HomeMy WebLinkAboutCity of Saint Paul Technical Feasibility Report Powerhouse Integration TDX Nov 2006REPORT ON
TECHNICAL, ECONOMIC AND
REGULATORY / LEGAL FEASIBILITY OF INTEGRATING
ST. PAUL, ALASKA POWER PLANTS
November 6, 2006
01AS CITY
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THE CITY OF ST. PAUL, ALASKA
SUBMITTED TO
And TaA
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TDX POWER, INC.
CAJCommonwealth Associates, Inc.
cnginccrs•cunKultants.ctmstructinn managcrx
In Association with
Electric Power Systems, Inc. and David Johnson Consulting, LLC
TABLE OF CONTENTS
ExecutiveSummary .....................................................................................................................................................I
Section1 — Introduction..............................................................................................................................................4
1.1 Background.........................................................................................................................................................4
1.2 Report Organization........................................................................................................................................... 9
Section 2 — Technical Feasibility ...........................................................
2.1 Scope..............................................................................................
2.2 Introduction...................................................................................
2.3 Operating Evaluation of Existing Utility Systems ..........................
2.3.1 City of St. Paul......................................................................
2.3.2 TDX POSS Camp.................................................................
2.3.3 Summary ................................................................................
2.4 Plan Evaluation.............................................................................
2.5 Technical Expertise........................................................................
2.6 Power Sales Evaluation.................................................................
...............................................................11
...............................................................11
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11
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...............................................................16
......................... —17
Section3 — Economic Feasibility ..............................................................................................................................18
3.1 TDX Cost Estimate.. .......................................................................................................................................... 18
3.1.1 Capital Costs............................................................................................................................................18
3.1.2 Operating and Maintenance Costs............................................................................................................18
3.2 Fair Market Value o St. Paul Electric Utility 21
3.2.1 Net Book Value........................................................................................................................................21
3.2.2 Replacement Cost.....................................................................................................................................22
3.2.3 Present Value of Future Cash Flows........................................................................................................22
3.2.4 Summary of Fair Market Value Alternatives...........................................................................................24
Section4 — Operating Feasibility..............................................................................................................................25
Section5 — Regulatory Issues....................................................................................................................................28
5.1 Likelihood of Economic Regulation..................................................................................................................28
5.1.1 Overview of Regulation...........................................................................................................................28
5.1.2 Acquisition by TDX (or an Affiliate).......................................................................................................29
5.1.3 Power Sale Agreement.............................................................................................................................30
5.1.4 Summary — RCA Statements Concerning St. Paul Utilities.....................................................................31
5.2 Process for CPCN Transfer..............................................................................................................................32
5.2.1 Overview of Process................................................................................................................................32
5.2.2 Action by RCA.........................................................................................................................................34
5.3 Likelihood of Favorable Action on CPCN Transfer Application......................................................................35
5.3.1 Discussions with Staff..............................................................................................................................35
5.3.2 The RCA's Test.......................................................................................................................................35
5.4 Operating Decisions That Require RCA Approval...........................................................................................39
5.4.1 RCA Authority.........................................................................................................................................39
Section 6 — Options and Recommendations............................................................................................................42
6.1 Introduction and Approach............................................................................................................................... 42
6.2 The Fundamental Assumption...........................................................................................................................42
6.3 Power Cost Equalization..................................................................................................................................42
6.3 Base Case Rates................................................................................................................................................44
6.3.1 Assumptions.............................................................................................................................................44
6.3.2 Results......................................................................................................................................................45
6.4 Sale of Electric Utility to TDX..........................................................................................................................46
6.4.1 Description...............................................................................................................................................46
6.4.2 Potential Benefits of Sale.........................................................................................................................46
6.4.3 Issues To Be Worked Out........................................................................................................................47
6.4.4 Retail Rate Projections.............................................................................................................................51
6.4.5 Recommended Process for Moving Ahead..............................................................................................54
6.5 Power Sale Option............................................................................................................................................54
6.5.1 Description...............................................................................................................................................54
6.5.2 Potential Benefits of A Power Sale Option..............................................................................................54
6.5.3 Issues to be Worked Out..........................................................................................................................54
6.5.4 Retail Rate Projections.............................................................................................................................55
6.5.5 Recommended Process for Moving Ahead...............................................................................................57
6.6 Phased Approach..............................................................................................................................................57
6.6.1 Description...............................................................................................................................................57
6.6.2 Potential Benefits of the Phased Approach..............................................................................................58
6.6.3 Issues to Be Worked Out..........................................................................................................................58
6.7 TDXSells Wind Turbines To the City ...............................................................................................................58
6.7.1 Description...............................................................................................................................................58
6.7.2 TDX Invested Capital..............................................................................................................................58
6.7.3 Potential Benefits.....................................................................................................................................59
6.7.4 Issues to be Worked Out..........................................................................................................................59
6.8 City Keeps Electric Utility But Outsources the Operation of the Utility to TDX..............................................59
6.8.1 Description...............................................................................................................................................59
6.8.2 Potential Benefits.....................................................................................................................................59
6.8.3 Issues to Be Worked Out..........................................................................................................................59
Appendix 1 — List of People Interviewed.................................................................................................................61
Appendix 2 — Detailed Replacement Cost Calculations.........................................................................................63
GenerationReplacement Costs............................................................................................................................... 63
DistributionEquipment Summary ........................................................................................................................... 64
Transformers......................................................................................................................................................65
Appendix3 — Matrix of Options and Assumptions.................................................................................................66
Appendix4 — Avian Impacts.....................................................................................................................................67
Appendix 5 — TDX Wind Power Experience...........................................................................................................73
This report is prepared by Commonwealth Associates, Inc ("CAI" or the "CAI Team") in
association with Electric Power Systems, Inc ("EPS") and David Johnson Consulting, LLC
("David Johnson"). It is in response to a Request for Proposals ("RFP") issued jointly by the
City of St. Paul, Alaska and TDX Power, Inc. requesting an analysis of the Technical, Economic
and Regulatory/Legal Feasibility of Integrating St. Paul, Alaska Power Plants. The City of St.
Paul ("City") currently owns and operates the electric utility on St. Paul Island and depends on
diesel generation for its power supply.
TDX Power, Inc. ("TDX") has proposed to acquire the City -owned electric utility and to
construct, operate and maintain a high -penetration wind -diesel generating system. TDX has
suggested that this combined operation will lower electric rates for St. Paul citizens. CAI's task
was to provide an independent, third -party technical, economic and regulatory review of the
TDX proposal. This report presents the results of that review and makes recommendations on
how to proceed.
EPS has evaluated the TDX conceptual design and cost estimate. EPS recognizes the conceptual
design does not represent a detailed engineering design and therefore there is a level of
uncertainty in the cost estimate and required equipment. EPS concludes that the TDX design and
cost estimate are reasonable with some additions to account for the uncertainties. EPS has
evaluated the reliability of the City's electrical system. EPS has EPS has similarly analyzed
other Alaskan rural utility systems and believes that the reliability of the City system is within
normal ranges for rural Alaskan utilities. Likewise, EPS reviewed the TDX reliability at its
POSS Camp installation and determined that it meets normal expectations for a small-scale self -
generating industrial plant.
CAI has reviewed TDX's estimates of annual operating and maintenance costs for the integrated
utility. CAI recommends increasing the number of employees from the three included by TDX
to five. In light of this increase, TDX has agreed to drop the $150,000 management fee included
in its original proposal.
CAI has developed a set of estimates for the fair market value of the St. Paul electric utility.
These estimates range from a low of $2.9 million to a high of $7.6 million. These estimates
establish a range of possible purchase prices for the utility. The ultimate purchase price will be
subject to negotiation.
The City and TDX asked CAI to "evaluate the respective management and operating expertise of
both TDX and City personnel." The RFP specifically requested that CAI "Make a
recommendation as to which entity, the City or TDX, should own and operate the integrated
utility." CAI interprets the phrase "integrated utility" to mean a utility using diesel generation
and five wind turbines as proposed by TDX. CAI also interprets this question as specifically
referring to a situation where a single entity both owns and operates the utility.
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In answer to this narrowly defined question, CAI believes that TDX is the more capable of the
two entities to operate such a utility. This judgment is primarily supported by the significant
edge that TDX has over the City in wind generation experience.
However, the situation described in this question is not the only option on St. Paul Island. CAI
has also evaluated a power purchase option where the owner and operator are not the same
entity, and where an "integration" of the respective systems may occur without the City
necessarily selling the electric utility to TDX. CAI also recommends additional options for the
City and TDX to consider. These options include: (A) a phased approach where the first step is a
power sale possibly followed by a sale of the utility, (B) an option where the City owns the wind
turbines, and (C) an option where the City outsources operation of the entire utility to TDX.
Section 6 of this report describes these options.
TDX and the City have posed several distinct regulatory issues, starting with the prospect of
economic regulation if the respective electrical systems on St. Paul Island are integrated. They
then ask about the regulatory process for transferring the City's operating authority (as a public
utility) and whether an application to approve this transfer will be granted. Lastly, they inquire
about the operating decisions that the regulatory agency must approve once the systems are
integrated.
Briefly, economic regulation is almost certain if TDX or an affiliate acquires the City's electric
utility, and possible if the parties enter into a power sales agreement in which the owner of the
POSS generation facility sells electric energy to the City. The regulatory process for transferring
operating authority is straightforward at present, but subject to change depending on the outcome
of a pending rulemaking proceeding (R-04-04). No "roadblocks" to approval of this transfer are
foreseen at present if the applicants (1) file an application to transfer the operating authority that
is complete in all respects, and (2) anticipate and discuss (to the regulatory agency's satisfaction)
issues that might appear out of the ordinary or that otherwise might merit explanation, e.g., due
to the transaction terms, the plans for the combined utility, and the situation on St. Paul Island.
Finally, and once an acquisition occurs, the regulatory agency will most likely assume final
authority for overseeing the combined utility's rates and service, under detailed regulations that
the agency has adopted.
This report concludes with an estimate of what system average electric rates might be under
three different cases: (1) a Base Case where the situation continues as it is today, (2) a Sale of the
Electric Utility to TDX case, and (3) a Power Sales option. The following Chart 1 shows the
estimated system average rates in these three cases.
Chart 1
Estimated System Average Electric Rates ($/kWh)
$0.50
$0.45
$0.40
$0.35
$0.30
$0.25
$0.20
$0.15
$0.10
$0.05
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
CBase Case f Sale of the Electric Utilty to TDX —iF Power Sales Option
AICommonwealth Associates, Inc. Page 2
As the above chart shows, either the Power Sales Option or the Sale of the Electric Utility case
can be expected to lower rates when compared to the Base Case. The details of these estimates
on explained in the report.
The report identifies certain issues that the parties may wish to address during negotiation and
proposes possible solutions for some of those issues. The report also identifies steps for the
parties to consider if they decide to proceed towards a possible agreement to implement any of
the options. In the case of a sale of the utility to TDX, these steps include a vote of the St. Paul
citizens.
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Commonwealth Associates, Inc. ("CAI") is pleased to present this report to the City of St. Paul,
Alaska ("the City") and TDX Power, Inc. ("TDX"). CAI completed this report and the work it
represents in association with Electric Power Systems ("EPS") and David Johnson Consulting,
LLC ("David Johnson"). This report may alternatively refer to this team and its members by
their individual names ("CAI", "EPS", or "David Johnson") or together as the CAI Team or the
Team.
The CAI Team completed this work in response to a Request for Proposals issued by the City
and TDX titled Request for Proposals for Independent Assessment of Technical, Economic, and
Regulatory/Legal Feasibility of Integrating St. Paul, Alaska Power Plants. CAI presented
proposal P-06-136 in response to that RFP and completed this work under CAI project #370001.
TDX has proposed to acquire the City -owned electric utility on St. Paul Island and to construct,
operate and maintain a high -penetration wind -diesel generating system. TDX has suggested that
this combined operation will lower electric rates for St. Paul citizens. The job of the CAI Team
was to provide an independent, third -party technical, economic and regulatory review of the
TDX proposal. The Team has completed this assignment and achieved that goal. This document
reports the results of those reviews and makes recommendations on how to proceed.
To conduct this study, the CAI Team interviewed numerous individuals knowledgeable about the
TDX proposal and the existing utility system on St. Paul Island. The Team interviewed others
regarding TDX and its operations and service both on St. Paul Island and elsewhere in Alaska.
Lastly, CAI interviewed individuals regarding State of Alaska programs and other issues that
may affect the implementation of the TDX proposal. A list of persons interviewed is included as
Appendix 1 to this report.
In addition to interviews, the CAI Team conducted extensive research regarding areas ranging
from legal/regulatory issues that might affect a transfer of the utility, to accounting and financial
research regarding the City's books of account, to system control hardware and software required
in a high -penetration wind -diesel system. Finally, CAI examined the TDX financial models and
conducted additional analysis to test financial results under differing assumptions.
1.1 Background
Chart 2 shows St. Paul residential electric rates before Power Cost Equalization (PCE) benefits
from July 2001 to date.
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Chart 2
St. Paul Residential Electric Rates Before PCE
$0.50
$0.45
$0.40
$0.35
r
$0.30
$0.25
$0.20
$0.15
$0.10
$0.05
$-
Jul-01 Jul-02 Jul-03 Jul-04 Jul-05
Source: City of St. Paul PCE Reports
Jul-06
Residential rates peaked in late 2004. After dropping in early 2005, rates have risen nearly back
to late 2004 levels.
CAI reviewed individual residential customer billing data for 2005. This data included account
numbers, monthly consumption, PCE benefits and total billing for each customer and amounted
to more than 6,600 individual data points. Of the 139 residential customers, there were 108
customers with bills for the full twelve months. These customers were the only used in the
analysis.
Chart 3 shows the average monthly consumption for these 108 residential customers. Each data
point is the average of the twelve-month's consumption for one customer. Average monthly
consumption for these customers ranged from 220 kWh per month to a high of 1,359 kWh per
month. Among all 108 customers, the average consumption was 586 kWh per month.
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Chart 3
Average 2005 Monthly Consumption of 108 St. Paul Residential Customers — All Have 12 Months of Bills
1,600
1,400
1,200
s 1,000
c
0
800
600
400
200
0
Avg. = 586 kWh per Month
Source: City of St. Paul Billing Data
Chart 4 shows the 2005 average monthly bill after PCE benefits for each of these 108 residential
customers. The average bill for an individual customer ranged from a low of $45.18 per month
to a high of $420.04 per month. The average for all 108 customers was $143.63 per month.
Chart 4
Average 2005 Monthly Bill (After PCE Benefits) of 108 St. Paul Residential Customers
All Have 12 Months of Bills
$450.00
$400.00
$350.00
$300.00
$250.00
$200.00
$150.G-
$100.00
$50.00
$0.00
Avg. Mo. Bill = $143.63
Source: City of St. Paul Billing Data
The following Chart 5 compares City electric rates to other selected Alaskan communities.
%Commenwealth Associates, Inc. Page 6
Chart 5
Average Residential Rate Based on 500 kWh Per Month Before PCE Benefits
90.00
80.00
70.00
60.00
. 50.00
40.00
U 30.00
20.00
10.00
0.00
G°li1N ��N G°�Q
a"`
,� G� �� �� r G ��` �, �`° �` •moo, ���
Source: Statistical Report of the Power Cost Equalization Program, Fiscal Year 2005, Alaska Energy Authority
Commercial rates have risen over the past few years as shown in Chart 6.
Chart 6
St. Paul Commercial Electric Rates
$0.500
$0.450
$0.400
$0.350
$0.300
L
Y $0.250
$0.200
$0.150
$0.100
$0.050
q5 do q1 q4 c� CP O� 01' O� C1" 05
Source: St. Paul Monthly PCE Filings
The unusual dips in the rates shown in Chart 6 are most likely bad data and can be ignored. This
chart shows that commercial rates have increased an average of 4% per year between July 1995
and June 2006. This is a not an unusually high rate of increase. However, if one looks at the
%Commonwealtb Associates, Inc. Page 7
period July 2002 to June 2006, the average rate of increase is 10% per year. These are
significant increases and are likely due to climbing diesel fuel prices.
It is expensive to live and conduct business on St. Paul. This is evident in the cost of food. The
following Chart 7 shows the cost of a week's food for a family of four in St. Paul compared to
other Alaskan communities and to Portland, Oregon. St. Paul is the highest cost area shown on
this chart. This does not necessarily mean that St. Paul is the highest cost area in Alaska. It is
only the highest cost area of those surveyed. Data for additional Alaskan communities that
might have higher costs than St. Paul was not readily available from the same source. The raw
data for this chart and for the same communities for other periods is available on the internet at
www.uaf.edu/ces/fcs/index.html.
Chart 7
Cost of One Week's Food For A Family of Four
$- $50 $100 $150 $200 $250 $300
St. Paul
Naknek-King Salmon
Dillingham
Bethel
Haines
Dutch Harbor
Cordova
Homer
Kodiak
Seward
Delta Junction
Sitka
Kenai
Juneau
Ketchikan
Anchorage
Fairbanks
Mat -Su Area
Portland, Ore
$171
$171
- $165
$159
$148
$136
$136
$135
S129
■ $125
■ $122
1 $118
$114
$111
$109
$203
$245
$227
$224
Source: "The Cost of Living in Alaska" by Neal Fried and Dan Robinson. Published in Alaska Economic Trends,
July 2006
The following two charts show a recent decline in school district enrollment and population on
St. Paul Island.
