proposal for heavy load hour energy rates
Current, Proposed, Increase , Current Proposed Increase
January $0.02968 $0.02968: $0.04578 54%' July 1 $0.02457 $0 . 102%
:February: 0.03031. 0.04587 51%, _ _ August _ 0 781 0.05170 80%
'March 0.02812 0.94400: 56%1 September 0.62970 _ 0.04880' 64%i
April 0.02639 0.04028 5Voi ; October 0.03141 ' 0.04396 40%' ..„ ...
Ma _ 0.02204! 0.03833 74% November 0.03350 0.04448 33%
June ' 0.01995: 0.6949 98%, December 0.03496 0.04762 36%'
BPA's initial proposal for light load hour energy rates
Current Proposed Increase, _ __... _ . „ , Current: Proposed' Increase
January $ 0.02146 $6.03472 ' 62% July : $0.01799 , $0.03656 103%,
Fehruary: 0.02168 0.03486 6i°% 'August ii:oifizi : 0.03837' ioii..
March ' 0.02061 0:03293 60% September , 0.02384 , 0.03505 47%
...___,..,_ „.. ._,.
,April ' 0.01897 0.02976 , 57% 'October 0.02301 0.03415! 48%;
'May 0.01524 1 0.02307 51%, November ; 0.02443 0.03393 r • 39%'
; June 0.01059 0.02372, 124% 'December 0.02565 0.03745 46%'
The following link is provided for more information about BPA's initial rate proposal
h ttp ://www . boa eo \leo rporate/ratec ase/20 1 2/
Date:
ORT i NGELES
W A S H I N G T O N , U.S.A.
Utility Advisory Committee Memo
December 14, 2010
To: Utility Advisory Committee
From:
Larry Dunbar, Deputy Director of Power Systems
Rick Hostetler, Customer Services Manager
Jim Harper, Systems Coordinator
Subject: Advanced Metering Infrastructure System Agreement
Summary: At the direction of the City Council, staff and EES Consulting completed the
procurement process for the Advanced Metering Infrastructure System. A total of fifteen vendors
participated in the process and three vendors submitted proposals. After evaluations, interviews,
demonstrations, and reference checks, Mueller Systems was selected as the vendor that provides
the best value to the City.
Recommendation: Forward a favorable recommendation to City Council to authorize the
City Manager to sign the Advanced Metering Infrastructure System Agreement with
Mueller Systems, and to make minor modifications to the agreement, if necessary.
Background /Analysis: The Electric, Water and Wastewater Utilities use meters to record
customer consumption used for utility billing, and over 60% of the meters are more than 15 -years
old with some meters in service since 1959. The Radix hand -held computer used for entering
manual meter readings into the utility billing system is also beyond its service life. Instead of
replacing the manual system with the same technology, this project will procure a modern
Advanced Metering Infrastructure (AMI) System. By replacing aging meters that have slowed
down over time, energy, water, and wastewater sales are anticipated to increase. The current
distribution system losses (which are about 6% for electric and 20% for water) should decrease by
replacing aging meters. The AMI System will comply with the recent National Energy Policy Act
and Water Efficiency Rule unfunded mandates to offer electric time -of -use metering and to reduce
water distribution system losses, respectively.
The AMI System is also an outstanding customer service enhancement opportunity and will
eliminate estimated meter readings and most billing adjustments. Remote electric meter
disconnect will significantly reduce management of the most difficult past due accounts. This
modernization project will provide infrastructure needed to satisfy upcoming needs for tiered rates
and demand response, and the future smart grid. After the AMI System is implemented, cost
savings will be realized by discontinuing most manual readings, reduced theft, and lower
wholesale power costs. Staff has been updating the Utility Advisory Committee (UAC) monthly
since it May 11, 2010 meeting on the AMI System project milestones and schedule.
N \UAC \Final \AMI System Agreement doc
Advanced Metering Infrastructure System Agreement
December 14, 2010
Page 2
On January 19, 2010, City Council authorized EES Consulting to proceed with the AMI System
Request for Proposals (RFP). The RFP included requirements for a two -phase turn-key AMI
System including a technical proposal and a charge proposal. The technical proposal included the
metering equipment, hardware and software, 2 -way communications technology, network security,
and an outline of the implementation plan. The implementation plan will be prepared by the
Vendor after the AMI System Agreement is executed, and will be approved by the City prior to
proceeding with installation. The charge proposal includes the AMI System and its installation.
As part of the proposed Agreement the City will purchase and install a needed module for its
customer information system, essential information technology hardware, necessary fiber optic
network connections, and installation of approximately 500 polyphase electric meters.
A staff project team and representatives from the UAC were assembled to work with EES
Consulting during the procurement process. EES Consulting and the staff team participated in the
development of the RFP, evaluation of proposals and life cycle costs, interviews, demonstrations,
reference checks, and vendor selection. A total of fifteen vendors registered with the City to
participate in the RFP and three vendors (HD Supply Utilities, Elster Solutions and Mueller
Systems) submitted proposals. The proposals from Elster Solutions and Mueller Systems were
determined to be highly competitive and responsive to the RFP and they were invited to participate
in interviews and demonstrations. As a result of the interviews, demonstrations and reference
checks, Mueller Systems was selected as the most responsive Vendor and the one that provides the
best value to the City, which was confirmed by Public Works and Utilities Director and the
Finance Director.
A summary of the Advanced Metering Infrastructure System RFP procurement schedule is
provided below.
Milestone
RFP advertisement
Pre - proposal conference
Proposal deadline
Vendor interviews
Vendor demand response demonstrations
Vendor reference checks
Proposal review and evaluation
Vendor negotiations
Utility Advisory Committee consideration
City Council contract award
Completion Date
May 10, 2010
May 21, 2009
August 16, 2010
September 10, 2010
October 21, 2010
October 26, 2010
November 9, 2010
December 10, 2010
December 14, 2010
December 21, 2010
Status
Complete
Complete
Complete
Complete
Complete
Complete
Complete
Complete
Staff negotiated changes to the AMI System Agreement that was included in the RFP with Mueller
System. The final review of the negotiated AMI System Agreement will be completed by the City
Attorney before today's meeting. A summary of the Mueller Systems Charge Proposal is attached
and the total cost of the project is less than the budget. The Vendor proposals are available for
review at City Hall in the Public Works and Utilities engineering office, confidential computer
network security- related information has been removed from all documents.
Attachment: Mueller Systems Charge Proposal Summary
A
B
B
B
B1
B1
BI
C
E
E
El
El
El
F
H
H
H
H
H
H
H
H
J
J
J
J
J
K
K
L
M
M
M
Mueller Systems Charge Proposal Summary
Schedules/Description Mueller Systems
Electric Meters
Electric Meter Installation
Electric Meter GPS Locating
Electric Meter Lockable Ring
Electric Meter Repairs - Socket Replacement
Electric Meter Repairs - Conductor Replacement
Electric Meter Repairs - Other
Water Meters
Water Meter Installation
Water Meter GPS Locating
Water Meter Repairs - Lid Installation
Water Meter Repairs - Box Installation
Water Meter Repairs - Other
Electric Meter Remote Connect (305 Units)
Demand Response Controller (600 Units)
Demand Response Controller Installation
Srrrat Thermostat (105 Units)
Smart Thermostat Installation
In -Home Display (30 Units)
In -Home Display Installation
ZigBee ®Gateways (600 Units)
Demand Response Software
Supplemental Services
Outage Management System
Warranty
Insurance
Performance Bond
2 -Way Communications System
Hand -Held Computer Field Tool
AMI System Software
Meter Data Management System (MDMS) Software
Integrate MDMS Into Customer Information System
Customer Portal
Subtotal (Taxes Not Included)
Taxes
Total Mueller Systems
Schedules/Description City of Port Angeles
K Information Technology Hardware
K Fiber Optic Connections
M CIS Module
Subtotal (Taxes Not Included)
Taxes
Total City ofPort Angeles
Total AMI System Project Cost
Schedules/Description City of Port Angeles
L lAnnual AMI System Software License Agreement
M lAnnual Fiber Optic Network Connections
M lAnnual CIS Module
ITotal Annual Costs (beginning 2012)
N \UAC \ Final \AM[ System Agreement doc
Charges
$ 991,291
297,248
Included
48,000
66,320
67,800
54,600
1,188,906
717,996
Included
5,000
41,250
55,000
31,300
87,000
137,880
23,100
12,635
6,000
Included
110,000
Included
35,200
Included
Included
Included
Included
33,000
3,000
35,500
Included
1,800
2,500
$ 4,052,326
337,439
$ 4,389,764
Charges
45,830
53,296
146,360
$ 245,486
20,621
$ 266,107
$ 4,655,871
Charges
10,900
3,960
14,200
$ 29,060
ORT NGELES
W A S H I N G T O N , U.S.A.
Utility Advisory Committee Memo
December 14, 2010
Date:
To: Utility Advisory Committee
From: Larry Dunbar, Deputy Director of Power Systems
Subject: Western Public Agencies Group Consulting Agreement
Summary: The Western Public Agencies Group represents the interests of its electric utility
members before the Bonneville Power Administration. Each year they propose an agreement and
scope of services to its members. The City's share of the 2011 proposed scope of work is $16,468
out of the total membership cost of $390,000.
Recommendation: Forward a favorable recommendation to City Council to authorize the
City Manager to sign an agreement with EES Consulting, Inc., and Marsh Mundorf Pratt
Sullivan & McKenzie in an amount not to exceed $16,468.00 for Western Public Agency
Group 2011 membership dues.
Background /Analysis: The Electric Utility is a member of the Western Public Agencies
Group (WPAG) along with twenty -three other publicly owned electric utilities. WPAG members
serve more than one million customers and purchase more than 6 billion kilowatt hours from the
Bonneville Power Administration (BPA). WPAG represents the interests of its members before
BPA, and has intervened in every major BPA rate proceeding since 1980. EES Consulting, Inc.,
provides WPAG engineering and financial services, and legal services are provided by Marsh
Mundorf Pratt Sullivan & McKenzie.
Each year WPAG proposes an agreement and scope of services to its members, which is allocated
to each utility based on average customers, energy sales, and capital investments. The City's share
of the 2011 proposed scope of work is $16,468 out of the total membership cost of $390,000. The
Electric Utility budget in 2011 for WPAG membership is $21,000. A copy of the proposed scope
of services and contracts are attached.
It is recommended that City Council authorize the City Manager to sign the agreement with EES
Consulting, Inc., and Marsh Mundorf Pratt Sullivan & McKenzie in an amount not to exceed
$16,468.00 for Western Public Agency Group 2011 membership dues.
Attachment: Proposed WPAG Scope of Services and Contracts for 2011
N \UAC \Final \WPAG Consulting Services Agreement docx
EES
November 15, 2010
Mr. Charles Dawsey
Benton Rural Electric Association
Post Office Box 1150
Prosser, WA 99350
Mr. Doug Nass
Clallam County P U.D.
Post Office Box 1090
Port Angeles, WA 98362
Mr. Wayne Nelson
Clark Public Utilities
Post Office Box 8900
Vancouver, WA 98668
Mr Bob Titus
City of Ellensburg
501 N Anderson Street
Ellensburg, WA 98926
Mr. Rick Lovely
Grays Harbor County PUD
P.O Box 480
Aberdeen, WA 98520
Mr Chuck Ward
Ktttitas County PUD
1400 East Vantage f-righway
Ellensburg, WA 98926
Consulting
Dear Ladies and Gentlemen:
570 Kirkland Way, Suite 200
Kirkland, Washington 98033
Mr. Dave Muller
Lewis County P.0 D
Post Office Box 330
Chehalis, WA 98532
Mr. Steven 14 Taylor
Mason County P.U.D No 1
North 21971 Highway 101
Shelton, WA 98584
Ms Wyla Wood
Mason County P U.D. No. 3
Post Office Box 2148
Shelton, WA 98584
Mr Doug Miller
Pacific County P.U.D.
Post Office Box 472
Raymond, WA 98577
Mr JafarTaghavi
Peninsula Light Company
Post Office Box 78
Gig Harbor, WA 98335
Mr Larry Dunbar
City of Port Angeles
9.0 Box 1150
Port Angeles, WA 98362
SUBJECT: Proposed WPAG Scone of Services and Contracts for 2011
Attached please find consulting and legal contracts from Terry and me for the 2011 scope of
services for the Western Public Agencies Group (WPAG). If these contracts are acceptable,
please sign and return one copy of each contract for our respective files.
Thank you for allowing EES Consulting and Marsh, Mundorf, Pratt, Sullivan & McKenzie
(MMPS&M) to serve you for another year.
Telephone: 425 889 -2700 Facsimile: 425 889 -2725
A registered professional engineering corporation with offices in
Kirkland, WA; Portland, OR; and Bellingham, WA
Mr. Bob Wittenberg
Skamania County PUD
P.O. Box 500
Carson, WA 98610
Mr Steve Walter
Tanner Electric Cooperative
P 0 Box 1426
North Bend, WA 98045
Mr. David Trambhc
Wahkiakum County PUD No 1
P.O. Box 248
Cathlamet, WA 98612
Mr. Terry Huber
Pierce County Cooperative
Association
do Town of Steitacoom
1030 Roe Street
Steilacoom, WA 98388
Western Public Agencies Group
November 15, 2010
Page 2
Please feel free to call Terry or me if you have any questions.
Very truly yours,
.2„2„,
Gary S. Saleba
President
cc: Dan Sharpe, Alder Mutual Light Company
Gary Armstrong, Town of Eatonville
Daniel Brooks,Elmhnst Mutual Power & Light
Robin Rego, Lakeview Light & Power Company
Letticia Neal, City of Milton
Isabella Dedrteb, Ohop Mutual Light Company
Mark Johnson, Parkland Light & Water Company
Mark Burlingbamc, Town of Steilacoom
Terry Mundort MMPS&M
Western Pub is Agencies Group
2011 Scope of Services and Budget
EXHIBIT A
The Western Public Agencies Group (WPAG) comprises 23 publicly owned utilities in the state
of Washington: Benton REA, Clallam County P.U.D. No. 1, Clark Public Utilities, the City of
Ellensburg, Grays Harbor P.U.D. No. 1, Kittitas County P.U.D. No. 1, Lewis County P.U.D. No.
1, Mason County P.U.D. No. 1, Mason County P.U.D. No. 3, Pacific County P.U.D. No. 2,
Skamania County P.U.D. No.1, Wahkiakum County P.U.D. No. 1, Peninsula Light Company,
the City of Port Angeles, Tanner Electric Cooperative, and members of the Pierce County
Cooperative Power Association, which includes Alder Mutual Light Company, the Town of
Eatonville, Elmhurst Mutual Power and Light Company, Lakeview Light and Power Company,
the City of Milton, Ohop Mutual Light Company, Parkland Light and Water Company, and the
Town of Steilacoom.