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180
160
140
120
100
80
60
40
20
0
Chart 8
Average Daily Enrollment
Pribilof School District
1999 2000 2001 2002 2003 2004 2005 2006
Source: Pribilof School District
Chart 9
St. Paul Population
yvv
800
700
600
500
400
300
200
100
0
O� 01 O1 T T C� O O O O O O
a 7 7 7 7 7 7 7
Source: St. Paul PCE Data FY95-August 2006 supplied by AIDEA
This information simply illustrates the difficult economic situation on St. Paul Island. There are
multiple factors that affect economic development. One of those factors is electric rates. This
study has not specifically examined the extent to which electric rates impact economic
development on St. Paul Island and can make no conclusions in that regard. With that
qualification, however, CAI is comfortable saying that lowering electric rates may help improve
the economic situation.
1.2 Report Organization
The remainder of this report is organized into the following major sections.
Section 2 — Technical Feasibility — which reviews the TDX design for the installation of wind
turbines and interconnection with the City's existing electrical system, the electrical reliability of
the City's and TDX's existing electrical systems, and the technical expertise of each entity to
operate the integrated utility. Finally, this section recommends changes as appropriate to the
TDX cost estimate for interconnection.
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Section 3 — Economic Feasibility — which reviews the TDX estimate of annual operating and
maintenance costs and recommends appropriate changes. This section also estimates the fair
market value of the City's electric utility using three commonly used methods.
Section 4 — Operating Feasibility — which evaluates the ability and expertise of the City and TDX
to own and operate the integrated utility.
Section 5 — Regulatory Issues — which evaluates the likelihood of RCA regulation of TDX if it
acquires the City's electric utility. This section also describes the process for, and the likelihood
of approval by the RCA of, the transfer of the City's Certificate of Public Convenience and
Necessity to TDX in the case of an acquisition by TDX.
Section 6 — Options and Recommendations — This section discusses the Power Cost Equalization
program operated by the State of Alaska. CAI then estimates retail rates if the City continues to
own and operate the electric utility as it does today. This situation is referred to as the Base
Case. Other cases are then evaluated including: Sale of the Electric Utility to TDX, a Power Sale
Option, a Phased Approach, an option where TDX Sells Wind Turbines to the City and finally an
option where the City Keeps the Electric Utility But Outsources the Operation of the Utility to
TDX.
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Electric Power Systems ("EPS") prepared this section of the report, which reviews the technical
feasibility of the proposed wind -diesel integration project.
EPS has evaluated the TDX conceptual design and cost estimate. EPS recognizes the conceptual
design does not represent a detailed engineering design and therefore there is a level of
uncertainty in the cost estimate and required equipment. EPS has determined that the TDX
design and cost estimate are reasonable with certain additions to the cost estimate to account for
the uncertainties. EPS has evaluated the reliability of the City's electrical system. EPS has
similarly analyzed other Alaskan rural utility systems and believes that the reliability of the City
system is within normal ranges for rural Alaskan utilities. Likewise, EPS reviewed the TDX
reliability at its POSS Camp installation and determined that it also meets normal expectations
for a small scale, self -generating industrial plant.
2.1 Scope
The TDX proposal includes a conceptual design showing the major components required for
integrating wind with the City's diesel generation. The design is in the very early stages of
completion and does not include detailed engineering or cost estimates but does include
conceptual operations and costs. TDX based the conceptual design on expanding the POSS
Camp system to meet the needs of the City. The purpose of EPS's portion of this report is to
evaluate the TDX conceptual plan for technical feasibility and review estimated costs to
implement the wind integration.
2.2 Introduction
The TDX conceptual design uses five Vestas 225 kW wind turbines to offset diesel generation
on St. Paul Island. The City's existing diesel plant will house two new Caterpillar 3456
generators rated at 455 kW along with the City's existing unit 6, rated at 855 M. The two
Volvo 100 kW generators at the POSS Camp would remain in the system for light diesel load
requirements. Initially, a diesel generator will run at all times to support system voltage and
assist with frequency regulation. A 600 kW binary load controller and load bank will be
installed at the POSS plant for additional wind frequency regulation. Additional load banks
(electric boilers) could be installed at sites within the community to offset heating costs with
surplus wind energy; one of these is included in the cost estimate and located at the elder care
facility.
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2.3 Operating Evaluation of Existing Utility Systems
2.3.1 City of St. Paul
EPS assessed the City of St. Paul's existing distribution and generation systems for reliability
and operational aspects. Additionally, EPS reviewed the system configuration and outage
records.
The distribution system consists of underground utilities using a combination of directly buried
cable and cable installed in conduit. The City replaced a majority of the distribution cable with
aluminum cable from 1995 to 1996. All service equipment is pad mounted. There are
approximately 36 three -position and four, four -position fiberglass junction cabinets. There are
three Cooper sectionalizing cabinets. The sectionalizing cabinets and service transformers use
standard painted steel enclosures. EPS did not verify the transformer connections, but the as -
built drawings indicate all three-phase transformers in the distribution system are connected per
the Rural Utility Service.
The generation system consists of six Caterpillar diesel generators housed in a common
powerhouse. Units 2 and 3 are out of service due to mechanical failures. The primary operating
units are units 1, 4 and 6. Typically, the City operates units 4 and 6 together. Table 1 describes
these units.
Table 1
City of St. Paul Diesel Generating Units
Unit #
Voltage
kW
Status
Unit 1
4160
855
Major — 8/01, top end 5105
Unit 2
480
600
Needs OH - out of service
Unit 3
480
210
Major — 3/05 - broken front gear train
Unit 4
480
300
Major — 7/03
Unit 5
480
650
Major — 5/94
Unit 6
480
855
Major — 4/05
The existing diesel generator controls are basic with manual control only. The speed and voltage
controls are industry standard, using Woodward speed controls and Basler voltage controls. The
engine start/stop/protectives use the Caterpillar standard manual control packages with no remote
monitoring or control. The City is in the process of upgrading the protective relays. Units 4 and
6 have Basler BE1 overcurrent relays. Units 2, 3 and 5 are using basic Crompton relays. Unit 1
has a more comprehensive protective package using a combination of Beckwith and Basler
relays.
Units 2 through 6 operate at 480 volts and supply a common 480-volt bus. The 480-volt bus is
stepped up to 12.47 kV using a delta -to -grounded wye transformer. The City has recently
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converted the 480-volt bus to an ungrounded bus with a zig-zag transformer for ground fault
detection. Unit 1 operates at 4.16 kV and is stepped up to 12.47 kV through a delta -to -grounded
wye transformer. The two step-up transformers connect to a 15 kV distribution switch located
outside the powerhouse in a wood structure. The distribution switch has four feeders; three of
which supply different sections of town (feeders) and one which is used for a temporary station
service feed (normally open). The distribution switch has basic overcurrent protection for each
feeder along with provisions for remote operation of the switches. The remote operators are
currently out of service due to faulty control wiring.
The City's outage records indicate that it has improved electric reliability over the past three
years. Between 2000 and 2002, the City experienced 29 unplanned area -wide and partial
outages.' From 2003 to 2005, however, the City experienced only eight unplanned area -wide
and partial outages.z
The recent reliability of the City's electric utility is very good. The City has improved the
generation plant reliability by upgrading equipment and modifying the configuration. The new
protective relays have improved coordination for clearing faults and limiting area wide outages.
The underground distribution system has also proved to have good reliability.
2.3.2 TDX POSS Camp
EPS reviewed the TDX POSS Camp system to determine the reliability of a similar system
proposed for the City's energy needs. The POSS Camp system consists of one 225 kW Vestas
wind turbine and two 100 kW Volvo diesels. The entire system operates at the 480-volt level.
The diesel controls use Encorp devices for speed control and an unknown manufacturer for
voltage control. The controls are automated using a PLC based control system for automatic
start and stop along with remote alarm capabilities. The protective relaying is basic, using
Crompton relays. The POSS Camp distribution system is confined to the building low -voltage
distribution system.
The POSS Camp generation system's reliability is good. The POSS Camp experienced 13
unplanned outages between January 1, 2004 and December 31, 2005. A majority of the outages
recorded were documented as equipment failures at the controls level and have very short outage
times. The reader should note that the POSS Camp outages were not due to failures of the wind
turbines. In fact, TDX reports that wind turbine availability was 100% during 2004 and 2005,
meaning that the turbines were always available to produce power if the wind was blowing
within the acceptable ranges.
1 Twelve of these outages were caused by a common problem with the diesels' day tanks and eight of the outages
were caused by a distribution cable fault that was not located until a complete failure occurred on the eighth outage.
A majority of the 2000 — 2002 distribution outages were complete outages due to a miss -coordination of the system
protective relays. The generation protective relays would trip the generators off-line prior to the distribution switch
clearing the faulted feeder.
2 The distribution outages occurring after 2002 were (all but one) partial outages with the distribution switch
clearing the faulted feeder prior to the generation tripping off-line, keeping the unfaulted feeders on-line.
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2.3.3 Summary
While the POSS Camp system did experience more outages, EPS continues to assert that the
reliability of both systems is good. Because the POSS Camp is the only "customer" for the TDX
wind power, there is no requirement to be on-line 100% of the time, and a certain number of
short outages is acceptable. Also, the control equipment used at the POSS Camp is not utility
grade equipment, such as that found at the City's plant. EPS does not expect that TDX would
experience the same number of outages as it has faced at POSS Camp if it acquires the City's
system, with the corresponding installation of new utility grade equipment.
It is not reasonable to compare the POSS Camp distribution reliability to the City's distribution
system. The City's system is a medium -voltage system with much more complexity than the
POSS Camp low -voltage distribution system.
The TDX conceptual integration plan includes implementation of upgraded controls at both the
POSS camp and the City plant. EPS expects that the updated controls will be utility grade and
will increase the overall reliability. The proposed replacement of the distribution switch will
also improve distribution reliability, limiting outages to the effected feeder only. Overall, the
system reliability should improve with the addition of new generators, upgraded switchgear,
automated controls and upgraded distribution feeders along with the addition of the wind
turbines.
2.4 Plan Evaluation
The proposal submitted by TDX is a conceptual plan. The engineering is in the very early design
stages and therefore many engineering details have yet to be sorted out. EPS reviewed the plan
for its overall feasibility and proposed costs.
Silicon controlled rectifiers (SCR) are currently being used for frequency control at the POSS
Camp. With a properly sized load bank and sufficient energy being diverted to the load bank,
the SCRs can control the frequency for both load acceptance and rejection. The SCRs are
controlled by a binary controller4, which monitors the system frequency and adjusts the SCR
controlled load bank as required. The TDX proposal includes increasing the size of the POSS
Camp binary controller and load bank to regulate frequency on the integrated system and provide
capacity in the load bank for five wind turbines.
Before connecting the TDX POSS Camp to the City's system, it will be necessary to monitor the
power quality when the load bank is on-line. The load bank uses SCRs to control the amount of
energy being dumped into the resistive heaters. SCRs can cause waveform distortion, or "dirty
power". Sufficient distortion can cause various problems with the end users (customers
interconnected with the wind plant). Filter banks or some other power conditioner may be
s A silicon controlled rectifier is a device used for power switching. In this application, the SCRs will be used to
quickly vary load on the resistive load bank. For example, as excess energy is produced from the wind site, the
system frequency will increase if the excess energy is not quickly dissipated. The SCRs will increase the load on the
load bank to maintain system frequency.
4 The binary controller is a device used to monitor system frequency and provide a signal to the SCRs. The binary
controller is essentially the wind turbine's "governor".
%Commonweafth Associates, Inc.
Page 14
required to correct the waveform distortion. This may be required at the TDX interconnect point
or possibly at each sensitive end user (Coast Guard).
The TDX conceptual plan does not address how the system voltage will be supported and fault
current will be supplied when on 100% wind generation. EPS understands that TDX is planning
to operate a diesel generator in parallel with the wind generator to provide voltage support.
When 100% wind integration is desired, equipment for voltage support will be added at the
POSS camp. Synchronous condensers5 are a viable option to provide voltage support at this
time, but new technology is being developed that can be investigated in the future. It will also be
critical that. TDX engineer the size and location of the voltage support device such that all
distribution feeders are adequately protected. Furthermore, consideration will have to be given
to any future motor loads that may be added to the City's system. The voltage support device
must be able to support any motor starting currents.
Currently, the City uses jacket water heat recovery from its diesel generators to provide building
heat at the public works buildings. As the wind displaces diesel generation, there will be less
waste heat available for these facilities. During the transition to wind energy, the diesel
generator supporting voltage can be located at the City's plant with a jacket water heat recovery
system to supply heat to the public works buildings. There will also be surplus wind generated
electricity that can be diverted to an electric boiler, as proposed in TDX's proposal for use at the
elder care facility. An electric boiler can be located at the public works buildings for use during
100% wind operation and to supplement the jacket water heat recovery system.
The equipment required to integrate the TDX wind turbines with the diesel plant is included in
TDX's conceptual design. Based on the conceptual design, which includes operating a diesel
generator at all times, all necessary items were included and no superfluous items were included.
With the design at the early conceptual stage, EPS recommends adding a 20% contingency to the
proposed costs. The contingency will cover costs of the additional items added during the
detailed engineering design. If the proposed costs are to include 100% wind penetration a line
item will be required for a voltage support device (synchronous condenser or equivalent). Table
2 below summarizes the TDX proposed interconnection costs along with EPS's notes and
additional line items.
5 A synchronous condenser is an AC motor that is not connected to any load and is used to provide voltage support
to the connected system. Such a device is not needed at this time because the same purpose is achieved by having
diesel generators operating. If, however, TDX wants to operate in a wind -only mode, a synchronous condenser or
other similar equipment may be required.
%Cenunpoweafth Associates, Inc.
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Table 2
TDX-City Interconnect Costs
TDX-CITY INTERCONNECT
COSTS
Function
TDX Est Cost
EPS descriotioo
Design/Engineering/Consulting
$ 10,000.00
Permitting (City, ADEC, EPA, FAA etc.)
$ 5,000.00
T&D Interconnect -POSS Camp
$ 35,000.00
Equipment required to connect the POSS camp distribution to City's
distribution - meters, transformers, cable, etc.
15 KV Substation 1.5mva - POSS
$ 22,500.00
Dedicated transformer for connecting POSS 480 volt bus to City's
distribution switch at power house.
15KV Substation 1.5mva wye/delta
$ 23,750.00
Dedicated transformer for connecting POSS 480 volt bus to City's
distribution switch at power house.
15 kv T&D Feeder section -City plant
$ 135,000.00
New 15 kV switchgear at the City powerhouse to improve distribution
reliability.
2.8 miles 15kv 4/0 conductor
$ 350,000.00
2/0 dedicated feeder between POSS 480 generating bus and City power
plant
Control integration- City and TDX
$ 430,000.00
SCADA system and automated control of diesels and wind turbines.
Control automation City Power Plant
$ 225,000.00
New 480 volt switchgear and engine control panels for diesel automation.
600kw thermal node w/binary control
$ 29,500.00
Increase load bank capacity for frequency regulation and load dump for 5
wind turbines.
Low load diesel - 2ea Cat 3456
$ 158,000.00
New gensets with better fuel consumption curve and better match to system
loads.
Increase POSS camp fuel storage
$ 36,000.00
Increase capacity of POSS diesels.
Equipment/mat'l frght costs
$ 85,000.00
Labor/equip install cable & substation
$ 200,000.00
Installation of new transformers and 2/0 dedicated feeder.
Labor install control automation
$ 25,000.00
Installation of new switchgear and automation equipment
Labor install new gensets
$ 26,000.00
Installation of new generators
Labor install T&D feeder switch
$ 12,000.00
Installation of new 15 kV feeder switchgear
Labor install fuel tank
$ 5,000.00
TDX Estimated Project Costs
$ 1,812,750.00
Electric boilers for excess wind
$ 27,750.00
Electric boilers to use surplus wind generation
Contingency - 20%
$ 362,550.00
Contingency due to conceptual design
Subtotal of additions
$ 390,300.00
New Total
$ 2,203,050.00
Total including additional line items
2.5 Technical Expertise
The City's technical staff currently consists of three powerhouse operators and one lineman. The
operators run the diesel generators and monitor the plant. The current configuration of the plant
does not include automated equipment (PLCs, communications, automatic controls, etc). The
lineman is responsible for customer services, customer connections and maintaining the
distribution system. The City relies on outside engineering firms to provide support for system
modifications, troubleshooting and repairs.
TDX relies on one technician to maintain the POSS Camp plant along with technical support
from TDX Power's engineering staff. The technician is responsible for operating the POSS
Camp diesel generators and wind turbines, on -site troubleshooting and support for implementing
upgrades at the POSS Camp.
%COMMORWeafth Associates, Inc.
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The TDX conceptual design for integrating the wind turbines with the City's power grid includes
automated controls that will require more technical expertise to operate than what is currently
being used by either the City or TDX. There will be additional PLC controls, network
communications and a SCADA interface. This equipment will also require a higher level of
protective relaying to be implemented for system reliability and safety, which, in turn will
require additional training for the on -site technician and operators along with engineering
support for troubleshooting and maintenance.
2.6 Power Sales Evaluation
The technical aspects of operating with a power sales agreement will include some of the same
issues of a fully integrated system. In order for the TDX wind plant to displace diesel generation
there must be constant communication between the TDX and City personnel and/or equipment.
The amount of wind generation exported to the City must be coordinated with the diesel plant to
maintain a minimum amount of load on the diesel generator(s). TDX would be required to
implement a control system that would regulate the wind generation and load bank so that the
amount of power exported is fixed. Any change in the exported energy would have to be
coordinated with the City's diesel plant operator. The existing City plant controls would allow
for this arrangement, but would require an operator to be available for making adjustments when
the TDX energy export levels change. Automation of the City's diesel plant would improve
response time to changes in the wind and require less labor for operation, but would not be
required.
Table 3 below shows a preliminary estimate for costs associated with a power sales agreement
assuming minimal automatic control on the City's diesel generators and always having a diesel
generator operating to support voltage. If the power sales agreement includes 100% wind
penetration, EPS recommends that the proposed costs in Table 2 be used.
Table 3
TDX-City Interconnect Costs Under Minimal Power Sales Option
TDX-CITY INTERCONNECT
MINIMAL
POWER SALES COSTS
Function
Est Cost
EPS description
Design/Engineering/Consulting
$ 5,000.00
T&D Interconnect -POSS Camp
$ 35,000.00
Equipment required to connect the POSS camp distribution to City's
distribution - meters, transformers, cable, etc.
15 kv T&D Feeder section -City plant
$ 135,000.00
New 15 kV switchgear at the City powerhouse to improve distribution
reliability.
Control integration- City and TDX
$ 75,000.00
Control modifications to POSS camp and city
Control automation City Power Plant
$ 55,000.00
Limited controls modifications to diesel plant
Equipment/mat'l frght costs
$ 30,000.00
Labor install control automation
$ 15,000.00
Installation of new switchgear and automation equipment
Labor install T&D feeder switch
$ 12,000.00
Installation of new 15 kV feeder switchgear
Electric boilers for load dumps
$ -
Electric boilers to use surplus wind generation
Power conditioner
$ -
As required to clean up distortion caused by SCR
Contingency - 20%
$ 72,400.00
Contingency due to conceptual design
Total
$ 434,400.00
%Conmonwadth Associates, Inc.
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Page 17
This section of the report will address two issues: (1) the TDX estimate of annual operating and
maintenance costs, and (2) the fair market value of the City's electric utility. Section 6 of this
report includes electric rate forecasts and more detailed discussion of options.
CAI has reviewed TDX's estimates of annual operating and maintenance costs for the integrated
utility. CAI recommends increasing the number of employees from three to five. In light of this
increase, TDX has agreed to drop the $150,000 management fee included in its proposal.
CAI has developed a set of estimates for the fair market value of the St. Paul electric utility,
which ranges from a low of $2.9 million to a high of $7.6 million. These estimates establish a
range of possible purchase prices for the utility. The ultimate purchase price will be subject to
negotiation.
3.1 TDX Cost Estimate
TDX estimated both capital and operating costs for the installation of a wind -diesel system. CAI
reviewed both of these cost estimates.
3.1.1 Capital Costs
Section 2.4 of this report reviews TDX's estimated capital costs for interconnecting the City and
TDX's systems. That review concludes that the capital costs are reasonable and all required
equipment is included with the exception of the electric boiler at the elder care facility and a 20%
contingency. With those additions, the total required capital costs are $2,353,050.
3.1.2 Operating and Maintenance Costs
The following table shows the TDX estimate of annual operating and maintenance costs for
2007.
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Table 4
TDX 2007 Estimated Annual Operation & Maintenance Costs
Generators
Fuel Cost for Diesel Engines
Personnel
Personnel: Operators, Maintenance Clerical
Labor Burden
Training
Total Cost
Operations and Maintenance
Engine maintenance (parts, freight, oil)
Fuel Truck & Tank Farm Maintenance
Equipment Rental
Utilities (Phone, Water, Refuse, Internet)
Total Cost
Office and Administrative Expenses
License and Permit Fees
Dues and Subscriptions
Insurance (Auto / Property)
Total Cost
Management Fee
Debt Service
Principal and Interest Payment for AEA loan
Total Operating Costs
TDX made the following assumptions in the above table.
$186,188
$55,856
$10,609
$180,781
$12,731
$5,305
$1,273
$12,731
$1,591
$26,523
$599,901
$252,653
$200,090
$40,845
$150,000
$144,839
$1,388,328
1. For fuel cost, TDX assumed that it would burn 202,587 gallons of diesel and that the
2007 price would be $2.96 per gallon.
2. The personnel estimate includes three employees with a 30% labor burden.
3. The $150,000 Management Fee is paid to TDX Power for maintenance services,
accounting, billing and other services.6
4. The AEA loan is to pay for capital equipment for interconnection upgrades and two of
the five wind turbines. The loan is assumed to be at 0% interest over 20 years. The other
three wind turbines are assumed to be donated by TDX.
CAI reviewed these TDX cost estimates and recommends certain changes. These changes are
described below.
Personnel Costs
CAI believes that three employees will not be sufficient to operate and maintain 5 wind turbines,
all the required controls and interconnection equipment, five diesel generators and the
distribution system as well as provide customer service, accounting and billing. Additionally,
6 It is assumed that if TDX acquires the St. Paul electric utility, a new affiliate of TDX Corp. will be operating the
utility on St. Paul Island. It is this new, and as yet unnamed, entity that would be paying the management fee to
TDX Power.
%Commonweafth Associates, Inc.
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Page 19
there are four City employees currently working primarily for the City electric utility. CAI
understands that TDX intends to hire those employees if TDX becomes the operator of the
electric utility. Consequently, CAI recommends increasing the currently assumed three
employees to five employees. This change is reflected in the assumptions that underlie CAI's
economic modeling.
CAI has discussed the above change from three to five employees with TDX. TDX concurs with
this change and has stated that with five employees, the $150,000 Management Fee is no longer
necessary. CAI will use these changes in its modeling.
Capital Costs
As explained in Section 2 of this report, CAI and EPS recommend additions to the TDX capital
estimate of a 20% contingency and an electric boiler at the elder care facility for $27,750. CAI
and TDX have also discussed the best way to model the City's long-term debt in the case of
acquisition of the utility by TDX. TDX has proposed to pay the City an amount necessary to pay
off the electric utility long-term debt ($1.4 million). TDX will then approach the State of Alaska
regarding a new loan from the Alaska Energy Authority. TDX believes that it can arrange such a
loan with a 20-year term and 0% interest. The debt service for this loan is $67,800 and is
included in the model. Section 6.4.3 explains more about the City's long-term debt.
When all these changes are made the annual costs are revised to the amounts shown in the
following Table 5.
Table 5
TDX 2007 Estimated Annual Costs With CAI Changes
Generators
Fuel Cost for Diesel Engines
Personnel
Personnel: Operators, Maintenance Clerical
Labor Burden
Training
Total Cost
Operations and Maintenance
Engine maintenance (parts, freight, oil)
Fuel Truck & Tank Farm Maintenance
Equipment Rental
Utilities (Phone, Water, Refuse, Internet)
Total Cost
Office and Administrative Expenses
License and Permit Fees
Dues and Subscriptions
Insurance (Auto / Property)
Total Cost
Debt Service
Principal and Interest Payment for AEA loan
Total Operating Costs
Total Operating Costs in dollars
%Commonwenftb Associates, Inc.
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$599,901
$310,313
$93,094
$10,609
$414,016
$180,781
$12,731
$5,305
$1,273
$200,090
$12,731
$1,591
$26,523
$40,845
$222,954
$1,477,806
Page 20
3.2 Fair Market Value of St. Paul Electric Utility
It is common to consider three different methods when considering the fair market value of an
asset such as the St. Paul Electric utility. These methods are: (1) net book value, (2) net
replacement cost, and (3) present value of future cash flows. CAI calculated each of these
methods for the St. Paul electric utility.
3.2.1 Net Book Value
Net book value looks at the accounting value of the plant -in-service and then deducts from that
the accumulated depreciation. This method is relatively straightforward to calculate.
Table 6
City of St. Paul Electric Utility
Calculation of Net Book Value
Buildings $3,091,433
Machinery and Equipment 77,604
Plant -in -Service 2,711,215
Total Property, Plant & Equipment $5,880,252
Accumulated Depreciation (1,820,429)
Net Property Plant & Equipment (Net Book Value) $4,059,823
Source: 2005 Audited Financials
If TDX acquires the St. Paul electric utility, the Regulatory Commission of Alaska (RCA) will
most likely regulate its rates; see Section 5.1 of this report for more on potential regulation. The
RCA will likely to want to know what portion of the net book value is "contributed capital."
Contributed capital refers to capital that has been provided through state, federal or other grants,
or has been paid for by someone other than the City. The RCA rarely permits an entity to
recover a payment for the acquisition of an asset that exceeds the net book value minus
contributed capital. In the present case, this does not mean that TDX could not pay more than
the net book value minus contributed capital for the acquisition of the St. Paul electric utility. It
does mean, however, that RCA would not likely allow TDX to recover anything paid above that
amount in its rates.7
The Governmental Accounting Standards Board (GASB) establishes the standards by which
government entities conduct their accounting and by which auditors review governmental
accounting. Through 2003, GASB required municipalities to reflect contributed capital in their
audited financial statements. Those rules have since been changed and reporting of contributed
capital is no longer included. However, the City Financial Officer confirmed that the City still
accounts for contributed capital and reported that as of December 31, 2005 the contributed
capital on the books was $1.131 million. More than 95% of the contributed capital came from
State of Alaska grants and the rest is from federal grants. Subtracting the contributed capital
from the above figure brings net book value down to $2,928,823.
' See also Section 5.3.2 of this report and its brief discussion of acquisition adjustments under 2. The Public Interest.
%Commonwenfth Associates, Inc.
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Page 21
3.2.2 Replacement Cost
The replacement cost method of calculating fair market value estimates what it would cost to
rebuild the system from scratch today. Normally, accumulated depreciation is also subtracted
from the replacement cost to determine fair market value. EPS calculated the replacement costs
for the St. Paul electric utility as follows.
Table 7
City of St. Paul Electric Utility
Replacement Costs
Generation
Distribution
Total
Minus Accumulated Depreciation
Repl. Costs Minus Depreciation
Estimated Renlacment Cost
$5,205,000
$4,212,719
$9,417,719
($1, 820,429)
$7,597,290
Details of the replacement cost calculations are included in Appendix 2.
3.2.3 Present Value of Future Cash Flows
This method of calculating fair market value considers the positive annual revenue generated by
an asset and forecasts that revenue into the future. Those revenues represent a stream of future
cash flows. Each cash flow after the first year is then discounted at an appropriate discount rate
to represent that an amount of money in the future is worth something less than the same amount
of money today. These discounted cash flows are then totaled to establish the net present value
of the cash flow stream. The idea behind this method of evaluating fair market value is that an
asset is worth whatever revenue it will produce into the future.
The St. Paul electric utility has generated, on average, a positive operating income of $264,000
per year between 2000 and 2005. This amount was forecast into the future for 30 years and
discounted using a rate of 5%. The resulting present value of the future cash flows generated by
the St. Paul electric utility is $4.3 million. CAI believes that 30 years is a justified term for this
calculation because electric utilities are generally considered to be long-term assets. CAI
believes that any discount rate between 3% and 8% could be justified. CAI has used 5% in this
calculation and has also presented the present value results using different discount rates in Table
9.
C
Commonwealth Associates, Inc.
Page 22
Table 8
St. Paul Electric Utility
Present Value of Future Cash Flows Using 5% Discount Rate
Operating Present
Year Income Value
2007
$264,000
$264,000
2008
$264,000
$251,429
2009
$264,000
$239,456
2010
$264,000
$228,053
2011
$264,000
$217,193
2012
$264,000
$206,851
2013
$264,000
$197,001
2014
$264,000
$187,620
2015
$264,000
$178,686
2016
$264,000
$170,177
2017
$264,000
$162,073
2018
$264,000
$154,355
2019
$264,000
$147,005
2020
$264,000
$140,005
2021
$264,000
$133,338
2022
$264,000
$126,989
2023
$264,000
$120,941
2024
$264,000
$115,182
2025
$264,000
$109,697
2026
$264,000
$104,474
2027
$264,000
$99,499
2028
$264,000
$94,761
2029
$264,000
$90,248
2030
$264,000
$85,951
2031
$264,000
$81,858
2032
$264,000
$77,960
2033
$264,000
$74,248
2034
$264,000
$70,712
2035
$264,000
$67,345
2036
$264,000
$64,138
$7,920,000 $4,261,243
Table 9
Present Value of 30 Year Cash Flows Using Alternative Discount Rates
Discount Rate Present Value
3%
$5,329,572
4%
$4,747,701
5%
$4,261,423
6%
$3,851,950
7%
$3,505,306
8%
$3,209,819
AICDMMOAWCNM Associates, Inc.
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3.2.4 Summary of Fair Market Value Alternatives
Table 10 summarizes the most common methods for establishing fair market value. All of these
methods are reasonable, yet each emphasizes a different perspective. Together, they establish a
reasonable range of fair market value. The ultimate value paid and received by the parties is
normally decided through negotiation.
The net book value method emphasizes the historical, actual cost of developing the electric
utility. It is based on the City's books of account and is therefore highly accurate, however it
tends to undervalue the system because it would cost significantly more to construct the system
today. When contributed capital is subtracted from net book value the result represents what was
actually paid by the City for the system, however, it may still significantly underestimate the
value of the system today.
The replacement cost method looks at what it would cost to build the system today. It uses the
components of the system (wire, transformers, generators, etc.) that exist today, but assumes that
they were all purchased and installed at today's prices rather than the prices at the time they were
actually installed. This method will normally show the highest market value because the entire
system is valued at today's prices.
The present value of future cash flows is an economic evaluation. This method ignores the
accounting costs and only values the net revenue that can be generated from an asset. This
method assumes that the value of an asset is what would be paid for that asset in an open,
competitive market.$ In such a market, the price would normally be slightly less than the total
revenue that the asset would produce over its life. This method is economically sound and may
be a relatively good predictor of market value.
Table 10
Summary of Fair Market Value Alternatives
Net Book Value $4,059,823
Net Book Value Minus Contributed Capital $2,928,823
Replacement Cost Minus Accumulated Depreciation $7,597,290
Present Value of Future Cash Flows $4,261,243
The above values represent a range of possible prices that TDX could pay the City for the
purchase of the electric utility. The actual price paid will ultimately be subject to negotiation.
CAI is not recommending a specific purchase price. Section 6.4.3 of this report includes a more
detailed discussion of purchase price.
8 An open, competitive market, as defined in economics, would be a market with many buyers and sellers where no
one buyer or seller could manipulate the price. Additionally, in such a market all buyers and sellers would have
perfect access to all relevant information. Under this definition, an open, competitive market in the economic sense
seldom exists.
%COnmonweafth Associates, Inc.
Page 24
The City and TDX asked the CAI Team to "evaluate the respective management and operating
expertise of both TDX and City personnel."9 As part of this evaluation, CAI has reviewed the
resumes of employees of each party. Both TDX and the City have many strengths, and CAI
believes that both are qualified to operate and manage their respective electrical utilities.
The City has a number of strengths that make it a highly capable utility operator. These
strengths include a long history of successfully operating the St. Paul utility. This history
includes upgrades to the distribution and generation systems. The City's employees that operate
the diesel generating systems have many years of diesel operation experience. The City's
serviceman also has many years of distribution system experience. In addition, the City has
capable management personnel including the City Manager, City Finance Officer and their staff.
TDX also has strengths that make it a highly capable utility operator. TDX is operating
successful electric utilities at Sand Point and Deadhorse. TDX has been operating Sand Point
since the year 2000 and Deadhorse since 2002. In addition to this corporate experience,
individuals within the TDX organization have significant experience in the utility and power
generation fields. CAI interviewed a small number of people at Sand Point who purchase their
electricity from TDX. These customers reported that service has been good and the power has
not gone out often. When there have been outages, power has been restored quickly. TDX has
experience operating wind turbines on St. Paul Island and this is a plus considering the plan to
install additional turbines. TDX employees also have significant experience designing,
constructing and operating wind generation installations in other locations. Appendix 5 of this
report summarizes this experience. The Staff of the Regulatory Commission of Alaska have
made favorable comments about TDX Power's key management personnel.10
CAI noted earlier in this report its recommendation that TDX, if it takes over the St. Paul electric
utility, increase the number of employees from the three originally planned by TDX to six.
During the course of working on this project, CAI has also discussed with TDX the availability
of John Lyons to provide engineering support to the St. Paul utility and TDX's plans to provide
customer service on the island.
The strength of TDX's engineering capability is centered in John Lyons. He supports the TDX
utilities at Sand Point, Deadhorse and the current POSS Camp installation on St. Paul. If TDX
acquires the entire St. Paul electric utility and installs additional wind turbines for a total of five
turbines, with significantly more controls and interconnection devices, CAI expects the demand
for Mr. Lyons' presence on the island to increase. CAI has questioned whether this might spread
9 Request for Proposals for Independent Assessment of Technical, Economic, Regulatory/Feasibility of Integrating
St. Paul, Alaska Power Plants, City of St. Paul, AK and TDX Power, Inc., July, 2006, page 5. This document is
hereafter referred to as the RFP.
10 In the Staffs evaluation of the application to transfer the certificate for the Sand Point utility to TDX, the Staff
stated at page 5, "The resumes of TDX Power's key management personnel indicate that they have a very strong
background of experience, which will make them fit to operate an electric utility." For more on this statement and
statements by the RCA itself regarding TDX's management capability see Section 5.3.2 of this report.
AjCOnlnronwealth Associates, Inc.
Page 25
Mr. Lyons too thin. Additionally, there is the potential problem of Mr. Lyons being prevented
from getting to the island in a timely manner due to bad weather and resultant flight delays. This
problem might be at least partially corrected by training one of the on -island TDX employees to
have more wind turbine and control trouble -shooting capability so that many problems can be
overcome without Mr. Lyons' presence. This would allow Mr. Lyons to only be on -island for
major issues. CAI also heard similar concerns about the availability of employee back up at the
Sand Point utility.