Together the WPAG member utilities serve more than one million customers and purchase more
than 6 billion kilowatt-hours from the Bonneville Power Administration ( "Bonneville ") each
year under both Load Following and Slice Contracts. WPAG member utilities also own or
receive output from more than 400 megawatts of non - Bonneville generation and purchase more
than 300 megawatts of power from sources other than Bonneville. WPAG members are generally
winter- peaking utilities with lower annual load factors.
WPAG members' similar characteristics have caused them to join together to represent their
interests before Bonneville, and in other regional and national forums since 1980. WPAG has
intervened as a group in every major Bonneville rate proceeding since enactment of the Pacific
Northwest Electric Power Planning and Conservation Act of 1980. WPAG's interests have also
been represented in Congress, before the Northwest Power Planning Council, and in other
regional forums.
The scope of services presented here includes areas that various other organizations, of which
WPAG members might also be members, cannot advocate for WPAG members due to conflicts
of interest within those organizations, lack of staff resources or subject area expertise. WPAG
thus fills a need that is unmet by membership in the Public Power Council, the Northwest Public
Power Association, the Pacific Northwest Utilities Conference Committee and other similar
groups.
Scope of Services
The 2011 scope of services for WPAG is proposed as follows:
■ General WPAG Activities and Meetings
EXHIBIT A
During 2011, EES Consulting and MMPS &M will monitor and comment on regional and
federal activities of specific interest to WPAG members not covered adequately by other
public power organizations of mutual interest and relevance. Monthly meetings will be held
to brief WPAG members on these activities.
■ Regional Activities
WP -12 Rate Proceedinas
BPA has completed planning workshops to prepare for a combined power and
transmission rate proceeding that will set rates under the Tiered Rate Methodology for
the very first time. In this case, virtually every issue that has been subject to settled
treatment since 1980 will be up for grabs. In addition, certain large preference customers
are seeking to upset the current balance between PTP and NT rates by shifting costs from
PTP to NT. While there are WPAG members that use PTP as well as NT, WPAG will
actively participate in the transmission rate case to ensure that costs are not shifted from
PTP to the detriment of NT, and that the coincidence factor used to allocate costs treats
fairly both NT and PTP users. WPAG will be fully engaged in these proceedings to
protect the interests of its members. This will be staffed by EES Consulting and
MMPS &M.
TRM Loose Ends and Revisions
There have already been some changes to the TRM to correct errors and address
omissions. The WP -12 rate proceedings are likely to uncover more of the same. In
addition, there are a number of significant issues that were not satisfactorily resolved at
the end of the Tier Rate Methodology process that BPA has agreed to revisit, including
most importantly the issue of system obligations that BPA treats as off-the -top
dedications to the Tier 1 system capability. Additionally, there are significant issues that
will arise as the TRM is actually translated into rates that will need to be dealt with in the
next year. One such issue is the lack of any agreed upon methodology for determining the
capability of the Tier 1 system, which impacts how much Tier 1 power is available to
WPAG utilities. This will be staffed primarily by MMPS &M.
TRM Benchmarks
During the next 18 months, a number of important values will be established for each
WPAG member utility that will bear on the amount of low cost federal power each
WPAG member will be able to purchase from BPA. These include the Contract High
Water Mark (CHWM), the Rate Period High Water Mark (RHWM), and the Contract
Demand Quantity (CDQ). While the primary responsibility for the determination of
these values will rest with individual WPAG member utilities, WPAG as a group will be
involved in the public processes that determine these values to ensure that WPAG
A -2
EXHIBIT A
member receive fair and equitable treatment. This will be staffed by EES Consulting and
MMPS &M.
Tier 2 Resource Acauisition
BPA is already investigating various resources for acquisition purposes, and will be
gearing up these activities during the coming year. While the theory of tiered rates is to
separate the costs of these resources from those of Tier 1 resources, there is a strong
likelihood that some of the costs of Tier 2 resources will find their way into Tier 1 rates.
As such, WPAG members have a direct financial interest in how BPA goes about
evaluating resources, and what resources it decides to acquire regardless of whether they
intend to rely on BPA for Tier 2 service or not. WPAG will participate in the BPA
processes regarding the acquisition of additional resources. This will be staffed by EES
Consulting and MMPS &M.
Conservation
BPA has been and will remain engaged in discussions regarding how conservation will
be funded under the new TRM contracts and rates. There is a desire among many
preference customers be have the option of providing their own funding for conservation,
not run these dollars through the BPA rates, and obtain thereby more flexibility in how
conservation and demand side programs are managed. This will make conservation and
demand side more adaptable for meeting Tier 2 loads. WPAG will work to ensure that
current BPA funded programs will continue to be available to utilities that want to
participate in them. In addition, WPAG will ensure that conservation can be used as a
Tier 2 resource for those who wish to do so. This will be staffed by EES Consulting and
MMPS &M.
Preference to FBS Canacitv
BPA has been using increasing amounts of FBS capacity to integrate wind generation on
the Federal transmission system. This capacity is deducted from the FBS capability made
available to preference customers under Tier 1. For the near term, the primary impact of
this activity is to reduce the secondary revenues available to BPA to reduce the PF rate by
shifting secondary power sales from heavy load hours to light load hours. However, in
the future this reduction in FBS capacity may impinge on service to preference customer
loads under both load following and Slice contracts. WPAG will bring to the fore in the
WP -12 rate proceeding this misuse of FBS capacity, and assert our preference rights to
this capacity. Vindication of these preference rights may require litigation. This will be
staffed by MMPS &M.
IOU REP Benefits Pronosed Settlement
Our success in the Golden Northwest and PGE cases resulted in the WP -07 Supplemental
rate proceeding, and substantial refunds to preference customers. There continues to be
litigation over funds that BPA allowed the IOUs to retain. This caused BPA to initiate
negotiations under the auspices of a mediator between the publics, IOUs and BPA in an
effort to resolve the pending litigation and agree on the appropriate level of benefits that
should be paid to the IOUs over the long term. A proposed settlement of these issues is
currently being drafted into final form, and is likely to be offered to all WPAG members
A -3
EXHIBIT A
as litigants. The question of whether the settlement agreement should be signed by each
WPAG utility is ultimately a decision of each board and council, but WPAG intends to
offer all necessary assistance to WPAG members in making this decision. This will be
staffed primarily by MMPS &M.
IOU REP Benefits Public Process and Congressional Ratification
In the event that sufficient preference customers sign the final settlement offered by BPA
to resolve pending litigation and set the REP benefits for the IOUs for the next 17 years,
BPA will conduct a public process to determine whether the proposed settlement is
reasonable, and whether BPA should execute the settlement. If BPA elects to sign the
settlement, there will be an effort to secure Congressional legislation to preclude legal
challenges to the settlement. Since these proceeding will, if successful, replace the cost
protection provided to preference customers by the Rate Test set out in the Regional
Power Act, WPAG intends to be fully involved in both of these activities. The positions
taken in these processes will be dictated by the WPAG members. This will be staffed
primarily by MMPS &M.
DSI Lone -Term Contracts
During the coming calendar year, BPA will also be dealing with the issue of how it will
deliver "benefits" to the DSIs. The cost of these benefits will be imposed on Tier 1
customers, including WPAG utilities. It will also require BPA to negotiate a contract
with the DSIs for the delivery of any such benefits. This effort to continue to support the
DSIs will be aggressively opposed by WPAG. This will be staffed primarily by
MMPS &M.