CAI has also discussed with TDX how it plans to provide customer service on the island. TDX
has stated verbally that it will have personnel on -island to handle customer questions and other
customer service issues. TDX is likely to handle billing and accounting out of Anchorage, but
there will be someone in the community that customers can speak with regarding electric service.
CAI believes it is important for TDX to have an on -island customer service presence.
The RFP issued by the City and TDX asked CAI to "Make a recommendation as to which entity,
the City or TDX, should own and operate the integrated utility."11 CAI interprets the phrase
"integrated utility" to mean a utility using diesel generation and five wind turbines as proposed
by TDX. CAI also interprets this question as specifically referring to a situation where a single
entity both owns and operates the utility. In preparing to answer this question, CAI has
evaluated the current capabilities12 of the City and TDX as shown in the following Table 11.
Table 11
Comparison of City and TDX Capability
(0 = Low, 3 = High)
Category City Capability TDX Capability
Wind Power Operations & Maintenance 0 3
Diesel Generation Operations & Maintenance 3 2
Distribution System Operations & Maintenance 2 3
General Utility Management & Knowledge of St. Paul System 3 3
TDX has seven years experience operating wind turbines on St. Paul Island. In addition, TDX
staff have significant experience with wind power in other locations. Appendix 5 summarizes
this experience. The City has no wind power experience at all. TDX has a clear advantage in
this category.
The City has two employees on -island with many years experience operating diesel generation
and a third with a small amount of experience. The City has additional employees on -island that
have previous experience operating diesel generators but have different positions with the City at
this time. The City is also cross training some of its employees to be able to provide backup to
the diesel generator operators. In addition, the City has a contract engineer off -island. TDX has
excellent diesel experience, but only one of its employees is on -island. Like the City, TDX has
additional off -island experience including employees at Sand Point and Deadhorse and John
Lyons, the TDX engineer. Because the City has more employees on -island with diesel generator
experience, CAI gives the City has a slight edge in this category.
11 RFP, page 5.
12 CAI emphasizes that these are the current capabilities without additional personnel or training of existing
personnel, and without combining the respective systems into a single, integrated utility.
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Both the City and TDX have experience operating distribution systems. The City's experience is
focused in one employee who is on -island and works in this area currently as well as other
employees that currently hold other responsibilities but have previous experience with the
distribution system. The City's contract engineer in Anchorage also compliments the on -island
experience. TDX has one employee on -island with some experience, and multiple employees
off -island with a large amount of experience. The TDX off -island expertise includes the
diversity of experience at other utilities including Sand Point and Deadhorse. CAI gives a slight
edge in this category to TDX.
Both the City and TDX have excellent general utility management experience. This experience
includes multiple utilities in multiple locations. The City's experience is focused in the City
Manager who has managed utilities in other rural Alaskan cities. TDX has multiple employees
with varied experience. This experience itself might give the edge to the TDX; however, it is
also important to consider the knowledge of the St. Paul utility system. The City has a clear
advantage over TDX in knowledge of the St. Paul system. Overall, CAI considers TDX and the
City to be comparable in this category.
In answer to the narrowly -defined question included in the RFP, which envisions a utility
integrating both wind power and diesel generation and which assumes that the same entity must
own and operate the utility, CAI believes that TDX is the most capable of the two entities to
operate such a utility. This judgment is primarily supported by the significant edge that TDX has
over the City in experience operating wind power.
However, the situation described in this question is not the only option on St. Paul Island. CAI
has evaluated a power purchase option where the owner and operator are not the same entity, and
where an "integration" of the respective systems may occur without necessarily selling the City's
electric utility to TDX. CAI has also presented additional options that CAI believes the City and
TDX should consider. These additional options include a phased approach, an option where the
City owns the wind turbines and an option where the City outsources operation of the entire
utility to TDX. These options are described in Section 6 of this report.
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This section of the report reviews state regulatory issues that are associated with a combined
utility. It was prepared by David Johnson Consulting, LLC ("David Johnson").
TDX and the City have posed several distinct regulatory issues, starting with the prospect of
economic regulation if the respective electrical systems on St. Paul Island are integrated. They
then ask about the regulatory process for transferring the City's operating authority (as a public
utility) and whether an application to approve this transfer will be granted. Lastly, they inquire
about the operating decisions that the regulatory agency must approve once the systems are
integrated.
These issues are discussed in more detail later in this section. In brief: Economic regulation is
almost certain if TDX or an affiliate acquires the City's electric utility, and possible if the parties
enter into a power sales agreement in which the owner of the POSS generation facility sells
electric energy to the City. The regulatory process for transferring operating authority is
straightforward at present, but subject to change depending on the outcome of a pending
rulemaking proceeding (R-04-04). No "roadblocks" to approval of this transfer are foreseen at
present if the applicants (1) file an application to transfer the operating authority that is complete
in all respects, and (2) anticipate and discuss (to the regulatory agency's satisfaction) issues that
might appear out of the ordinary or that otherwise might merit explanation, e.g., due to the
transaction terms, the plans for the combined utility, and the situation on St. Paul Island. Finally,
and once an acquisition occurs, the regulatory agency will most likely assume final authority for
overseeing the combined utility's rates and service, under detailed regulations that the agency has
adopted.
5.1 Likelihood of Economic Regulation
TDX and the City have asked whether TDX would be subject to full rate regulation -- also
known as "economic regulation" -- if it owns or operates a combined utility system on St. Paul
Island.
This type of regulation is almost certain if TDX acquires the City's electric utility. If a TDX
affiliate acquires the utility, but TDX operates the combined system (much as TDX now operates
the generation facility at the POSS Camp), then either TDX or its affiliate (but not both) would
likely be subject to economic regulation. But if TDX does not acquire the utility, and the owner
of the POSS facility, Tanadgusix Corporation (Tanadgusix), simply agrees to sell energy to the
City from the facility, then the potential for RCA regulation -- including economic regulation --
would depend on a number of factors.
5.1.1 Overview of Regulation
The State of Alaska has adopted three types of regulation for electric utilities:
1. Exempt from RCA Regulation. A utility that grosses less than $50,000 annually is exempt
altogether from regulation by the Regulatory Commission of Alaska (RCA) unless the utility's
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subscribers petition the RCA for regulation.13 In addition, the RCA may exempt a utility from
all or a portion of the regulation that would normally apply if it decides, on an individual basis,
that the public interest justifies such an exemption.14
2. Certificate of Public Convenience and Necessity — No Economic Regulation. This is a
common form of utility regulation in Alaska.15 The RCA issues a Certificate of Public
Convenience and Necessity (CPCN) to a utility if the agency determines that (1) the utility is fit,
willing, and able to provide utility service, and (2) the service is in the public interest. 16 A
municipal -owned utility requires a CPCN. But such a utility is exempt from economic
regulation unless (1) the municipality's governing body elects to be subject to such regulation, or
(2) the utility competes with another utility other than a telecommunications utility.17 A
privately -owned electric utility that grosses between $50,000 and $500,000 annually (and any
cooperative utility) (1) requires a CPCN, and (2) is subject to economic regulation unless, by a
majority vote of its subscribers or members, the utility elects to exempt itself from such
regulation. 1 8 In all of these cases, the RCA may exempt a utility from all or a portion of the
regulation that would normally apply — including economic regulation -- if the RCA decides, on
an individual basis, that the public interest justifies such an exemption.
3. Certificate of Public Convenience and Necessity — Economic Regulation. Under
economic regulation, the RCA issues a CPCN to the utility and oversees the utility's rates and
service. This is the rule if the utility does not possess a statutory or other exemption from such
regulation.
5.1.2 Acquisition by TDX (or an Affiliate)
The City holds CPCN No. 339 for its electric utility, but is not subject to economic regulation.
This situation would change if the City transfers its CPCN to TDX. In that case, TDX would not
possess the exemption that the City now enjoys as an Alaska municipality.
In this regard, it would not matter if TDX runs the combined utility as a not -for -profit venture, or
if TDX employs a renewable energy technology (i.e., wind generation) to serve the combined
load on St. Paul Island. Nor would it matter that TDX happens to be a subsidiary of a Native -
owned village corporation (Tanadgusix). Rather, TDX's private ownership and the combined
13 Alaska Statutes (AS) 42.05.711(e).
14 AS 42.05.711(d).
15 The RCA's Staff reported in 2004 that 123 electric utilities in Alaska possessed CPCNs. Of these utilities, 29
were subject to economic regulation. See Review of Existing Methodologies & Current RCA Practice, RCA
Sustainability Regulation Workshop (2004).
16 AS 42.05.221; AS 42.05.241.
17 AS 42.05.711(b).
18 AS 42.05.711(f)-(h); AS 42.05.712; 3 Alaska Administrative Code (AAC) 49.010 - 49,100. A privately -owned
electric utility (other than a cooperative utility) that grosses $500,000 or more annually cannot exempt itself from
economic regulation. But the RCA can exempt even a "large" utility from regulation if it decides that the public
interest justifies such an exemption.
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utility's expected gross annual revenues (likely over $500,000) are key -- and would subject
TDX to economic regulation unless the RCA decides that the public interest justifies an
exemption.
If a TDX affiliate acquires the City's electric utility, but TDX operates the integrated system
(much as TDX now operates the generation facility at the POSS Camp), then either TDX or the
affiliate (but not both) would have to acquire the City's CPCN and would be subject to economic
regulation unless the company qualifies for an exemption. A regulated public utility under the
Alaska Statutes includes an entity that owns or operates a system for furnishing electrical service
to the public.19 The RCA's Staff has advised, though, that it is not necessary for the owner and
operator of the same utility system to each acquire a CPCN.20
5.1.3 Power Sale Aereement
In lieu of acquiring the City's electric utility, or as an intermediate step to such an acquisition,
the owner of the POSS generation facility, Tanadgusix, may agree to sell energy to the City that
the facility generates. The Alaska Statutes define the "public" that receives regulated service to
include a utility such as a municipal utility that purchases energy from a wholesale seller for
ultimate re -sale to the utility's customers. A seller to the "public" as so defined may thus qualify
as a public utility under the Alaska Statutes -- in which case (1) the seller would have to obtain a
CPCN to provide wholesale electric utility service, and (2) the agreement between the seller and
the municipal utility would require the RCA's prior approval (as a form of economic regulation
over the agreement's rates and other terms of service). I
But there are other factors that determine the extent of RCA regulation. For example, another
Alaska Statute exempts from regulation "sales, exchanges, or gifts of energy to an electric utility
certificated under this chapter when the energy which is the subject of the sale, exchange or gift
is waste heat, electricity, or other energy which is surplus or the by-product of an industrial
process." The sale of such energy to the City -- a certificated electric utility -- would not, by
itself, cause Tanadgusix to become a regulated public utility that requires a wholesale CPCN.
Nor would the RCA have to approve the sale agreement.22
19 AS 42.05.990(4).
20 Some of the points in this section are based on an informational meeting with the RCA's Staff and two follow-up
telephone conferences. Staff responded to questions and gave helpful advice. It is important to remember, though,
that these discussions were informal in nature and not within the scope of a regulatory proceeding. Nor does Staff
speak for the RCA.
21 AS 42.05.990(3)(C); AS 42.05.431(b) (power sale agreement between two public utilities requires RCA
approval). The standard for RCA approval of a power sale agreement is whether the "rates are just and reasonable,
load forecasts justify the need for the contract, and the contract is the most feasible means of meeting the forecasted
load." See, e.g., In the Matter of the Application of Alaska Electric and Energy Cooperative, Inc. for a Certificate of
Public Convenience and Necessity to Serve as the Wholesale Electric Service (sic) to Homer Electric Association,
Inc., U-01-101(1) at page 6 note 3 (2002).
22 AS 42.05.7110) (a contract for the sale of energy exempt under the statute "does not make the supplier a public
utility"). In early 2005, Tanadgusix offered to sell the City up to 150 KW of so-called "excess energy" from the
POSS facility, conditional upon the sale not causing the seller to become a regulated public utility. Tanadgusix may
have structured its offer in this way to fall under the AS 42.05.7110) exemption that applies to sales of surplus
energy.
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The extent of potential regulation depends on the seller's gross annual revenues under the
thresholds discussed above, e.g., less than $50,000, between $50,000 and $500,000, and more
than $500,000. The RCA Staff has advised that, in determining these thresholds, the RCA
interprets the phrase "gross revenues" to include only those revenues from operations that are
subject, potentially, to RCA oversight. Thus, revenues from power sales to the City would count
towards a particular threshold -- but revenues from Tanadgusix's hotel operations would not,
since the RCA does not have jurisdiction over those operations.
The application of the revenue test can be summarized as follows, assuming that the revenues
include only those revenues from power sales to the City.23 If those revenues are less than
$50,000 on an annual basis, then Tanadgusix would be exempt altogether from RCA regulation
unless it elects to be subject to such regulation in the manner described above. If annual
revenues are between $50,000 and $500,000, then Tanadgusix would require a wholesale CPCN
and would be subject to economic regulation -- in the form of RCA approval of the power sale
agreement -- unless it exempts itself from such regulation in the manner described above. But if
the City purchases most or all of its energy requirements from the POSS facility, then the gross
annual revenues would likely exceed $500,000 — which would subject Tanadgusix to regulation
unless exempted by the RCA.24
5.1.4 Summary — RCA Statements Concerning St Paul Utilities
In summary, the upshot of economic regulation is RCA oversight with respect to a utility's rates
and service. This is not necessarily a bad thing. TDX has indicated that the company is not
averse to the potential for economic regulation on St. Paul Island. As privately -owned
companies, the TDX affiliates that operate electric utilities elsewhere in Alaska — TDX Sand
Point Generating, Inc. and TDX North Slope Generating, Inc. — have recent experience with this
level of regulation.
Further, economic regulation of the electric utility on St. Paul Island (through private ownership)
may cause all of the City's utilities to become more viable and sustainable over the long term.
This assessment is based on recent statements by the RCA and its Staff in a proceeding that
involved the City.
As discussed elsewhere in this report, the revenues that the City now receives from rates for
electric service are available to support other City functions, such as sewer utility service (which
the City provides below cost). The RCA's Staff noted this subsidy when it evaluated the City's
23 Staff advised that the RCA has, on occasion, included revenues from affiliated utilities when determining a
particular revenue threshold. If the RCA did so here, then it could conceivably count revenues from the Sand Point
and Deadhorse utilities towards a revenue threshold on St. Paul Island -- which would make full regulation of a St.
Paul power sale almost certain. The likelihood of such treatment seems remote. Still, it cannot be discounted.
24 The power sale discussion in this section assumes that the generation facility at the POSS camp does not
represent a "qualifying facility" (QF) under PURPA. Other procedures apply to QF sales to Alaska electric utilities.
See 3 AAC 50.750 - 50.820. Although the Energy Policy Act of 2005 removed some of the conditions for QF
eligibility, TDX has indicated that the fuel use at the St. Paul generation facility may still prevent the facility from
qualifying as a QF.
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application to obtain a CPCN for sewer service (U-99-18). Staff stated in its evaluation at 3-4:
"Based upon the financial statements provided, St. Paul subsidizes its sewage operation from
other general fund accounts... St. Paul has a significant amount of money in reserves that will
allow it [the utility operations] to operate at a loss for some time; however it is not indefinitely
sustainable... Staff recommends the Commission advise St. Paul to consider setting their utility
rates at a level that will ensure their long-term viability."
In its Order approving the City's application, the RCA agreed with its Staff that the utility rate
structure on St. Paul Island should be revised to make the Island's utilities more viable over the
long term. The RCA stated: "As St. Paul is not subject to economic regulation under AS
42.05.711(b), we did not review its rates. However, we note that St. Paul's FY02 audited
financial statement indicates that it is operating most of its utilities at a loss. While St. Paul
appears to have the financial resources to bear this burden, it cannot continue to sustain losses
indefinitely. We encourage St. Paul to consider revising the rate structure of its utilities to ensure
their long-term viability."25
Indeed, the City has been increasing the rates of its utilities as the RCA suggested. The City has
additional increases planned and is committed to making all utilities financially sustainable.
5.2 Process for CPCN Transfer
TDX and the City have asked about the process whereby the City would transfer its CPCN to
TDX or a TDX affiliate (as part of a purchase and sale transaction for the City's electric
utility)."
5.2.1 Overview of Process
A CPCN holder and the intended transferee may apply to the RCA for permission to transfer the
certificate. The transfer process is straightforward. The RCA's Web site contains a link to a
transfer application form.27 The application form contains instructional footnotes to assist the
applicant, as well as phone contact information for the RCA at its Anchorage office.
Several categories of information need to be provided as part of a transfer application:
25 In the Matter of the Application by City of Saint Paul for a New Certificate of Public Convenience and Necessity
to Allow it to Operate as a Sewer Public Utility on St. Paul Island, Alaska, U-99-18(2) at pages 2-3 (2003).
26 See AS 42.05.281 (CPCN transfer requires RCA approval). In theory, TDX or its affiliate could ask the RCA to
issue a new CPCN rather than transfer the City's CPCN. But the RCA's Staff has advised that a newly -issued
CPCN could result in competing authority to provide retail electric service on St. Paul Island. The RCA has stated
that such competition is not in the public interest. See In the Matter of Regulations Defining the Future Market
Structure of Alaska's Electric Industry, R-97-10(8) at page 16 (2001) (RCA stated that there was "insufficient
evidence in the record showing that retail electric competition is in the public interest for any area of Alaska").
27 The RCA's Web site also contains a link to an application for "authorization to acquire a controlling interest in a
regulated public utility." The RCA's Staff has advised, however, that if TDX agrees to acquire the City's electric
utility, then the parties need to file only one application with the RCA (the CPCN transfer application).