Resource Integration Impacts
BPA is integrating increasing amounts of wind generation that is being exported to
California, and the uncontrolled nature of this generation combined with the generation
requirements imposed on the FBS due to fish mitigation has lead to adverse operating
events, market dysfunction and additional costs imposed on BPA. This is a multifaceted
problem that will require imaginative and forceful responses. These developments
present another manner in which the rights of preference customers are being eroded.
WPAG will be actively involved in the identification and implementation of actions to
address all of the issues that are presented in this context to ensure that the FBS is
preserved for use in serving preference customer loads, and that costs of integrating these
resources are borne by their sponsors. This will be staffed primarily by MMPS &M.
Transmission
Issues have arisen regarding the ability of BPA transmission network to accommodate the
amounts of wind generation being developed without imposing costs or access limitations
on preference customers receiving service under their post -2011 power contracts via NT
service over the Federal transmission system. All WPAG members receive federal power
service from BPA, and many have developed and will develop non - federal resources. As
such, WPAG is uniquely positioned to strike the proper balance between the integration
of non - federal resources, particularly wind, and BPA's obligations to husband the
resources of the Federal base system for service to its preference customers. WPAG will
A -4
be fully involved with all processes in which these issues come to the fore, and in
particular the development of the position that preference attaches to both the energy and
capacity that is available from the Federal base system. This will be staffed primarily by
MMPS &M.
• Federal Energy Regulatory Commission
The Federal Energy Regulatory Commission (FERC) has begun investigations into
transmission service provided under the NT and PTP contract under the auspices of updating
of its landmark Order No. 888. This may result in changes to the way transmission
dependent utilities have access and pay for access on transmission facilities and will have
significant implications for WPAG members. To date, PPC has done a good job of working
this issue. EES Consulting and MMPS &M will continue to assist PPC in its efforts, and will
monitor this process to see if WPAG direct participation is needed.
In June 2007, under the direction of FERC, the North American Electricity Council (NERC)
began enforcing electric reliability standards. As of that time utilities with greater than
25,000 customers are required to register with NERC and their regional reliability
organization or the Western Electricity Coordinating Council (WECC) on the west coast of
North America. EFS Consulting has been monitoring and advising WPAG members on
compliance issues since April of 2007. EES Consulting will continue to monitor compliance
issues on behalf of WPAG members in 2011. EES Consulting will alert WPAG members of
issues as they arise. To the extent that detailed analysis and/or representation is required by
an individual WPAG member with respect to compliance issues, tasks will be completed and
billed on an individual utility basis
• Olympia Legislative Session
EES Consulting and MMPS &M will monitor the activities of the 2011 legislature on behalf
of WPAG's specific interests.
• Other Matters
Budget
EES Consulting
President $165 per hour
Managing Director 160 per hour
EXHIBIT A
During the course of each year, matters arise that require WPAG attention to protect the
interests of our customers. These matters are undertaken at the direction of the WPAG
utilities.
The budget for the scope of services described above is calculated at the following billing rates
for EES Consulting and MMPS &M:
A -5
Manager 155 per hour
Senior Project Manager 150 per hour
Project Manager 145 per hour
Senior Analyst or Engineer 140 per hour
Analyst 135 per hour
Clerical 120 per hour
MMPS&M
Principal $175 per hour
Associate $165 per hour
These billing rates will remain in effect through December 31, 2011.
Project Staffing
EXHIBIT A
On the basis of the above billing rates, the 2011 labor budgets of EES Consulting and
MMPS &M combined are estimated to remain at $200,000, which holds the line on budget
increases. This labor budget will be split equally between EES Consulting and MMPS &M. In
addition, an amount of $150,000 in supplemental funding has been provided to staff the WP -12
Power and Transmission rate cases, and any public process regarding the proposed IOU REP
benefit settlement.
In addition to labor costs, out -of- pocket expenses will be billed to WPAG members at their cost
to EES Consulting and MMPS &M. It is estimated that $40,000 in total out -of- pocket expenses
will be incurred for all work non -rate case elements in total. Out -of- pocket costs will be billed by
whichever organization actually incurs the expense. The total estimated annual WPAG budget
for 2011 is estimated at $240,000, and a supplemental budget of $150,000 for rate case activities.
As always, the allocation of the budget among WPAG members is open to negotiation by the
participants. We have attached an inter - utility allocation predicated on the most recent available
utility data. After a discussion of the foregoing issue, a final budget by utility will be prepared.
An example of the budget's allocation is attached at the end of this narrative.
The staffing for these projects will be similar to that for past WPAG activities. Gary Saleba and
Terry Mundorf will be the principal representatives for EES Consulting and MMPS &M,
respectively, with Ryan Neale providing support for the activities of Terry Mundorf Additional
MMPS &M and EES Consulting staff will assist as needed.
3. Insurance.
CONSULTING SERVICES AGREEMENT
EES CONSULTING, INC.
Billing Address
570 Kirkland Wa% Suite 200, Kirkland. Washington 98033
(425)889 -2700
This Consulting Services Agreement (herein Agreement) is made between EES Consulting, Inc., (hereinafter "EES CONSULTING') and the City of Port Angeles,
Mr. Larry Dunbar, P.O. Box 1150, Port Angeles, WA 98362 (hereinafter "CLIENT').
1. SCOPE, COMPENSATION AND QUALITY OF CONSULTING SERVICES
EES CONSULTING will provide the services and be compensated for these services as described In Exhibit A, attached hereto.
EES CONSULTING shall render its services in accordance with generally accepted professional practices. EES CONSULTING shall, to the best of its knowledge and
belief, comply with applicable laws. ordinances, codes, rules, regulations, permits and other published requirements in effect on the date this Agreement is signed.
11. TERMS & CONDITIONS OF CONSULTING SERVICES AGREEMENT
1. Timing of Work. EES CONSULTING shall commence work on or about January 1, 2011.
2. Relationship of Parties, No Third -Party Beneficiaries EES CONSULTING is an independent contractor under this Agreement This Agreement gives no nghts or
benefits to anyone not named as a party to this Agreement, and there are no third party beneficiaries to this Agreement.
a insurance of EES CONSULTING EES CONSULTING will maintain throughout the performance of thls Agreement the following types and amounts of
insurance:
r. Worker's Compensation and Employer's Liability Insurance as required by applicable state or federal law.
ii Comprehenstve Vehicle Liability Insurance covering personal injury and property damage claims arising from the use of motor vehicles with combined
single limits of $1,000,000.
fi. Commercial General Liability Insurance covering claims for personal injury and property damage with combined single limits of $1,000,000.
iv. Professional Liability (Errors and Omissions, on a claims -made basis) Insurance with limits of $1,000,000.
b. Interpretation. Notwithstanding any other provision(s) in this Agreement, nothing shall be construed or enforced so as to void, negate or adversely affect any
otherwise applicable insurance held by any party to this Agreement
4. Mutual Indemnification_ EES CONSULTING agrees to indemnify and hold harmless CLIENT and its employees from and against any and all loss, cost, damage,
or expense of any kind and nature (including, without limitation, court costs, expenses, and reasonable attorneys' fees) arising out of injury to persons or damage to
property (Including, without limitation. property of CLIENT, EES CONSULTING, and their respective employees, agents, licensees, and representatrves) in any manner
caused by the negligent acts or omissions of EES CONSULTING in the performance of its work pursuant to or in connection with this Agreement to the extent of EES
CONSULTING's proportionate negligence, if any.
CLIENT agrees to indemnify and hold harmless EES CONSULTING and its employees from and against any and all loss, cost, damage, or expense of any kind and
nature ( including without limitation, court costs, expenses and reasonable attorneys' fees) ansing out of Injury to person(s) or damage to property (including, without
limitation, property of CLIENT, EES CONSULTING and their respective employees, agents, licensees and representatives) In any manner caused by the negligent acts or
omissions of CLIENT or other(s) with whom CLIENT contracts ( "CLIENT'S agents ") to perform work pursuant to or in connection with this Agreement, to the extent of
CLIENT's or CLIENT's agents proportionate negligence, rf any.
5. Resolution of Disputes, Attorneys' Fees The law of the State of Washington shall govern the interpretation of and the resolution of disputes under this
Agreement If any claim, at law or otherwise, is made by either party to this Agreement, the prevailing party shall be entitled to its costs and reasonable attomeys' fees
6 Termination of Agreement. Either EES CONSULTING or CLIENT may terminate this Agreement upon thirty (30) days wntten notice to the other sent to the
addresses listed herein
In the event CLIENT terminates this agreement, CLIENT specifically agrees to pay EES CONSULTING for all services rendered through the termination date.
EES CONSULTING INC. ` ^X)� CITY OF PORT ANGELES
By: Gary Saleba tl U 2" �/ By.
0
Title ' President Title:
Date: November 15, 2010 Date.
Western Public Agencies Group
Preliminary Indicative Budget for 2011
EES Consulting and Marsh Mundorf Pratt Sullivan & Mckenzie
Source: 2010 -2011 Northwest Electric Utility Directory (NWPPA), 2003 EIA Form 412 & 2004 EIA Form 861, Utility Supplied
November 15, 2010
Total Budget
Labor $ 200,000
Expenses $ 40,000
Total Allocation $ 240,000
BPA Rate Case $ 150,000
Supplemental Allocation $ 150,000
Average of Customers,
Energy Sales and
Investment Standard Supplemental
Customers' Energy Sales 1 Net Investment 2 18.0% Budget Allocation Budget Allocation
Without Cap Cap with Cap with Cap
percent of percent of percent of percent of percent of
number total kilowatt-hours total dollars total total total dollars dollars
Individual Utihhes
Benton Electric REA 14,592 3.2% 565,802,985 4.7% $ 93,440,576 70% 4.96% 6 30% $ 15,128 $ 9,455
Clallam County PUD 30,031 6 5% 762,660,906 6.4% $ 106,596,449 8 0% 6.95% 8.87% $ 21.282 $ 13,301
Clark Public Utdties 183,015 39 7% 4,946.000.000 41 4% $ 347,900,000 28 0% 35.69% 18.00% $ 43,200 $ 27,000
C,ty of Ellensburg 9,200 2 0% 222,215,504 1.9% $ 26,419,391 2.0% 1.94% 2.48% $ 5,958 $ 3,724
Grays Harbor PUD 41,690 9.0% 978,550,115 82% $ 224,895,016 16.8% 11.35% 14.39% $ 34,547 $ 21,592
KIttitas County PUD 4,252 0 9% 84,029,083 0.7% $ 18,356,529 1.4% 1.00% 1.27% $ 3,047 $ 1,904
Lewis County PUD No 1 30,892 6.7% 933,660,601 7 8% $ 109,236,614 8.2% 7 56% 9.65% $ 23,160 $ 14,475
Mason County PUD No 1 5,143 1.1% 70,296,782 06% $ 13,709,373 1.0% 0.91% 1 16% $ 2,782 $ 1,739
Mason County PUD No 3 32,634 71% 660,405,008 5.5% $ 112,548,253 8 4% 7.01% 8.92% $ 21,417 $ 13,385
Pacific County PUD No 2 17,091 3.7% 299,128,325 2.5% $ 38,651,128 2,9% 3.03% 3.88% $ 9,305 $ 5,816
Peninsula Light Company 27,374 5.9% 600,281,800 5.0% $ 84,883,260 6.3% 5 77% 736% $ 17,662 $ 11,039
City of Port Angeles 10,919 2 4% 689,775,650 5.8% $ 22,618,463 1 7% 3 28% 4.22% 6 10,134 $ 6,334
Skamanla County PUD No 1 5,791 1 3% 130,110,119 1.1% $ 16,802,110 1.2% 1.20% 1.53% $ 3,663 $ 2,289
Tanner Electric Cooperative 4,461 1.0% 88,973,918 0.7e/ $ 21,705,036 1.6% 1.11% 1.41% $ 3,385 $ 2,115
Wahkiakum County PUD No 1 2,404 0 5% 41,592,833 0.3% $ 7,383,612 0.6% 0.47% 080% $ 1,447 $ 905
Pierce County Cooperative Power Association
Alder Mutual Light Company 283 0,1% 4,787,000 0.0% $ 409,409 0.0% 0.04% 006% $ 136 $ 85
Town ofEatonvile 1,178 03% 27,271,397 0.2^ $ 1,150,000 0.1% 0.19% 024% $ 587 $ 367
Elmhurst Mutual Power and Light Company 13,884 3.0% 269,750,037 2 3% $ 30,050,620 2 2% 2.50% 3 21% $ 7,692 $ 4,808
Lakeview Light and Power Company 11,434 2 5% 278,291,000 2.3% $ 29,018,475 2.2% 2 33% 2 98% $ 7,140 $ 4,463
City of Milton 3,389 0 7% 62,183,202 0.5% $ 2,378,975 0 2% 0.48% 0.62% $ 1,478 $ 924
Chop Mutual Light Company 4,189 0 9% 82,889,733 0 7% $ 8,969,611 0 7% 0.76% 0 97% $ 2,327 $ 1,454
Parkland Light and Water Company 4,425 1 0% 118,504,536 1.0% $ 18,854,000 1 4% 1.12% 1.43% $ 3,422 $ 2,139
Town ofSteilacoom 2,816 0.6% 40,428,000 03% $ 1,571,502 0.1% 0.36% 0.40% $ 1,100 $ 688
Subtotal Pierce County Cooperative Power Association 41,598 90% 884,104,905 7.4% 92,402,592 6.9% 7.8% 9.95% $ 23,883 $ 14,927
Total 461,087 100.0% 11,957,588,534 1000% 1,337,328,402 100.0% 100.0% 100.00% $ 240,000 $ 150,000
LEGAL SERVICES AGREEMENT
THIS AGREEMENT is made between BENTON RURAL ELECTRIC ASSOCIATION,
WASHINGTON; CITY OF PORT ANGELES, WASHINGTON; CITY OF ELLENSBURG,
WASHINGTON; CITY OF MILTON, WASHINGTON; TOWN OF EATONVILLE,
WASHINGTON; TOWN OF STEILACOOM, WASHINGTON; ALDER MUTUAL LIGHT
COMPANY, ELMHURST MUTUAL POWER AND LIGHT COMPANY, WASHINGTON;
LAKEVIEW LIGHT AND POWER COMPANY, WASHINGTON; OHOP MUTUAL LIGHT
COMPANY, WASHINGTON; PARKLAND LIGHT AND WATER COMPANY,
WASHINGTON; PENINSULA LIGHT COMPANY, WASHINGTON; TANNER ELECTRIC
COOPERATIVE, WASHINGTON; PUBLIC UTILITY DISTRICT NO. 1 OF CLALLAM
COUNTY, WASHINGTON; PUBLIC UTILITY DISTRICT NO. 1 OF CLARK COUNTY,
WASHINGTON; PUBLIC UTILITY DISTRICT NO. 1 OF GRAYS HARBOR COUNTY,
WASHINGTON; PUBLIC UTILITY DISTRICT OF KITTITAS COUNTY, WASHINGTON;
PUBLIC UTILITY DISTRICT NO. 1 OF LEWIS COUNTY, WASHINGTON; PUBLIC
UTILITY DISTRICT NO. 1 OF MASON COUNTY, WASHINGTON; PUBLIC UTILITY
DISTRICT NO. 3 OF MASON COUNTY, WASHINGTON; PUBLIC UTILITY DISTRICT
NO. 2 OF PACIFIC COUNTY, WASHINGTON, PUBLIC UTILITY DISTRICT NO. 1 OF
SKAMANIA COUNTY, WASHINGTON; AND PUBLIC UTILITY DISTRICT NO. 1 OF
WAHKIAKUM COUNTY, WASHINGTON (Public Utilities); and MARSH MUNDORF
PRATT SULLIVAN & McKENZIE (Attorney) for the provision of legal services and the
payment of compensation as specified herein.