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1. Certificate Number. This would be CPCN No. 339, which the City holds for its electric
utility operation. (The City would not transfer the CPCNs that it holds for other utility
operations.)
2. Agreement(s) of Transfer. The applicants must file all of the agreements by which the
parties propose to accomplish the CPCN transfer. These agreements would include any
agreement for the purchase and sale of the City's electric utility since, presumably, that
agreement would list the City's CPCN as one of the assets that the City is selling.28
3. Asset and Liabilities Transferred. The applicants need to provide a list that shows all of
the assets and liabilities that they intend to transfer. The assets and liabilities must be classified
in accordance with the uniform utility system of accounts, as discussed in detail in the
application form. The instructional footnotes state that a tentative statement may be furnished
initially with complete data furnished within six months of the effective transfer date.
4. Name of Transferee. The application must identify the transferee's legal status (i.e.,
individual proprietorship, partnership, or corporation); list the date of organization and the
principal office location; and name the state of incorporation if the transferee is a foreign
corporation.
5. Evidence of Transferee's Legal Status. The Certificate of Incorporation, Articles of
Incorporation, and Bylaws need to be provided if the transferee is a corporation. A partnership
must provide a copy of the partnership agreement.
6. Owners of S% or More of Transferee's Equity. These individuals or entities need to be
provided along with their addresses and respective ownership interests. In addition, the
application has to identify all persons who hold an "affiliated interest" as defined in the Alaska
Statutes'29 to the extent not otherwise listed as an ownership interest.
7. Names and Titles of Key Management Personnel. This section of the application must
include a resume of qualifications for each person that is relevant to the conduct of utility
operations. A corporate transferee's "key management personnel" include but are not limited to
all of the transferee's officers.
8. Required Authorizations, Franchises, and Permits. This information does not include
RCA authorizations, but includes all other authorizations by public authorities (including federal)
that are required in order to accomplish the proposed transfer of ownership and ownership rights.
28 Although the purchase and sale agreement needs to be filed as part of the transfer application, the RCA will not
approve the agreement terms themselves. The RCA has stated: "We have authority under various statutes to
approve a change in ownership control of a utility, and to determine the ratemaking effects of a change in ownership
control. But we have no statutory authority to approve per se the terms of a contract for the purchase or sale of a
utility." In the Matter of Alaska Power Company Application to Amend its Certificate of Public Convenience and
Necessity No. 2 to Provide Electric Service to Thorne Bay on the Prince of Wales Island, U-01-98(1) at page 4
(2002) ("Thorne Bay Order").
29 AS 42.05.990(1) defines an affiliated interest.
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9. Public Interest Narrative. The application must include a general narrative statement that
explains why the transfer of the CPCN is in the public interest.
10. Transferee's Proposed Tariff. The proposed tariff must include proposed rates, rules, and
regulations using the RCA's approved format for tariff sheets (sample attached to the application
form).
11. Transferee's Financial Information. An exhibit to the application must include the
transferee's comparative statement of financial information at the beginning and at the end of the
most recent calendar year. The exhibit must also include related comparative statements of
income and undistributed earnings for the years then ended. All financial statements have to
reflect the use of the applicable uniform utility system of accounts. Suggested forms are
available at the RCA office.
12. Transferee's Statement of Proposed Financing Sources. The statement must list the
financing sources for the proposed asset and liability acquisition. The statement has to include
the terms of proposed loans and equipment contracts, and documentary evidence in support
thereof.
5.2.2 Action by RCA
The RCA's Staff will review the transfer application and determine if it is complete. Staff may
ask questions or request more detail. The RCA will then issue an order that either approves the
application (with or without conditions) or rejects the application. A period of 90-120 days
seems to be the norm for final RCA action subject to the press of business on the agency's
calendar.30 This period includes the public comment period.
The above process is the process that the RCA currently follows when it reviews an application
to transfer a CPCN. This process could change in the near future. Pending is a comprehensive
proceeding (R-04-4) in which the RCA is considering, among other issues, whether it should
create a "new rural -oriented regulatory paradigm that responds to regulatory needs for rural
electric, water and wastewater utilities."31 The proceeding has sparked considerable interest
among Alaska utilities.
In a public meeting on September 13, 2006, the RCA indicated that it expects to (1) schedule a
public workshop by early October with R-04-4 stakeholders, (2) present draft regulations at the
RCA's public meeting in late October, and (3) finalize the draft regulations by December 31,
2006. It is not known what action the RCA will take in these regulations. It is conceivable that,
if the RCA does change the "regulatory paradigm" for rural utilities, it could revise the process
whereby a utility such as the City seeks to transfer a CPCN to another entity. The RCA could
30 The RCA took 85 days to process and approve TDX Sand Point Generating, Inc.'s application to acquire the
CPCN for the Sand Point utility (U-00-122). But the RCA acted on that application more quickly than usual since
TDX and the transferor asked the RCA for expedited action. A more likely time estimate is probably the 124 days
that the RCA took to process and approve TDX North Slope Generating, Inc.'s application to acquire the CPCN for
the Deadhorse utility (U-02-70).
31 In the Matter of the Consideration of Changes to the Regulatory Treatment of Grant funded Plant to Attain Long-
term Sustainability Under AS 42.05, R-044(1) at page 16 (2004).
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also take action that affects utility regulation in other ways, including the CPCN requirement and
the extent of economic regulation.
5.3 Likelihood of Favorable Action on CPCN Transfer Application
TDX and the City have asked whether the RCA would approve an application to transfer the
City's CPCN.
This approval appears likely if TDX and the City (1) file all of the information that the
application form requires, and (2) anticipate and discuss (to the RCA's satisfaction) issues that
might appear out of the ordinary or that otherwise merit explanation, e.g., due to the transaction
terms, TDX's plans for the combined utility operation, and the situation on St. Paul Island. The
RCA has approved many transfer applications including two applications by other TDX
affiliates. This history may bode well for TDX and the City if they pursue a transfer.
There is also recent RCA precedent for the sale of a small municipal electric utility, to a private
company. Alaska Power Company ("APC") applied to amend its CPCN after APC's parent
company agreed to acquire the City of Thorne Bay's electric utility. The RCA approved the
application in the Thorne Bay Order that is discussed above. The RCA cited the public support
for the acquisition and the company's plans to significantly reduce customer rates.
5.3.1 Discussions with Staff
After hearing about the St. Paul acquisition alternative during an informal meeting, the RCA's
Staff advised that an application by TDX and the City to transfer the City's CPCN should be
"relatively routine." Staff cautioned, however, that it does not speak for the RCA -- and the
RCA will ultimately decide any transfer application.
Further, Staff advised that the transfer application must be complete in all respects. The RCA
has made this point repeatedly according to Staff. TDX and the City should provide all of the
information that the application form requires. Failure to provide this information could slow the
review process and, potentially, jeopardize the application.
Finally, Staff advised that TDX and the City should anticipate and discuss, in the transfer
application, any issues that might appear out of the ordinary or that otherwise merit explanation.
These issues could arise due to the transaction terms, TDX's plans for the combined utility
system, and the situation on St. Paul Island. Several of these possible issues are discussed below.
5.3.2 The RCA's Test
The Alaska Statutes state that the RCA may only issue a CPCN if it finds that (1) the applicant is
fit, willing, and able to provide the requested utility services, and (2) the services are required for
the convenience and necessity of the public (i.e., the public interest).32 The same 2-part test
applies when the RCA evaluates an application to transfer a utility's CPCN to another entity.
32 AS 42.05.221; AS 42.05.241.
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The Transferee's Qualifications
The first part of the statutory test assesses the transferee's qualifications. Since TDX affiliates
have filed two successful transfer applications in recent years (involving the Sand Point and
Deadhorse acquisitions), the RCA may look to these proceedings as a starting point if it
considers a St. Paul transfer application.
In its evaluation of the transfer application for the Sand Point CPCN, at page 5, Staff stated:
"The resumes of TDX Power's key management personnel indicate that they have a very strong
background of experience, which will make them fit to operate an electric utility. Bruce Levy,
the President and CEO of TDX has 22 years of experience in the design, construction, financing
and operation of power plants worldwide and has developed and put into operation over 800
megawatts of power capacity in eight countries. Several of the other officers of TDX Power are
also officers in Tanadgusix Corporation and have significant experience in the power generation
industry." The RCA reviewed Staffs evaluation and concluded that "TDX is fit, willing, and
able to provide the service [to Sand Point]." 33
The same assessment was made when the RCA and its Staff evaluated the transfer application
for the Deadhorse operation. Staff referred again to Mr. Levy's experience and the experience of
other TDX personnel. The RCA concluded that "TDX is fit, willing, and able to provide the
service [to Deadhorsel.r34
Presumably, TDX would present these statements in support of an application to acquire the
City's CPCN. TDX may also argue that it has acquired additional expertise since its affiliates
took over the Sand Point and Deadhorse utilities. This level of experience -- coupled with the
company's experience with remote wind energy systems — suggests that TDX could capably run
a rural electric utility in Alaska that combines wind and diesel generation. Based on these facts,
TDX would seem to be sufficiently qualified (under the RCA's test) to provide electric utility
service on St. Paul Island.
But a few issues may still exist. In its evaluation in U-00-122 (the Sand Point acquisition), the
RCA's Staff noted at page 5 that TDX's affiliate planned to "retain the current staff from SPEI,
minimizing the learning curve associated with transferring a system." TDX has indicated
recently, that it intends to retain some of the City's electric utility staff. If TDX does not end up
retaining all of the current utility staff in a combined operation, then it would be appropriate for
TDX to discuss in the transfer application why such retention is not necessary. The staffing
issue could be a point of concern given St. Paul Island's remote location and the need (whether
real or perceived) for on -site personnel and management.
33 In the Matter of the Application for Transfer of Certificate of Public Convenience and Necessity No. 230 to
Operate as an Electric Public Utility, from Sand Point Electric, Inc. to TDX Sand Point Generating, Inc., U-00-
122(1) at page 2 (2000).
34 In the Matter of the Application for Transfer of Certificate of Public Convenience and Necessity No. 227 to
Operate as an Electric Public Utility, from Arctic Utilities, Inc. to TDX North Slope Generating, Inc., U-02-70(2) at
page 3 (2002).
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TDX has indicated that John Lyons would assume operational responsibility for the combined
systems on St. Paul Island, and that this responsibility would be in addition to his responsibilities
for the Sand Point and Deadhorse systems. But Mr. Lyons may be "spread too thin" under this
scenario as discussed elsewhere in this report. The RCA could be concerned that TDX's existing
management capability extends only so far -- and that additional capability should be brought in
to assist Mr. Lyons. This issue is worth anticipating and discussing in an application to transfer
the City's CPCN.
The TDX affiliates presented certain plans regarding the Sand Point and Deadhorse utilities
when the transfer applications were filed in U-00-122 and U-02-70. The RCA may want to
know (1) whether those plans were ever accomplished, and (2) whether the same plans will be
implemented on St. Paul Island. For example, the earlier applications stated that the affiliates
would "improve [utility] infrastructure," "change management," "[plan] upgrades," "[adopt]
compliance programs," and so on. TDX should consider discussing these issues in an
application to transfer the City's CPCN.35
The last component of the fitness test goes to TDX's financial qualifications to take over the
combined utility system on St. Paul Island. In this area, the RCA and its Staff typically focus on
the transferee's ownership structure; its assets, liabilities, net income, and available equity; the
purchase price; the amount of net book value that would be transferred; the depreciation history
for the transferred plant; the financing that would fund the acquisition; the proposed tariff terms;
the amount of any acquisition adjustment; and any cost allocation and affiliated interest issues
that may arise.
It is difficult at this time to fully assess TDX's financial qualifications since not all of the terms
for a St. Paul utility acquisition have been decided. Some issues can be identified, however. For
example, Staff referred in its Deadhorse and Sand Point evaluations to Tanadgusix's then -
existing asset/liability and debt/equity ratios. In the Sand Point evaluation, at page 6, Staff
characterized the ratios as "very strong." In a St. Paul transfer application, therefore, it would be
advisable for TDX to discuss the ratios and explain any recent changes to them -- particularly if
the ratios are not as strong as before.
Related to the debt/equity issue, Staff stated in its evaluation of the Sand Point transfer
application, at page 5: "The long term debt of SPEI will be paid off by SPEI after the final close
of the purchase agreement. No liabilities will be carried over from SPEI to TDX." CAI
discusses the issue of debt assumption elsewhere in this report (in Section 6.4.3). If TDX does
assume the City's debt, on either its original terms or revised terms, and the assumption has an
impact on Tanadgusix's debt/equity ratio, then it would be advisable for TDX to discuss those
issues in the transfer application.
35 Other issues appear more unique to the situation on St. Paul Island, e.g., the island's remoteness; the potential for
economic development with a combined system; the degree of popular support for an integrated utility; the use of
wind power generation in a combined system; the effect of a combined system on retail service and rate levels; the
allocation of costs among TDX's various utility operations in Alaska; and the existence of any affiliated interest
concerns. It would be advisable as well to anticipate and discuss these issues in a transfer application.
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2. The Public Interest
The second part of the RCA's 2-part test involves the public interest, i.e., "what does the deal
mean for the customers." To be in the public interest, a transfer (1) should not harm current
customers, (2) should result in reasonable rates for customers, and (3) should provide for
reasonable customer representation.36
The "no harm" standard means that customers should receive at least the same level of customer
service that they received before the transfer. Currently the City is responsible for customer
service. But under a combined operation that is subject to economic regulation, the RCA would
be ultimately responsible for overseeing this service. TDX may consider explaining, in an
application to transfer the City's CPCN, how the residents of St. Paul Island will be no worse off
from such a transfer of ultimate service responsibility.
Electric rates to St. Paul customers should drop if the City sells the utility to TDX. This is a key
issue to address in a transfer application. A proposed rate reduction may influence the RCA
when it evaluates the application.
In the recent Thorne Bay Order, for example, the RCA approved for ratemaking purposes the
transferee's proposed acquisition adjustment to rate base (to reflect the excess of the purchase
price over the net book value). The RCA stated in that Order that it rarely permits such an
adjustment since it requires evidence of "clear, tangible benefits to ratepayers in an amount at
least equal to the acquisition adjustment.i37 In the case of Thorne Bay, however, the transferee
(Alaska Power Company) persuaded the RCA that a projected 22% reduction in monthly electric
rates represented the kind of "clear, tangible benefits" that warranted an adjustment to rate
base.38
The last part of the public interest test requires "reasonable customer representation." It is
possible that the RCA would find sufficient representation if the City's residents become
members of the transferee corporation, or if the residents take seats on the transferee's board.
The RCA could also be influenced by public meetings that TDX and the City hold in advance of
an acquisition (to solicit opinions and feedback). Finally, the RCA may view a public vote on,
36 See, e.g., In the Matter of the Joint Application to Transfer Certificate of Public Convenience and Necessity No.
61 From Teller Power Company, Inc. to Alaska Village Electric Cooperative, Inc., U-04-68(1) (2004).
37 Thorne BayOrder
at pages 4-6; AS 42.05.441(b) (stating that, in determining the value of property for
ratemaking purposes, "the [RCA] shall be guided by acquisition cost or, if lower, the original cost of the property to
the person first devoting it to public service, less accrued depreciation, plus materials and supplies and a reasonable
allowance for cash working capital when required").
38 But rate savings alone do not guarantee an adjustment. In one proceeding, for example, the Alaska Public
Utilities Commission (the RCA's predecessor agency) determined that the applicant's projected rate savings did not
support an acquisition adjustment. See RCA Alaska Communications, Inc., U-78-4(33), 3 APUC 371 (1981)
(adjustment denied despite evidence of $40 million in rate savings). For purposes of potential rate recovery, then,
the issue is not whether the transaction will produce any rate savings, but rather whether the amount of those savings
-- coupled with other benefits to ratepayers -- equals or exceeds the amount of the acquisition adjustment.
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and approval of, an acquisition to transfer the City's electric utility as a positive signal that the St.
Paul community is involved with and supports the acquisition process.3
In summary, there do not appear to be any "roadblocks" at present that would prevent the RCA
from approving a transfer application. TDX and the City must still file a complete application
and discuss all of the issues that are germane to the application. But if the parties do so to the
RCA's satisfaction, then the likelihood of agency approval seems high.
5.4 Operating Decisions That Require RCA Approval
TDX and the City have asked about the operating decisions that would require RCA approval if
the electric facilities on St. Paul Island are integrated.
As discussed in Section 5.1 of this report, the St. Paul facilities would almost certainly become
subject to economic regulation if TDX or an affiliate acquires the City's electric utility. This
means that the RCA would regulate the combined utility's rates and service. Under this level of
regulation, the RCA would have the "final word" over the rates that the combined utility
proposes. This includes the right to suspend or reject the proposed rates.
Regarding service, the RCA has adopted mandatory standards that apply to regulated utilities. If
TDX or an affiliate acquires the City's electric utility, then (1) the RCA's standards would almost
certainly apply to the combined utility, and (2) TDX or the affiliate would be responsible for
managing the combined utility in compliance with these standards.40 The combined utility
would have to obtain RCA approval in the form of a waiver if it wants to deviate from the
required standards.41
5.4.1 RCA Authoritv
The Alaska Statutes authorize the RCA to "make or require just, fair, and reasonable rates,
classifications, regulations, practices, services, and facilities for a [regulated] public utility."