WHEREAS, the Public Utilities presently purchase electric power from the Bonneville
Power Administration (BPA) pursuant to wholesale rate schedules determined by BPA after
public hearing pursuant to Section 7 of the Pacific Northwest Electric Power Planning and
Conservation Act (Act);
WHEREAS, BPA is considering adoption of various policies, rate forms and long -term
contracts which would have a major impact on the wholesale rates of the Public Utilities, and
WHEREAS, BPA is preparing to conduct hearings and public processes to decide issues
which will affect Bonneville's wholesale rate schedules and Power Sales Contracts for the Public
Utilities; and
WHEREAS, the Public Utilities wish to actively participate in these hearings and
processes to protect the interests of their ratepayers, and
WHEREAS, the Public Utilities may wish to diversify their power supply sources,
It is Therefore Agreed That:
Page 1 of 2
1. The Attorney shall advise, assist and appear on behalf of the Public Utilities in
hearings and public processes relating to issues set forth Exhibit A referenced
herein attached and as directed by the Public Utilities.
2. Public Utilities shall compensate the Attorney for these services at an average
hourly rate not to exceed $175.00. Out -of- pocket expenses, such as telephone,
telecopy, copying and postage, and reasonable and necessary travel expenses shall
be in addition to the hourly rate. The Attorney shall send each of the Public
Utilities an itemized statement for legal services rendered and out -of- pocket
expenses on a monthly basis.
3. The Attorney fees and out -of- pocket expenses incurred hereunder shall be divided
among the Public Utilities according to the formulas attached in Exhibit A.
4. The activities encompassed by this Agreement are set forth in Exhibit A attached
hereto. No other activities shall be undertaken without prior authorization of the
Public Utilities. It is understood that the length and amount of work necessary in
these proceedings is unique and the cost may exceed these estimates.
5. Files of the Attorney relating directly to the foregoing legal services shall be
available for examination by the authorized representative of the Public Utilities
or their attorneys and shall, upon reasonable request, be turned over the Public
Utilities if the Attorney ceases to act as attorney for the Public Utilities.
6. Because the attorney- client relationship is dependent upon mutual trust and full
confidence, an individual Public Utility, the Public Utilities collectively, or the
Attorney may terminate this Agreement at any time upon written notice.
Date: November 15. 2010
Date:
MARSH MUNDORF PRATT SULLIVAN & McKENZIE
B ✓ e� , /rn;c-1-1
Terence L. Mundorf
CITY OF PORT ANGELES
By:
Manager
Page 2 of 2
pORT NGELES
W A S H I N G T O N , U.S.A.
Utility Advisory Committee Memo
Date: December 14, 2010
To: Utility Advisory Committee
From: Larry Dunbar, Deputy Director of Power Systems
Rick Hostetler, Customer Services Manager
Subject: Low - Income Home Heating Energy Vendor Agreement
Summary: For over twenty years the Olympic Community Action Programs has annually
requested the City to approve a Low - Income Home Heating Energy Vendor Agreement. The
proposed agreement provides federal funding from the Low- Income Home Energy Assistance
Program to the City for the benefit of its utility customers that have difficulty paying their
electrical charges.
Recommendation: Forward a favorable recommendation to City Council to authorize the
City Manager to accept the 2010 Low - Income Home Heating Energy Vendor Agreement
with Olympic Community Action Programs.
Background /Analysis: Each year the Olympic Community Action Programs (OLYCAP)
receives funds from the Federal Government. The funds are provided through the Low - Income
Home Energy Assistance Program ( LIHEAP). The LIHEAP funds are dispersed by OLYCAP to
the City to help pay electrical charges due from Port Angeles utility customers. Each year about
500 City utility customers received approximately $160,000 in LIHEAP benefits. As required by
the Federal Government, OLYCAP must obtain a Low - Income Home Heating Energy Vendor
Agreement with each LIHEAP energy vendor such as the City. The basic terms of the proposed
agreement are as follows:
• OLYCAP will receive customer LIHEAP applications and determine eligibility and benefit
amount for each customer and notify the City and customer.
• Upon City request, OLYCAP will provide a statement verifying a City utility customer's
income for the sole purpose of determining customer eligibility to be protected by Winter
Moratorium laws, which govern the City's collection procedures on past due utility bills
during winter months.
• Upon OLYCAP request, the City will provide electric consumption reports so they can
determine a customer's LIHEAP benefit. The benefit is determined by number of people in
the household, household income, and amount billed for electricity during the previous 12
months. The benefit ranges from $25 to $1000 per household.
• The City extends credit to customers based on the benefit amount until the amount is actually
paid by OLYCAP to the City.
N \UAC \Final \Low Income Home Heating Energy Vendor Agreement doc
Low- Income Home Heating Energy Vendor Agreement
December 12, 2010
Page 2
OLYCAP also assists Port Angeles utility customers pay their utility bills with "Pass the Buck"
and "Home Fund" funds, and offers weatherization programs to qualifying low - income families.
Staff recommends that the Utility Advisory Committee forward a favorable recommendation to the
City Council to authorize the City Manager to accept the 2010 Low - Income Home Heating Energy
Vendor Agreement with Olympic Community Action Programs.
Attachment: Proposed 2010 Low- Income Home Heating Energy Vendor Agreement
....,,,,
(
Sincerely,
City of Port Angeles
321 E 5' St
PO Box 1150
Port Angeles, WA 98362
To Whom It May Concern:
h• 9
Genevieve Short
Energy Lead
360- 385 -2571 ext 6376
gshort@olycap.org
cXcrimPtynmei
Re: Low Income Home Heating Energy Vendor Agreement
803 W. Park Ave. Port Townsend, WA 98368
Telephone (360) 385 -2571 Fax: (360) 385 -5185
E-mail: action @olycap.org
November 12, 2010
As you know we provide valuable assistance to your low income customers and we appreciate
your support with this important program. With the economy being in such rough shape, those
at the bottom of the economic ladder are struggling even more. Fortunately Congress has
increased funding for LIHEAP (Low Income Home Energy Assistance Program) and we expect
to serve even more people in the next program year. The terms of our contract require us to
have an agreement with every LIHEAP vendor prior to the start of the next season beginning
October 1s I am enclosing two Low Income Home Heating Vendor Agreements. Please
review, sign both copies and return one to our office. Please contact me should you have any
questions.
Thank you in advance for your cooperation,
"Helping people to help themselves.
1
PURPOSE
AGENCY RESPONSIBILITIES
The Agency shall:
1
,9 c�n / 9 4„, '
803 W. Park Avenue, Port Townsend, WA 98368
Telephone (360) 385 -2571 Fax (360) 385 -5185
LOW - INCOME HOME HEATING ENERGY VENDOR AGREEMENT
This agreement dated as of November 12, 2010, is entered into by and between
OIyCAP, (Agency) and Citv of Port Anaeles, a supplier of home heating
energy, (Vendor).
Funding for Low - Income Home Energy Assistance Program (LIHEAP) payments
is governed by Federal Law 42 U.S.C. 8624: Low - Income Home Energy
Assistance Act of 1981, and subsequent amendments. This act requires that
certain assurances be satisfied before energy assistance payments are made on
behalf of eligible individuals to suppliers of home heating energy. This
agreement defines the conditions that the Energy Vendor must agree to so that
the Agency can make energy assistance payment to the Energy Vendor on
behalf of eligible households.
1. Accept and review client applications and determine eligibility of
households for LIHEAP payments.
2. Follow procedures that minimize the time elapsing between the receipt of
LIHEAP funds and their disbursement to Vendor.
3. Make payments in a timely manner to the Vendor on behalf of eligible
households between October 1 and August 31 of the program year for the
term of this agreement.
4. Follow sound fiscal management policies, including, but not limited to
segregation of LIHEAP funds from other operating funds of the Agency.
5. Notify customer and /or vendor of the customer's eligibility and total benefit
amount.
6. Incorporate policies that assure the confidentiality of eligible households'
energy usage, balance and payments.
7. Upon request from Vendor, provide a statement verifying income of an
eligible household for the sole purpose of determining moratorium
eligibility within the statutory guidelines of confidentiality.
ENERGY VENDORS RESPONSIBILITIES
The Energy Vendor shall:
1. Immediately apply the benefit payment to customer's current/past due bill,
deposit/reconnect requirements, or delivery of fuel to eliminate the amount
owed by the customer for a period determined by the amount of the
benefit, or;
2. Apportion the LIHEAP over several billing periods to reduce the amount
owned by the customer until the benefit is exhausted, or;
3. Establish a line of credit for the customer to be used at the discretion of
the customer until the benefit is exhausted.
4. Notify the customer of the amount of benefit payments applied to the
customer's billing.
5. Keep customer records confidential.
6. Maintain records for four years from the date of this agreement, or longer
if the energy Vendor is notified that a fiscal audit for a specific program
year is unresolved.
7. Not treat adversely or discriminate against any household that receives
LIHEAP payments, either in the cost of the goods supplied or the services
provided.
8. Upon request of the agency, provide eligible customer's energy
consumption history for the sole purpose of determining customer benefit.
9. Comply with the provisions of the State law regarding winter disconnects
and pertinent provisions of the Washington Administrative Code related to
the winter moratorium, if governed by that ruling.
2
10. Make records available for review by authorized staff of the agency and
the Department of Commerce, and the U.S. Department of Health and
Human Services.
REQUIRED RECORDS FOR AUDIT PURPOSES
The Vendor will keep records showing the following:
1. Name and address of household who received LIHEAP payments
2. Amount of assistance accrued to each household
3. Source of payment (Energy Assistance, Project Share, etc)
4. Amount of the household's credit balance when the benefit payment
establishes a line of credit. This credit balance also needs to show on all
customer billing documents
CREDIT BALANCES
In the event that a customer has a credit balance and no longer needs service
from the energy Vendor, the vendor shall:
1. Forward a check in the amount of any remaining credit balance directly to
the customer, or if directed by the customer, forward a two -party check for
this balance to the customer in the customer's name and the name of the
new home heating energy Vendor
2. If the customer dies leaving a credit balance resulting from a LIHEAP
payment, the remaining credit becomes part of the customer's estate
3. The energy Vendor shall dispose of all unclaimed credit balances
according to customary procedures or applicable Washington State law
OTHER PROVISIONS
Term of Agreement
This agreement is effective from the date of execution for the current heating
season which is defined as October through August and must be renewed on an
annual basis.
Termination
3
This agreement may be terminated by either party with a thirty (30) day written
notice to the other party. Termination shall not extinguish authorized obligations
incurred during the term of the agreement. If LIHEAP funding is withdrawn,
reduced or eliminated by the Department of Commerce, the agency has the right
to terminate this agreement immediately.
Assignment of Agreement
Neither party may assign the agreement or any of the rights, benefits and
remedies conferred upon it by this agreement to a third party without the prior
written consent of the other party, which consent shall not be unreasonably
withheld.
The Vendor and the Agency do hereby agree to the conditions set forth in this
agreement.
Agency
Signature
. tipckkl
Timothy L. Hockett
Printed Name
Executive Director
Title
Olympic Community Action Proarams
Name of Company,
/ / 1 //Z
Date
HOME HEATING ENERGY VENDOR AGREEMENT
4
Vendor
Signature
Printed Name
Title
Name of Company
Date
P ORT A NGELES
W A S H I N G T O N , U.S.A.
Utility Advisory Committee Memo
Date: December 14, 2010
To: City Council and the Utility Advisory Committee
From: Larry Dunbar, Deputy Director of Power Systems
Subject: Northwest Public Power Association Power Supply Planning Workshop
Summary: The City must make its next commitment to the Bonneville Power Administration for
Tier 2 power supply by September 30, 2011. A workshop is being planned to provide the Utility
Advisory Committee and City Council with more information about BPA Tier 2 power supply
options and other matters of significance to the Electric Utility.
Recommendation: Staff requests that Councilmembers and Utility Advisory Committee
members identify their availability in 2011 for the workshop and RSVP to staff no later than
December 17, 2010.
Background /Analysis: On November 18, 2008, City Council approved a Power Sales
Agreement with the Bonneville Power Administration (BPA). The new Power Sales Agreement
will commence on October 1, 2011 and conclude on September 30, 2028. After holding an on -site
Northwest Public Power Association (NWPPA) workshop in June of 2009, City Council made its
first Tier 2 commitment to BPA on October 20, 2009 for the period of October 1, 2011 through
September through September 2014. The next Tier 2 commitment to BPA needs to be considered
no later than September 30, 2011 for the period of October 2014 through September 2019.
Staff is organizing the next power supply planning workshop as part of the City's membership
with the Northwest Public Power Association (NWPPA). The local workshop will be held over
two consecutive days, beginning at 9AM and concluding by 3PM each day (lunch provided). The
purpose of the workshop will be to provide the Utility Advisory Committee and City Council with
more information about BPA Tier 2 power supply options and other matters of significance to the
Electric Utility such as strategic planning, conservation and demand response, electrification of
transportation, and green retail electric rates.
Staff requests that Councilmembers and Utility Advisory Committee members RSVP to staff no
later than December 17, 2010 by circling all of the below dates that they are available.
April 12 & 13
2011
April 13 & 14
2011
April 19 & 20
2011
April 20 & 21
2011
N \UAC \Final \Electric Utility Strategic Planning Workshop doc
April 26 & 27
2011
April 27 &
282011
May 10 & 11
2011
May 11 & 12
2011
June 7 & 8
2011
June 8 & 9
2011
J»ORT NGELES
W A S H I N G T O N , U.S.A.
Utility Advisory Committee Memo
December 14, 2010
Date:
To: Utility Advisory Committee
From: Larry Dunbar, Deputy Director of Power Systems
Subject: Bonneville Power Administration Residential Exchange Program Settlement Agreement
Summary: A settlement agreement is being prepared for City Council consideration regarding
the Bonneville Power Administration's Residential Exchange Program. A meeting has been
arranged on December 15, 2010 to discuss and clarify the advantages and disadvantages of the
settlement agreement.
Recommendation: For information only, no action requested.
Background /Analysis: A settlement agreement is being prepared for City Council
consideration regarding the Bonneville Power Administration's Residential Exchange Program.