Under this authority, the RCA has adopted certain regulations that apply to utility ratemaking
and service.42
39 In the case of the Thorne Bay acquisition, the City's voters approved the sale of the City's electric utility by a
margin of 89 to 53. The RCA noted this vote in the Thorne Bay Order (at page 4).
4° AS 42.05.291(b) ("subject to the provisions of this chapter and the regulations or orders of the commission, a
public utility may establish reasonable rules and regulations governing the conditions under which it will render
service").
41 3 AAC 52.400(d) ("for good cause shown, the commission will, in its discretion, waive all or any portion of the
standards in 3 AAC 52.400 - 3 AAC 52.500 applicable to an individual electric utility, or establish interim standards
for that utility").
42 See, e.g., AS 42.05.141(a)(3); 3 AAC 48.200 - 48.560 and 3 AAC 52.501 - 52.519 (rate regulation by RCA); 3
AAC 52.400 - 52.500 (service regulation by RCA). This section of the report provides a broad overview of the
RCA's rate and service regulations. The actual regulations are quite detailed. TDX and the City should consult the
regulations directly if questions or concerns arise about a particular issue.
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These regulations do not apply to a municipal utility, however, since it is normally exempt from
economic regulation. A city council may set rates for utility service to the city's residents. The
Alaska Statutes do not limit this right if the city owns the utility."
If TDX or an affiliate acquires the City's electric utility and thereby becomes subject to economic
regulation, then the RCA will assume rate oversight in place of the St. Paul City Council. This
oversight involves a very complex regulatory framework. In brief. Tariff filings must be
submitted to the RCA and made available for public inspection. The proposed tariff must set out
the rates, charges, regulations, terms, and conditions that apply to the service. The regulations
prescribe the form of the filing and the information that must be included with it. The RCA may
suspend or reject the tariff filing.
Regarding service, the RCA has adopted several regulations that apply to utilities subject to
economic regulation. The regulations contain service standards that a regulated utility must
follow unless it first obtains a waiver from the RCA .45 The standards are summarized below.
Again, TDX and the City should consult the regulations directly if questions or concerns arise
about a particular issue.
1. Business office standards. A business office must be located and staffed to provide for
reasonable customer access; other office and contact procedures are specified.
2. Establishment of permanent service. The regulations state a detailed protocol for
establishing permanent service.
3. Establishment of temporary service. A utility may require an applicant for temporary
service to pay the estimated cost of service.
4. Deposit requirements. The regulations state a detailed protocol for receiving and
administering customer deposits.
5. Meter readings. A separate billing is required for each meter; the regulations state a
detailed protocol for meter readings.
6. Billing and collection requirements. The regulations state a detailed billing and
collection protocol.
7. Estimated billings. The regulations contain provisions for estimating bills
43 AS 29.35.070(a) ("the assembly acting for the area outside all cities in the borough and the council acting for the
area in a city may regulate, fix, establish, and charge the rates and charges imposed for a utility service provided to
the municipality or its inhabitants by a utility that is not subject to regulation under AS 42.05..."); AS 29.35.070(c)
("unless the utility is owned by the municipality, all rates, charges, and regulations established under this section
shall be established by ordinance and shall be reasonable and permit a fair return on invested capital").
44 See generally 3 AAC 48.200 - 48.560 and 3 AAC 52.501 - 52.519. This procedure applies to most regulated
utilities. A simplified procedure applies to electric cooperatives. See 3 AAC 48.700 - 48.790.
as See generally 3 AAC 52.501 - 52.519.
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8. Levelized billing. The utility must permit levelized billing.
9. Deferred payment agreements. Deferred payment agreements are authorized with certain
provisions; the utility may not refuse to restore or continue service if such an agreement in place.
10. Discontinuation of service. The regulations state a detailed protocol for discontinuing
service.
11. Line extensions and service connections. The regulations state a detailed connection and
extension protocol.
12. Quality of service. Service must be provided at a steady-state frequency of 60 Hertz with
specified tolerances.
13. Meter measurements, adjusting, and testing. The regulations state a detailed metering
protocol.
14. Engineering standards; energy purchase contracts. The utility must adhere to
engineering standards and to minimum electrical safety standards adopted by the State of Alaska.
15. Maintenance and testing standards. The regulations require a maintenance program.
16. Safety standards for utility plant. The utility must exercise reasonable care and comply
with minimum electrical safety standards adopted by the State of Alaska.
17. Safety standards for interconnecting to QFs and small power producers.
Interconnections are permitted only under NEC and other technical standards.
18. Information to furnish to RCA. The utility must provide the RCA with office and contact
information, outage plans, and reports on any outages and service interruptions.
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6.1 Introduction and Approach
The RFP asked CAI to evaluate how electric rates might change if TDX acquired the electric
utility. CAI was also asked to evaluate rates under a power sale option. This section responds to
those requests. Additionally, this section forecasts rates if nothing changes. This scenario
provides a Base Case against which other scenarios can be evaluated. CAI then proposes some
additional options that TDX and/or the City may wish to consider.
6.2 The Fundamental Assumption
As mentioned earlier in this report, CAI believes that replacing diesel generation with wind
power is a sound idea and one that should be pursued. Wind power brings with it both economic
and environmental advantages. The challenge to the City and TDX at this point is how best to
pursue that good idea.
6.3 Power Cost Equalization
Power Cost Equalization (PCE) is a program under which the State of Alaska pays a portion of
the electric bills for consumers served by utilities participating in the program. Participation in
the PCE program is limited by statute to utilities meeting certain requirements. The RCA sets
the PCE amount (cents/kWh) applicable to each utility participant's billings, regardless of
whether the utility is otherwise subject to economic regulation by the RCA. The PCE amount
varies according to the utility's rates and its costs of producing electricity. The PCE benefit
generally applies to the first 500 kWh that each residential customer purchases each month. In
addition, utilities receive PCE benefits for the power used to serve "community facilities."
Community facility benefits are calculated by allowing 70 kWh per month for each member of
the population. For example, if 400 people live in a community, the serving utility would get
28,000 (400 x 70) kWh per month of PCE benefits for community facilities.
The PCE program is designed to pay 95 percent of the legitimate electric generation costs
between a floor and a ceiling. The floor is set at a level equal to the cost for electricity
generation in urban areas, currently 12 cents per kWh. The ceiling is set at the level of
reasonable maximum cost for a small utility, currently 52.5 cents.
Funds must be appropriated by the legislature each year to support the PCE program. If the
program is fully funded, utilities may receive 95 percent of the difference between their costs and
the floor. The PCE benefits will be reduced if the program is not fully funded.
The following Chart 10 shows the level of legislative funding in recent years.
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100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Chart 10
Annual Average Legislative Funding of PCE Program
98%
88%
2001 2002 2003 2004 2005 2006
Fiscal Year
Source: Statistical Report of the Power Cost Equalization Program Fiscal Year 2005, Alaska Energy Authority
About 79,000 people in 183 communities participated in the PCE program in FY05.
During August of 2006, St. Paul received, for at least a portion of the month, 25.96 cents per
kWh of PCE benefits. The following Table 12 illustrates the calculation of a 500 kWh
residential bill during the period that the 25.96 cent per kWh PCE benefit was in place.
Table 12
Calculation of Sample 500 kWh Residential Bill
(Not Including City or Other Taxes)
$/kwh kWh Monthly Bill
Base Rate $0.4200 500 $210.00
PCE Benefit $0.2596 500 ($129 80)
Net Residential Bill $80.20
The following Chart 11 shows the annual PCE benefits recently received by the City.
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$180,000
$160,000
$140,000
$120,000
$100,000
$80,000
$60,000
$40,000
$20,000
Chart 11
Annual PCE Benefits Received By City of St. Paul
$153
$136,182
2001 2002 2003 2004 2005
Source: St. Paul Historical PCE Data Provided by AIDEA
As part of this report, CAI has attempted to estimate what PCE benefits would be in the case of a
Sale of the Electric Utility and in the Power Sales Option. CAI cautions that these are not exact
estimates and could change significantly as data used in the actual PCE filings is updated by the
City of St. Paul. CAI believes, however, that these estimates provide a ballpark estimate that can
effectively be used in the modeling included in this report. CAI estimates of 2007 PCE benefits
are shown in Table 13 below.
6.3 Base Case Rates
Case
Table 13
Estimated 2007 PCE Benefits
2007 PCE Benefits
Base Case $291,854
Sale of Electric Utility $143,477
Power Sales Option $277,964
This option forecasts what rates will be if no major changes are made to the utility. This
provides a base case against which other options may be compared.
6.3.1 Assumptions
Item
Assumption in this Option
1.
Wind Power
No wind ower included
2.
Diesel Generation
Same as existing
3.
Diesel Fuel Escalation
$2.39/ al in 2005, 18% increase in 2006, 5% in 2007, 3% thereafter
4.
Labor and Adm. Costs
From audited financials escalated into the future at 3%
5.
Debt Service
$98,614 per year per schedule provided by City
6.
PCE
$291,854 escalated at 15% the first year, 4% the second year and 2.5% thereafter.
7.
Load Growth
0% per year
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6.3.2 Results
Using the assumptions shown above, CAI estimated future electric rates. These are shown in the
following chart. The rates shown in this chart and the later charts estimating rates are system
average rates. They are higher than residential rates and lower than commercial rates. CAI was
not asked to estimate individual class (residential, commercial and industrial) rates and to do so
would have required a cost -of -service study and other additional analyses. This chart shows
rates steadily increasing from where they are today. Of course, these rates will be very sensitive
to increases in the price of diesel fuel.
Chart 12
Estimated Base Case System Average Electric Rates After PCE Benefits($/kWh)
$0.50
$0.45
$0.40
$0.35
$0.30
$0.25
$0.20
$0.15
$0.10
$0.05
$-
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
During 2005, residential customers paid $0.14 per kWh for the first 500 kWh per month. This
low rate is a result of the PCE benefits. Data from the charts in Section 1 of this report showed
that the average monthly residential bill in 2005 was $143.63 and that the average monthly
consumption was 586 kWh. Dividing the average bill by the average kWh yields an average rate
of $0.25 per kWh. This average residential rate is $0.10 below the average system rate.
Commercial rates are $0.11 per kWh higher than system average rates. The dashed lines on the
following Chart 13 show what residential and commercial base case rates would be if the same
difference that exists today continued into the future.
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Chart 13
Estimated Base Case System Average, Residential and Commercial Rates After PCE Benefits ($/kWh)
$0.60
$0.55
$0.50
$0.45
$0.40
$0.35
$0.30
$0.25
$0.20
$0.15
$0.10
$0.05
$0.00
Commercial
Residential
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
6.4 Sale of Electric Utility to TDX
6.4.1 Description
This option assumes that some or all electric utility assets and liabilities are sold to TDX
Corporation or one of its affiliates. CAI emphasizes that it is up to the parties which assets and
liabilities are included in the transaction and which are not included. It is assumed that TDX
takes over the job of providing electrical service to all customers on the island and installs wind
turbines to provide much of the electrical generation. The City would be completely out of the
electric utility business.
6.4.2 Potential Benefits of Sale
There are a number of potential benefits of such a sale. These include:
The use of wind power and the resultant reduction in diesel consumption would provide
financial and environmental benefits. The City was recently paying $3.05 per gallon for fuel.
If wind power can cost-effectively reduce the amount of fuel used, the electric rates should
be reduced. Any reduction in diesel consumption will also reduce greenhouse gases and
other potential air pollution. Lastly, a reduction in liquid fuel handling also reduces the risk
of other environmental problems. Questions are occasionally raised about the impacts of
wind turbines on bird populations. Appendix 4 to this report reproduces a portion of a 2005
environmental assessment prepared by TDX that deals with avian impacts. This
environmental assessment concludes there should be no significant negative impacts on birds
from the proposed TDX wind turbines. TDX reports that the US Department of Energy and
the Fish and Wildlife Service have signed off on this environmental assessment.
2. TDX has experience in operating wind generation on St. Paul Island. A sale of the utility to
TDX would take advantage of this experience.
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3. The City's long-term debt associated with the electric utility would be paid off or transferred
to TDX. See Section 6.4.3 for more detail on this issue. CAI is cautious about describing
this as a benefit. If the debt moves off the City books and onto TDX's books, this improves
the City's financial ratios and balance sheet, but may not directly or immediately translate
into lower costs for the citizens. The citizens would still be paying the same debt service, but
they would be paying it through a different entity. However, if the debt is forgiven, or
refinanced at a lower rate or over a longer payment period, this would be beneficial to both
the City as an entity and the citizens of St. Paul who would be paying a lower amount to
service the debt.
6.4.3 Issues To Be Worked Out
CAI has identified the following key issues that need to be addressed by the parties if and when
negotiations proceed for a potential sale of the utility. The fact that there are issues that exist
does not mean the parties should not proceed to negotiate. It simply identifies some of the items
that need to be on the table for discussion and may need to be resolved for agreement to be
reached.
_Electric Utility Long Term Debt
There are two bond issues currently on the City's books that are directly secured by electric
utility revenues. These are referred to as the 1995 and 1997 Junior Lien Bonds. The bonds are
held by the State of Alaska. The combined principal owing on these bonds as of 12/31/2005 is
made up as follows.
Table 14
City of St. Paul Electric Utility Long Term Debt
Issue 12/31/2005 Balance Discount Net Amount Owing
1995 Junior Lien $118,475 -0- $118,475
1997 Junior Lien $1,620,000 $382,184 $1,237,816
Total $1,738,475 $382,184 $1,356,291
Source: 2005 Audited Financials
The current annual debt service on these bonds is approximately $99,000. Because revenues
from the electric utility provide the security for this debt, the official documents related to these
bond issues require that if the utility is sold, the bonds must be paid off. There are certain
options that the parties could consider in dealing with this issue. First, proceeds from the sale of
the electric utility could be used to pay off the debt. Second, it is possible that the debt will be
able to be transferred to TDX and paid off over time. Third, there is the possibility that if the
City and TDX had reached agreement on most other issues and this was the last issue remaining,
that the City and TDX could approach the State about forgiving the debt. CAI has discussed
these options with TDX. TDX has proposed a fourth option whereby TDX would provide the
funds to pay off the City's long-term debt. TDX would then approach the State of Alaska to
refinance the debt in TDX's name. TDX believes that it is reasonable to expect that it will be
able to finance this debt at 0% interest or over an extended life. CAI has checked the feasibility
of this option with the City's bond counsel and counsel has confirmed that such an arrangement
is not out of the question. CAI recommends that the City consider TDX's offer.
The City's Bulk Fuel utility has a Coastal Energy Impact Program loan. While electric utility
revenues do not directly secure this loan, they provide a large portion of the Bulk Fuel Utility
revenues, which are used to pay back the loan. Between 2003 and 2005, internal diesel sales
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(primarily to the electric utility) accounted for an average of 47% (roughly $900,000 of $1.9
million) of the Bulk Fuel Utility's revenue. If the electric utility revenues disappear and the
terms of the loan are not altered, payment of this loan may be jeopardized. The City reports that
the terms of this loan are under negotiation at this time.
Electric Utility Financial Support of Other City Services
The St. Paul electric utility has traditionally generated a positive net operating income. Over the
years 2000 -2005, that operating income has averaged $264,000.
$450,000
$400,000
$350,000
$300,000
$250,000
$200,000
$150,000
$100,000
$50,000
$0
Chart 14
City of St. Paul Electric Utility Operating Income
$395,106
$342,672
$236,931
$201,105 $207,505 $199,109
2000 2001 2002 2003 2004 2005 Average
Source: city of St. Paul Audited Financial Statements
However, other major enterprise funds, which include other City utilities, and the City General
Fund have been operating at a loss.
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Chart 15
2000 — 2005 Average Annual Operating Income of St. Paul Major Enterprise Funds and General Fund
$400,000
$300,000
$200,000
$100,000
$0
($100,000)
($200,000)
($300,000)
($400,000)
($500,000)
($600,000)
91
Electric Water Refuse Bulk Fuel Harbor General Fund
This data indicates that the electric utility is providing positive cash flow that is available to
support other City services. This has been confirmed by the City's external auditor. If the
electric utility is sold, this support is lost and it is possible that taxes, fees, or rates for other City
services would have to be increased to make up for the loss.
How can this support for other City services be maintained if the electric utility is sold? There
are a couple of options. If TDX paid the City a purchase price for the electric utility, that money
could be used to support other City services. Table 11 shows the amount of principal that would
be required to produce $264,000 annually at various interest rates.
Table 15
Investment Required to Produce $264,000 Per Year At Various Interest Rates
Annual Interest Rate Investment Earnings
4%
$6,600,000
$264,000
5%
$5,280,000
$264,000
6%
$4,400,000
$264,000
7%
$3,771,429
$264,000
8%
$3,300,000
$264,000
There is another option to consider. As of December 31, 2005, the City's electric utility balance
sheet showed $5.2 million of current assets, of which $4.8 million was cash and investments. If
the electric utility was sold, but the current assets stayed with the City, this amount could be
invested and used to produce annual income to support other City services. This would go a long
way to meeting the needs of the other City utilities. This option leads into the following
discussion of purchase price.
Purchase Price
Whenever an asset is sold, it is reasonable for the seller to receive an acquisition price from the
buyer. This is true in the case of a possible sale of the City's electric utility to TDX. Section 3.2
C
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of this report calculated a range of fair market values that could be used to establish a purchase
price. That range went from a low of $2.9 million to a high of $7.6 million. It may also be
important to consider that a purchase price paid by TDX, and approved for inclusion in TDX's
retail rates by the RCA, will end up being paid by the St. Paul ratepayers.