The settlement agreement is a very significant issue for the Electric Utility and will affect future
wholesale power costs for the next twenty years. A draft of the settlement agreement is anticipated
around mid to late December 2010. A factsheet dated 2007 providing a history of the Residential
Exchange Program is attached for additional information.
Through the City's memberships with the Western Public Agencies Group and the Public Power
Council, a meeting has been arranged for policymakers and staff on December 15, 2010 to discuss
and clarify the advantages and disadvantages of the settlement agreement. The meeting facilitator
is Terry Mundorf and the host utility is Mason County Public Utility District No. 1, a total of 7
regional electric utilities have been invited to attend.
The meeting will be held at the Alderbrook Resort located in Union, WA from 9am to 1 pm.
Travel to the meeting will be by City vehicle and will leave City Hall at 6am and return by 4pm,
lunch and refreshments will be provided. The following Utility Advisory Committee and City
Council members have indicated that they are planning to attend: Dan Di Guilio, Cheri Kidd, and
Dean Reed. The following staff members are also planning to attend: Glenn Cutler, Bill Bloor,
Yvonne Ziomkowski, and Larry Dunbar.
Attachment: Factsheet, A History of BPA's Residential Exchange Program
N \UAC \Final \BPA Residential Exchange Program Settlement Agreement docx
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
facts
A history of BPA's
Residentia 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 Power Administra-
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 5(c) 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 to provide rate relief to Northwest residential
and small farm customers served by high -cost
investor -owned utilities, as well as to residential
and small farm customers served by high -cost
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
utilities with preference rights. At the same time,
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 of the Federal Columbia River Power
System (FCRPS) would be shared with those
Northwest utilities whose average system cost or
ASC (average cost of resources) 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 farm customers and cannot be used for any
other purpose, such as profits or to subsidize other
aspects of a utility s business.
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 sunilar 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" Jackson 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 pnmanly 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 terms
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 -farm 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
The 7(b)(2) rate test
The Northwest Power Act provides, through
Section 7(b)(2), a complex formula (rate test)
that, in general terms, shields preference custom-
ers from certain impacts of the Northwest Power
Act. Basically, this rate test is designed to ensure
that the cost of the Residential Exchange Pro-
gram and other factors, when considered togeth-
er, do not raise the rates of public utilities beyond
what they would have been absent the Northwest
Power Act.
Section 7(b)(2) includes five assumptions the
Administrator uses to develop a set of costs that
is compared with a set of costs reflecting the
Northwest Power Act. This comparison is used
in setting preference rates. (See box on five
assumptions.)
If Section 7(b)(2) "triggers," then an amount
of costs is allocated to rates other than the PF
(Priority Firm) power rate, which is the rate that
applies to preference customers' requirements
loads.
Consequently, BPA develops a PF Exchange
rate for REP loads that includes costs from any
Section 7(b)(2) trigger amount. If there is a
trigger, the PF Exchange rate is higher than the
PF Preference rate, and the difference between
the PF Exchange rate and the utility's ASC,
multiplied by the utility's residential and small -
farm load, determines the REP benefits for a
qualifying utility.
Administrator Peter Johnson said of this section,
" ... 1 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 "
Section 7(b)(2) includes five assumptions the
Administrator is to observe in setting preference
rates. 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 to those utilities' residential and small -
farm customers.
2. BPA's public utility customers would serve certain
of the direct - service industries with 100 percent firm
power. The industries that would be served by the
public utilities are (a) those industries served by BPA
and (b) those that are situated within or adjacent to
the service territories of the public customers.
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
The five assumptions
4
3. The preference customers' Load, including the
DSI loads mentioned in the second assumption,
would be served first with Federal Base System
power.
4. If 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.
5. 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.
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 1, 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
An ASC represents the average cost of resourc-
es for any given utility. An ASC cannot, by law,
include additional resource costs to serve new
large single loads or extra - regional load or the
costs of a resource terminated prior to commer-
cial operation. The calculation includes a
number of details, but generally, power costs
and certain transmission costs are currently
included in the ASC, although distribution costs
are excluded. Customers with market purchases
or those who own their own generation are most
likely to have ASCs that are higher than BPA's
PF Exchange rate. Since many of the North-
west's investor -owned utilities own coal or gas -
fired plants, historically they have had higher
ASCs than BPA's PF Exchange rate.
BPA's 1981 RPSAs included a number of contractual
terms and conditions describing BPA'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 DSls 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 pnce 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 (PaciCorp v. Fed
Energy Regulatory Cornnt'n, 759 F.2d 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
tally. 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 Depaititient of Energy, BPA and
the governors of the four Northwest states all called
for a Comprehensive Reviews 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 Appropnations 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 Apnl 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
8 Puget had a Penodic 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.
Key issues can swing REP payments substantially
When BPA does a 7(b)(2) test, it must develop a
hypothetical case to determine what the costs to
preference customers would have been under the
five 7(b)(2) assumptions. There are many arcane
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
brings up the question of what can be included in
BPA's resource stack in this hypothetical world.
An example is the Mid - Columbia resources not
dedicated to public load (approximately 800 MW
of hydropower, which are relatively cheap). The
publics that own the Mid - Columbia dams sold a
significant amount of the power to the IOUs by
contract. If 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
scenario, BPA's resource costs would be compara-
tively low. That would mean a surcharge is more
likely to be added to the PF Exchange rate to ensure
the publics aren't paying more than they would
have in circumstances reflecting the five 7(b)(2)
assumptions. This would reduce REP benefits.
8
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.
If, however, the Act means that in the hypothetical
case those Mid - Columbia resources dedicated to
IOU load are unavailable to BPA, then BPA would
have to go to the next cheapest resources in the
resource stack, which is much more expensive than
the Mid - Columbia hydro. This makes 7(b)(2) less
likely to trigger, and therefore means higher REP
benefits for the IOUs.
The issue of whether the Mid - Columbia resources
could be included in the BPA resource stack came
up in 1996 but turned out to be moot since at the
time there were enough Federal Base System
resources to meet public needs without these
additional resources. At the time, BPA assumed
that only the resources exported could be included
in the resource stack.
The issue next arose in 2002, where it once again
became moot. During the WP 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 be an issue as it remains an
open question.
BPA has calculated that this issue alone would
create a difference between the IOUs receiving
$30 million annually versus $260 million annually.
There are other similarly arcane issues that can
swing the benefit levels substantially.
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 $)
450,000
400,000
350,000 -
300,000 -
250,000 -
200,000 -
150,000 -
100,000 -
1
50,000 - '
19P, / R , n 9 H / P19 /9 9 / % <. 0 ' RJ b 0 ; ° 0; qi b 0; ' %,; -'
0 `,; -'
G 1 8 0 ' J 6� N D / I J J J % N 0/
Fiscal Year
FYS 2007 through 2011 benefits were computed pnor to the May 3 2007, 9th Circuit decision
9
provide 2,200 aM W 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.
❑ All IOUs
• All Publics
• Puget Sound Energy
❑ PGE
• PacifiCorp (UP &L)
® PacifiCorp (PP &L)
• NorthWestem Energy
❑ Montana Light & Power
❑ Idaho Power
• 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 Adintntstratton.
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.
10
In the winter of 2001, wholesale power pnces 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 pnces. 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 -farm
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 $160 million of payments between 2004 -2006
and defer another $100 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
I I
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
t0 Certain provisions forAvista, Idaho Power, NorthWestern and
PGE were different from those in Pacific's and Puget's contracts
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 pnnciples 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
DOC /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, Avesta, 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