In this case, in lieu of a purchase price, CAI recommends that the parties consider the following
option (introduced immediately above and described more fully here). The City's electric utility
has current assets of $5.2 million. It is reasonable that a sale of the electric utility would include
transfer of these assets. However, that does not have to be the case. Instead, TDX could
purchase the utility and leave the current assets with the City in lieu of a purchase price. This
would provide the City with a value for the utility that is within the range of fair market values
calculated earlier. In addition, it would provide the City with an amount of money that could be
invested to earn a return that would assist in financially supporting other City utilities.
Ultimately, this must be negotiated and agreed to by the parties, but CAI would put this option
forward for consideration.
Employees
There are currently four City employees whose time is primarily dedicated to the electric utility.
This includes three power plant employees and one serviceman. If the electric utility is sold, it is
important to consider what happens to these employees. TDX has confirmed its willingness to
hire these employees. This arrangement should be finalized as part of any negotiation.
Some or all of these employees were previously part of a federal pension program. TDX has
reported that there should be no effect on the employees' federal pensions if they went to work
for TDX. Again, this is something that should be decided in negotiation.
Credit and Collection Impacts
The City currently sends its customers one bill that covers all utility services including water,
refuse, sewer and electricity. If a customer does not pay a bill, the City has the ability, after
exhausting other options, of disconnecting the customer's power for non-payment. This is a
strong incentive for customers to pay their bills. If the electric utility is sold, the City would no
longer have the option of cutting off the electricity, and collection of bills may be more difficult.
There are other options available to the City to disconnect water service to a non-paying
customer, but these options may have costs associated with them.
Capital Investment
Section 2 of this report described the significant capital investment that would be required to
install the necessary controls and other interconnection equipment if the electric utility is sold
and wind turbines are used to generate a large amount of power.
_Complex Transaction
A sale of the electric utility to TDX would be a complex transaction, which may require the
payment of significant transaction costs, including attorney and consultant fees. This should be
discussed in negotiation.
%COMMORWeKM
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Plan For Providing On -Island Customer Service Operating Expertise and Employee Backup
This issue was discussed in Section 4 of this report. As part of their negotiation, CAI would
encourage the parties to decide how TDX would provide the required on -island customer service
and operating expertise to maintain high reliability and customer satisfaction.
Governance and Corporate Structure Issues
Some of the issues listed in this section may be resolvable by TDX Corporation forming a new
subsidiary to run the St. Paul utility. CAI would recommend that the parties consider such an
option and that the new subsidiary have a non -compensated board of directors may up entirely of
island residents. A strong governance plan is important because this may be the primary means
of enforcing contractual provisions agreed to between the parties. TDX has expressed
willingness to consider such an option and has formed similar separate entities to operate the
Sand Point and Deadhorse utilities.
Rate o Return
TDX stated in its proposal that it plans to earn a zero rate of return. The point here is that there
would be no net income produced beyond what is required to operate the utility and set aside
prudent reserves for replacements and new construction. In other words, a profit would not be
generated that would go back to the TDX Corporation or its shareholders. The issue is how
would a zero rate of return be enforced? It is possible that the proposed local board of directors
would be the best enforcement for this provision. An additional method of enforcement is to
include appropriate provisions in the corporate documents such as bylaws. CAI believes the goal
of the TDX proposal in this regard is appropriate. The challenge is how best to implement and
that is an issue appropriate for negotiation between the parties.
TDX Power Management Fee
The models that TDX used to estimate rates assumed that the entity operating the St. Paul
electric utility would pay a $150,000 per year management fee to TDX Power. The purpose of
this fee was to cover services provided by TDX Power to the utility such as billing, accounting,
engineering and financial management. TDX has agreed to CAI's recommendation to increase
the assumed TDX employees from three to five. TDX has volunteered that, in this situation, the
management fee is no longer necessary.
6.4.4 Retail Rate Proiections
CAI started with the TDX rate projection model and made changes to it as CAI believed
appropriate. This model was then used to project retail electric rates if TDX were to acquire the
electric utility and install additional wind turbines. As with any model, the output is highly
sensitive to the inputs and the assumptions.46 The next section reviews the key assumptions and
changes CAI made to the TDX model.
46 The rates estimated here are average annual rates for the entire utility. A cost -of -service analysis has not been
performed and the rates have not been estimated for each individual class or customers. Additionally, whatever
rates TDX would charge would ultimately have to be approved by the RCA. These estimates are not an effort to
predict RCA decisions.
AICOA MORWeafth Associates, Inc.
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Assumptions
Table 16
Sale of Electric Utility Option
MAAA Acc..+i....�
TDX
CAI Modification
Item
Assumption
1. Wind Power
5 wind turbines generate nearly 4.8 million CAI has reviewed the TDX assumptions
kWh regarding wind output and believes them to
be reasonable. No changes were made.
2. Diesel
Diesel consumption is reduced to 210,291 No change
Generation
gallons generating 3.0 million kWh
3. Diesel Fuel
$2.39/gal in 2005, 18% increase in 2006,
No change
Escalation
5% in 2007, 3% thereafter
4. Labor and Adm.
3 employees plus $200,090 for Office and
TDX has agreed to CAI recommendation to
Costs
Adm in 2007.
increase employees to 5. No change to
O&A.
5. Debt Service on
-0-
TDX has proposed to pay off the City debt
City Long Term
and refinance with an AEA loan for 20
Debt
years at 0%. CAI accepts this proposal and
has included it in the model.
6. PCE
Not included.
$143,477
7. Load Growth
0% per year
No change
8. TDX Power
$150,000 per year
Eliminated per TDX recommendation
M mt. Fee
9. TDX Operating
Starts around $100,000 and grows.
CAI left this in the model because some net
Margin
revenue will be needed to build reserves for
replacements and capital improvements.
10. Capital Costs
TDX "donated" 3 turbines and borrowed
CAI added a 20% contingency on the
from AEA for 20 years at 0% for the last
interconnection and controls costs and
two turbines. The debt service on this AEA
included the cost of an electric boiler which
loan is included in the model. Additionally,
had inadvertently been left out of the TDX
there are capital costs for interconnection,
model.
new controls and replacement diesel units.
These are borrowed from AEA at 0% for
20 years.
11. Purchase Price
No purchase price assumed.
CAI did not include a purchase price, but
does assume that the existing City electric
utility current assets will be left with the
12. Thermal
TDX assumes $137,669 in 2007
No Change
Revenue
In their model, TDX assumed that during many hours of the year the wind turbines will generate
more power than is needed by the community. That excess energy is used to power electric
boilers. The hot water from those boilers is sold to customers within the community primarily
for heating. TDX assumed that these hot water sales brought in $137,669 of "Thermal Revenue"
in 2007. CAI believes this a reasonable assumption at this point in the modeling and has not
made any changes in this area.
C
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Results
$0.50
$0.45
$0.40
$0.35
$0.30
$0.25
$0.20
$0.15
$0.10
$0.05
Chart 16
Sale of Electric Utility Option
Estimated System Average Electric Rates ($/kWh)
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
— Base Case Rates With PCE Benefits
TDX Original Proposal
[;�TDX
Original Proposal with CAI Modifications
The above chart shows that rates under the TDX proposal, without the changes suggested by
CAI, are significantly lower than rates under the Base Case. When the CAI changes are
included, rates are even a small amount lower than the TDX proposal. The primary reason that
rates are lower in these cases is that use of wind power reduces the use of diesel fuel. Less fuel
burned translates directly to lower rates. Additionally, the CAI changes include PCE benefits
which were not included in the TDX proposal.
The primary components that make up the electric rates modeled are shown in the following
table.
Table 17
Components of Projected System Average Rates ($/kWh)
TDX with CAI
Item
City
Changes
Fuel and Utilities
$0.268
$0.112
PCE
($0.065)
($0.032)
Personnel, Operating, & Adminstrative
$0.159
$0.114
Debt Service
$0.018
$0.042
Non -Operating Revenue
0.016
0.000
Total Average Retail Rate
$0.364
$0.236
AiCOUMMaweakh Associates, loc.
Page 53
6.4.5 Recommended Process for Moving Ahead
The St. Paul electric utility is an asset of the City. Many states have specific state laws that
dictate the process for a municipality to sell or otherwise dispose of assets. The State of Alaska
has no such laws. It is up to the City to develop its own process as it sees fit.
CAI recommends that if the City wants to proceed to negotiation with TDX to sell the electric
utility, that the City also adopt an ordinance describing the process the City will use to sell the
assets. CAI recommends that this process include public meetings and a public vote before the
utility is sold.
6.5 Power Sale Option
6.5.1 Description
Under the power sale option, the City would purchase wind power from TDX. The City would
continue to run the electric utility and serve retail customers. TDX would continue to own,
operate and maintain the wind turbines at POSS Camp and would sell a major portion of the
power produced by these turbines to the City. This option would likely bring TDX under rate
regulation of the RCA (see Section 5.1.3 of this report for more detail).
There have been frequent discussions between the City and TDX regarding a power sale. At
different times, each party has drafted documents. These discussions have never been
concluded, and to some extent, resulted in the RFP that requested this report. That RFP makes it
clear that both the City and TDX are interested in having CAI analyze a power sale option. CAI
has conducted such an analysis and the results are reported here.
6.5.2 Potential Benefits of A Power Sale Option
A power sale option would be a simpler transaction in most respects. This is not to say it would
be a simple transaction, just that it is easier to put together than a sale of the utility. A power sale
would not have to deal with issues such as long term debt, the electric utility contribution to
other City services, employees, and all the operating costs of TDX. Additionally, a power sale
may provide a positive initial transaction between the City and TDX that can be used as a
foundation for later negotiation of a sale of the utility, provided both parties end up being
satisfied with the power sale and desire to proceed towards a sale of the utility.
6.5.3 Issues to be Worked Out
Control and Infrastructure Upgrades
For the City to purchase wind power from TDX and integrate it with its diesel generation will
still require upgrades to the interconnection between TDX and the City and new controls to be
put in place. CAI has assumed that the wind generation sold by TDX to the City under this
option will be the same amount of wind power that would be produced if TDX acquired the
entire utility. Consequently, the controls and interconnection costs are the same. Who will pay
for these costs would be a key issue in the negotiation of a power purchase agreement.
%Cenmonweafth Associates, Inc.
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Operating Protocol and Scheduling Provisions
The parties will need to agree on how and when power will be scheduled. This will include
issues such as how much .warning is required before changing the amount of power being
delivered. Since wind power is a highly variable resource, changes may be virtually
instantaneous thereby requiring real-time adjustments. Metering, points of delivery, losses and
other issues will need to be worked out.
Power Sales Price
Of course, the price for the power purchase would have to be negotiated. As explained below,
CAI has assumed a cost -based price in its modeling of the power sale option. All of these details
would have to be negotiated.
Negative Impact on PCE
If the City purchases wind power from TDX, it will affect the City's PCE benefits in two
primary ways. First, PCE benefits will be reduced (from the Base Case option) due to the
reduction in fuel cost. A purchase of wind power would mean the City burns less diesel fuel
thereby lowering the costs that go into the PCE calculation. Counterbalancing this effect,
however, will be the inclusion of purchased power costs. The City could include in its PCE
calculation the cost of purchasing the wind power from TDX. Depending on the price paid for
the wind power, as long as it is higher than 12 cents per kWh (and CAI assumes that it will be)
this would mitigate the reduction of PCE benefits due to burning less diesel. The net result is
that PCE benefits under the Power Sale Option are lower than under the Base Case option and
higher than they would be under the Sale of the Electric Utility to TDX option. It is important to
note that the PCE benefits described here are included in the retail rates projected below. Even
though PCE benefits in the Power Sale option are less than the Base Case, retail rates are still
lower in the Power Sale option than they are in the Base Case.
6.5.4 Retail Rate Proiections
Assumptions
TDX did not specifically model a power sale option so there was no model to review. To
estimate retail rates under this option, CAI used data from the TDX model plus its own
assumptions.
%COnubonwenfth
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Table 18
Power Sale Option
Mndnl Secmmntinnc
CAI
Item
Assumption
L
Wind Power
5 wind turbines are constructed by TDX. Roughly, 2.5 million kWh of wind power are sold
to the City annually.
2.
Diesel
Diesel consumption is reduced to 210,291 gallons generating 3.0 million kWh
Generation
3.
Diesel Fuel
$2.39 in 2005, 18% increase in 2006, 5% in 2007, 3% thereafter
Escalation
4.
TDX Labor and
3 employees plus $197,000 for Office and Adm.
Adm. Costs
5.
Debt Service on
City continues to pay. No change from base case.
City Long Term
Debt
6.
PCE
$277,964 in 2007 then escalated.
7.
Load Growth
0% per year
8.
TDX Power
$150,000 per year to cover accounting, billing and regulation, etc.
M mt. Fee
9.
TDX Operating
Since it is a power sale option no operating margin is included. It is assumed the power is
Margin
sold by TDX to the City at cost.
10.
Capital Costs
TDX "donates" 3 turbines and borrows from AEA for 20 years at 0% for the last two
turbines. The debt service on this AEA loan is included in the model. This option assumes
that the City borrows the nearly $2.6 million for controls and interconnection at 0% over 20
ears. These costs are included in the Ci 's rates.
11.
Purchase Price
There is no sale of the electric utility in this option.
for Electric
utility
12.
Thermal
No thermal revenue included.
Revenue
13.
Power Sales
The above assumptions result in a price for wind power charged by TDX to the City of
Price Charged
$0.143/kWh in 2007.
to City by TDX
for Wind Power
Sales
Results
$0.50
$0.45
$0.40
$0.35
$0.30
$0.25
$0.20
$0.15
$0.10
$0.05
Chart 17
Power Sale Option
Estimated System Average Electric Rates ($/kWh)
2006 2007 2008 2009 2010 2011 2012 2013 2014
f�BaseCa-se Rates With PCE Benefits f- TDX Original Proposal
fginal Proposal with CAI Modifications --X Power Purchase Option
jcommonwealth Associates, Inc.
2015 2016
Page 56
Table 19
Components of Projected System Average Rates ($/kWh) in 2007
TDX with CAI Power Sale
Item
City
Changes
Option
Fuel and Utilities
$0.268
$0.112
$0.195
PCE
($0.065)
($0.032)
($0.062)
Personnel, Operating, & Adminstrative
$0.159
$0.114
$0.159
Debt Service
$0.018
$0.042
$0.039
Non -Operating Revenue
$0.016
$0.000
$0.016
Total Average Retail Rate
$0.364
$0.236
$0.315
As the above chart and table illustrates, retail rates are higher in the power sale option than the
option where TDX acquires the utility. There are several reasons for this. The first is that in the
Sale of the Electric Utility case, it is assumed that TDX receives revenues from the sales of
thermal energy to the elder care facility and other possible users of hot water. In that case, those
revenues reduce the amount of costs that must be covered by electric rates. In the power sales
case, no thermal revenues are assumed because TDX would not have facilities in town in order
to provide hot water. Secondly, in the Power Sales case and in the Base Case, the electric rates
are assumed to raise sufficient revenue to provide $264,000 of revenue for the electric utility that
can be used to support other City services. This pushes the rates up in these two cases. This is
not required in the Sale of the Electric Utility case because in that case, the $264,000 is not
raised through electric rates but rather as income on the investment of the current assets left with
the City if TDX takes over the utility.
The result is that the option with the lowest retail rates is the Sale of the Electric Utility case, the
next is the Power Sales case and the highest rates are in the Base Case.
6.5.5 Recommended Process for Moving Ahead
The process for moving ahead in this option is much the same as in the Sale of the Electric
Utility case. However, a public vote is probably less important in this option because the City is
not disposing of assets. CAI would still recommend public meetings to hear the public's
thoughts about the City purchasing wind power from TDX.
CAI has estimated the cost for TDX to produce wind power and has assumed that cost to be the
sales price for sales of wind power to the City. Of course, this number will eventually be
determined by negotiation.
6.6 Phased Approach
6.6.1 Description
In the RFP issued by the City and TDX, CAI was asked to evaluate the above Sale of the Electric
Utility to TDX case and the Power Sales case. CAI also volunteered to propose some other
options for consideration by the City and TDX. These are only proposals that are briefly
AiCommonwealth Associates, Inc.
Page 57
sketched out in this report. CAI has not estimated retail rates under these options. The first of
these additional options is the Phased Approach.
Under the Phased Approach, the City and TDX would negotiate and execute a power sales
agreement as an agreed upon first step towards the more complicated negotiation to sell the
electric utility to TDX. In this case, the power sale could be very simple and very small. The
purpose would be to demonstrate the ability to come to agreement and to demonstrate the
viability of wind power and of transferring it between TDX and the City.
6.6.2 Potential Benefits of the Phased Approach
If the simple power sale is successful, the negotiation of the sale of the electric utility may be
easier to accomplish. There would be the foundation of a successful power sales agreement on
which to build. Additionally, a small power sale could be accomplished with much less capital
investment. It could be transported over the existing feeders and would not need the
sophisticated controls that a larger sale would require. Of course, because it is a much smaller
amount of power, the reduction in electric rates would be much less.
6.6.3 Issues to Be Worked Out
One of the things to consider is whether negotiating a small power sale first would actually speed
up the eventual negotiation of a power sale or delay it. If the negotiation of the power sale
dragged on, it is possible it would eventually hinder the larger negotiation rather than assist it.
This option is only beneficial if the initial power sale actually makes it easier to get to agreement
on the larger negotiation.
Another issue to consider is whether TDX would be subject to rate regulation by the RCA as a
result of even a small power sale. The initial threshold for regulation is $50,000 of gross revenue
per year. If the power sale exceeded that amount, and if TDX is not exempted from rate
regulation, then TDX would likely incur the potential cost of being rate regulated by the RCA.
6.7 TDX Sells Wind Turbines To the City
6.7.1 Description
This is another of the additional options that CAI proposes for consideration. Under this option,
TDX would sell the existing wind turbines to the City. The City would own the turbines and
build the interconnection and control equipment required to use the wind power to serve
customers. CAI recommends in this option that the City hire TDX to operate and maintain the
wind turbines.
6.7.2 TDX Invested Capital
If the city was to purchase the TDX wind turbine, it would be helpful to know the amount of
capital TDX has invested in the equipment. CAI requested this information and received the
information included in the following Table 20.
%COMMORWealth
Associates, Inc.
Page 58
Table 20
TDX Invested and Contributed Capital
Capital
TDX Capital From Grants Total
Phase 1 $ 895,000 $ 895,000
Phase 2 $ 1,000,300 $ 860,000 $ 1,860,300
Upgrades $ 100,000 $ 100,000
$ 1,995,300 $ 860,000 $ 2,855,300
70% 30% 100%
6.7.3 Potential Benefits
This option would be yet another way to get access to wind power. That is always the bottom
line benefit to any of these options. Wind power should be always be less expensive and is
certainly cleaner than burning diesel. This option should also be simpler than a sale of the
electric utility. There are fewer assets being transferred, no City long term debt to deal with and
the City can continue to use electric utility revenues to support other City services if it desires to
do so. This option may also result in lower rates to customers.
6.7.4 Issues to be Worked Out
The primary issues to be worked out in this option are:
• What assets are sold and what is the sales price?
• How much wind power would actually be produced?
• Who would operate the turbines and if TDX does so, what would they be paid?
6.8 City Keeps Electric Utility But Outsources the Operation of the Utility to
TDX
6.8.1 Description
Under this option, the City would continue to own the electric utility. However, the City would
outsource the entire operation of the utility to TDX. The City electric utility employees would
now work for TDX. TDX would install and operate and maintain wind turbines and use the
power to serve customers. Either the City or TDX would upgrade the controls and
interconnection as required to use the wind power. One way of thinking about this option is that
the City still owns the utility, but has hired TDX to operate every aspect of it.
6.8.2 Potential Benefits
This option is another way to access the benefits of wind power without the difficulty inherent in
a major asset sale. The other advantage to this option is the outsourcing agreement would not
have to be permanent. If either the City or TDX was not satisfied with the arrangement at the
end of its term, things could go back to the way they are today.
6.8.3 Issues to Be Worked Out
Implementation of this option would require the parties to agree on:
• What is the term of the outsourcing contract?
C
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• What are the fees paid to TDX by the City for operating the utility?
• How can the employees transfer from one entity to another seamlessly and with the least
amount of upheaval?
• Who pays the cost of the required upgrades?
• How is operational effectiveness measured? Are there incentives for good performance?
%ComwonweaM Associates, Inc.
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Last Name First Name Company
Arbor Steve Trident Reafnndc
Baird
Ron
Lawyer
Baker
Pat
Tribal Government
Blizzard
Richard
National Weather Service
Bost
John
Mikunda, Cottrell & Co.
Bourdukofsky
Jason
City Council
Cheatham
Jane
TDX Corp
Chertkow
Bruce
AIDEA
Crimp
Peter
AIDEA
Fratis
Greg
City Council
Godbehere
Denise
Sand Point Resident
Goodman
Nick
TDX Power
Harper
Terri
AIDEA
Keen
James
RCA Utility Engineer
Kochutin
Rodion
City Power Plant
Kraft
Barbara
Davis, Wright, Tremaine
Krukoff
Neon
City Power Plant
Lawrence
David
RCA Administrative Law Judge
Lestenkof
Sherry
City Finance Officer
Levy
Bruce
TDX Power
Lyons
John
TDX Power
Mata-Rukovishnikof
Jessica
St. Paul Health Center
Melovidov
Robert
Tribal Government, TDX Board
Melovidov
John W.
City Power Plant
Melovidov
Wanda
City Accountant
Melovidov
Paul
TDX Power
Melovidov
Myron
City Council
Merculief
Jacob
City Lineman
Newman
Nora
Sand Point Resident
Philemonoff
Ron
TDX Corp.
Polvado
Colman, Cmdr.
Coast Guard Station
Ross
Elisabeth
Birch, Horton, Bittner
Senisch
Steve
City Council
Shane I
Julie
TDX Corp.
Shoemaker
Joe
Sand Point Resident
Snow
Linda
City Manager
Stacks
Jamie
Pribilof Island School District
Strandberg
James
AIDEA
Swetzof
Ph His
City Clerk
Swetzof
Simeon
Ct Council
Uhlenkott
Loren
Honchen & Uhlenkott, Inc.
%COMMGnWMM Associates, Inc.
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Page 61
Wellman
Ted
Davis, Wright, Tremaine
Young
Bob
Alaska Commercial Company
Zacharof
Mike
City Council
Zavadil
Phil
City Council
%COnmwnwe<b Associates, Inc.
Page 62
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Appendix 4 — Avian Impacts
low
i
,m X
1
Plate 3-7. Part ojthe island's reindeer herd
(picture taken Ane 2002).
BIRDS
Alaska field biologist and ornithologist
Declan Troy performed an onsite
survey of the project and surrounding
area during a field trip to St. Paul
Island in August 2003.
Existing Environment
Spectacled Eider has occurred in the
Pribilof Islands during winter;
however, Saint Paul is well south of
the southern limit (61 ON) of the
normal winter range (Petersen et al.
2000). Steller's Eider occurs more
regularly in small numbers, primarily
during the winter. Most or all of these
are likely of the Russian breeding
population. It is unknown if any
Alaska breeding Steller's Eiders (i.e.,
members of the listed population) are
present. Most of the world's Steller's
Eiders migrate through the Bering
Sea but generally stay close to the
Alaska Peninsula, Bristol Bay, and
along the eastem coast (Lamed
2003). Neither of these species
would be expected in the project area
as no water bodies are present at the
project site and both species are
3-13
%ConmwnweaRb Associates, Inc.
s+�i�etTM.a=.sn.rans.wi..w�c,:., rummer„
Chapter 3
Existing Environment and Environmental Effects
largely restricted to marine waters
during the periods when they might
occur around St. Paul Island.
St. Paul Island is renowned for its
seabird populations. Most bird
colonies are restricted to the coastal
fringe, in particular where cliffs
provide nesting sites for seabirds.
Inland sites on St. Paul Island have a
depauperate avifauna.
The most common terrestrial birds
breeding on Saint Paul are Rock
Sandpiper (Calidris ptilocnemis),
Lapland Longspur (Calcarius
lapponicus), Snow Bunting
(Plectrophenax nivalis), and Gray -
crowned Rosy Finch (Leucosticte
tephrocotis). The local populations of
Rock Sandpiper (Calidris p.
ptilocnemis) and Grey -crowned Rosy
Finch (Leucosticte tephrocotis
umbrina) are of interest due to their
rather restricted distributions. This
subspecies of Rosy Finch (breeds
only on Bering Sea islands of the
Pribilof and St. Matthews groups and
in the Aleutians.
Plate 3-8. Rosr finch.
Page 68
The breeding range of Rock
Sandpiper is restricted to the Pribilof
and St. Matthew groups and St.
Lawrence Island. Rosy Finches on
Saint Paul breed primarily near cliffs
and human habitation (Hanna 1922)
so are unlikely to nest on the project
site (but do occur around the facilities
at the airport). The highest densities
of breeding Rock Sandpipers occur in
the drier upland portions of the island
(Hanna 1921) but it does occur in
Lowland Forb Tundra such as around
the project site), at least early in the
summer before the vegetation
becomes too rank (Lee Tibbitts
USGS, personal communication).
The most likely breeding species
around the project site are expected
to be Lapland Longspur and perhaps
Rock Sandpiper. Additional species
such Snow Bunting (Plectrophenax
nivalis) and Gray -crowned Rosy
Finch (Leucosticte tephrocotis) would
be expected where the tundra has
been disturbed, such as along access
roads and near existing facilities
especially post -breeding.
No aggregations of birds are known
to occur nor are expected at the
project site. The nearest
concentrations are found on
freshwater ponds approximately 1 km
SE of the proposed turbine sites.
Gulls primarily Black -legged
Kittiwakes (Rissa tridactyla) and
Glaucous -winged Gulls (Larus
glaucesens) loaf in these ponds. Most
movement of these birds appears to
3-14
%Counnonweafth Associates, Inc.
sv�irren.r— _'' -- .cr+rucs�,n taarkr..
Chapter 3
Existing Environment and Environmental Effects
be directly between the coast and the
ponds and is not thought to occur
trough the project areas. A landfill
that was located approximately 1 km
from the project site is being
relocated to another location on the
island. Incineration minimizes the
availability of food at the project site;
consequently, it is not an attractant to
gulls.
Environmental Effects
Only low numbers of waterfowl have
been reported among fatalities at
wind farms (Erickson et al_ 2002).
This may reflect the location of
turbines in habitat little used by
waterfowl; however, Dirksen et al.
2000 found that diving ducks (mostly
Aythya spp.) appear to detect and
avoid wind turbines, even at night,
showing avoidance responses 100-
200 from the turbines. Some
mortality of Common Eiders
(Somateria mollissima) occurred at a
coastal wind farm in England (c.f.
Lowther 2000). Given the low
number of Spectacled and Steller's
eiders around Saint Paul Island and
the absence of suitable habitat near
the proposed turbines, impacts of the
project on these species is expected
to be negligible.
Wind turbines are perceived as
posing risks to birds. Indeed, poorly
sited wind farms have resulted in
substantial bird mortality. In
particular, several hundred raptors
are killed each year at a wind farm in
Page 69
Altamont Pass, California (Hunt
2002). Substantial raptor mortality
has also been recorded at a wind
farm in Spain near Gibraltar (c.f.
Lowther 2000). These installations
have proved the exception in terms of
the prevalence of raptors amongst
fatalities. At most sites, raptor
mortality at wind turbines is relatively
infrequent. Monitoring at many
installations indicates that wind
turbines result in the deaths of 1-3
birds/turbine/year (e.g., Erickson et
al. 2003, Johnson et al. 2002, 2003;
Thelander and Rugge 2001, Young et
al. 2003). Combining studies yields
an overall average of 2.19
birds/turbine/year including 0.033
raptors/turbine/year fatalities
(Erickson et al. 2001). Excluding
Califomia these averages are
reduced to 1.83 birds including 0.006
raptors/turbine/year.
Although examples of mortality
events involving of most groups of
birds are known, passerines comprise
over 80% of reported fatalities
(Erickson et al. 2001) and
approximately half of these involve
nocturnal migrants. Risks of bird
strikes increase in areas with large
numbers of raptors or large numbers
of nocturnal migrants. Raptors occur
infrequently in the Pribilof Islands.
Passerines are probably the most
numerous birds at the project site but
large numbers of nocturnal migrants
are not expected. Situations
conducive to bird strikes include:
3-15
Chapter 3
Existing Environment and Environmental Effects
• Movement corridors
Birds often concentrate along linear
features such as coasts, rivers, and
ridges especially during the day
(Richardson 2000). The proposed
site is removed from all such
features.
• Tower height
Towers (all types, not limited to
wind turbines) less than 400-500
feet cause minimal mortality
(Kerlinger 2000) and towers less
than 300' rarely implicated in bird
kills (Kerlinger 2002). The wind
turbines proposed for Saint Paul are
less than 200' tall.
• Artificial perches
Some wind turbine designs attract
birds by providing perches in
formerly featureless terrain. For
example, lattice towers provide
numerous potential perches and are
discouraged to minimize attraction
of birds (Curry and Kerlinger 2000).
The turbine style to be used on
Saint Paul has a solid tubular tower
offering minimal perching
opportunities.
• Rotor speed
Available evidence suggests that
mortality is greatest at turbines with
faster rotors; therefore, models with
slower rotors (< 35 rpm) are
recommended to minimize potential
bird strikes. The wind turbines to be
used at Saint Paul have an
operating range of 760-1008 RPM.
The above reference to a rotor speed of 760-1008 RPM appears to be in error. An accurate
speed is closer to 44 RPM.
%Commmonweaftilt
Associates, Inc.
Page 70
• Lighting
Bird mortality at towers (not just
wind turbines) appears to be
exacerbated by lights, which,
especially under adverse weather
conditions. may attract and confuse
migrants. General guidelines are,
subject to requirements by FAA and
other regulation, to minimize lights
and if lights are necessary use the
minimum number, minimum
intensity, and only white strobes at
the minimum frequency.
• Guy lines
Guy lines supporting towers (not
just wind turbines) may be more
important than the towers they
support as agents of bird strikes
(Kerlinger 2002). The wind turbines
proposed for Saint Paul have no
guys.
Overall, most mortality at wind
turbines is usually unrelated to the
turbine itself but rather factors
associated with generic tower kills,
i.e., the poor weather in concert with
lighting, guy wires, and tower height.
The proposed towers minimize most
of these factors, being low, without
guys, without perches, and with
minimum lighting. The high rotational
speed of the turbine is the least bird
friendly aspect of the model turbine
being proposed. However, given the
relatively benign location, away from
the coast and known or potential bird
concentration areas the risk to birds
at the proposed wind turbines is
expected to be low and less than the
3-16
%COMMONWeafth Associates, Inc.
Chapter 3
Existing Environment and Environmental Effects
average reported for existing
installations.
In addition to direct mortality some
changes in bird use of the project
area may be expect due to
disturbance from increased human
activity, turbine noise, and perhaps
movement of the turbines. Leddy et
al. (1999) found reduced densities of
nesting birds in uplands near (within
approximately 180 m) wind turbines
in Minnesota.
The project also will entail
construction of gravel pads to support
the wind turbines and roads
connecting these pads to existing
facilities. In total gravel placement
cover less than 1 hectare of tundra.
Effects of this loss of habitat should
be minimal and likely to affect nesting
Lapland Longspur and perhaps Rock
Sandpiper. Disruption of tundra and
introduction of road edges will likely
increase use of the area by Gray -
crowed Rosy Finches, Snow
Buntings, and Lapland Longspurs
(foraging and post -breeding).
At present, electricity at St. Paul is
obtained from diesel -powered
generators. Greater reliance on wind
generated power would be expected
to reduce use of diesel. Shipping and
transferring fuel poses risks to birds.
In excess of 1700 birds (mostly King
Eiders) were estimated to have died
as an oil spill following a ship collision
near St. Paul Island in 1966 (Flint et
al. 1999). Although the proposed
Page 71
action in isolation will result only in a
modest reduction in future fuel
shipments (the greatest reduction
occurred with the installation of the
first turbine), the potential benefits to
birds may outweigh the small risk due
to collisions with the turbines.
THREATENED AND
ENDANGERED SPECIES
According to the list of endangered,
threatened, and candidate species in
Alaska found on the U.S. Fish and
Wildlife Service (USFWS) web page,
there are no threatened or
endangered species within the project
area (see appendix). Furthermore,
consultation with USFWS during the
scoping process confirms that there
are no endangered species within the
project area.
Miscellaneous
SOLID AND HAZARDOUS
WASTE
Existing Environment
The following information is based on
past research done for the St. Paul
Airport Improvement Plan in 1994
and the St. Paul Airport Paving
Project in 2003.
A fueling facility on the east side of
the runway, next to the existing
parking apron, is used by transient
aircraft. It consists of one 22,500-
gallon aboveground fuel tank with a
fueling pump. There is another
3-17
%Commenweafth Associates, Inc.
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Chapter 3
Existing Environment and Environmental Effects
aboveground storage tank, used for
heating, located behind the ARFF
building. Two aboveground aviation
fuel tanks were known to be located
south of the existing parking apron.
These tanks have been removed and
no known contamination or spills exist
at the location.
On the west side of the runway,
adjacent to the POSS facility, are
thirteen aboveground fuel tanks.
These were previously used by
EXXON U.S.A. for storage of aviation
fuel. TDX owns the POSS Camp
facility and stores fuel and waste fuel
in the tanks. ADEC indicated that the
POSS Camp facility has
contaminants in the adjacent gravel
pad surrounding the buildings. Spills
from aircraft and vehicle
maintenance, numerous 55-gallon
drums, and other assorted equipment
has produced surface contaminants.
TDX and National Oceanic and
Atmospheric Administration (NOAA)
are in the process of cleaning up the
contaminants.
A landfill facility approximately 2,500
feet southwest of the wind power
plant contains hazardous materials in
the form of buried leaking drums.
The Alaska Department of
Environmental Conservation (ADEC)
has required that NOAA cleanup the
drums in the landfill, as well as near
the airport.
The current wind power plant consists
of a wind turbine, a diesel control
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TDX will use its own personnel to manage and implement virtually every aspect of the proposed
St. Paul wind power project. This management team has a long record of wind power industry
experience in Alaska, the lower 48 and internationally. Principal management for the St. Paul
project will include:
• Bruce Levy - TDX Power's President with experience designing, developing and managing
12 wind farms in the U.S., Mexico and Europe;
• John Lyons - TDX Power's Operations Manager with experience in the design and long term
operations of eight similar wind projects in Alaska;
• Nicholas Goodman - TDX Power's CEO, with experience in the design, development and
operations of nine wind power projects, both in Alaska and Vermont;
• Clare Lees - TDX Power's wind power construction manager, with 25 years of experience in
wind power design and construction. Mr. Lees has personally overseen over 1500 wind
turbine installations in locations from remote Alaska, to southern California to remote
regions of South America. In 1989, Clare received the first "Windsmith of the Year" award
from the American Wind Energy Association (AWEA), the trade group's highest recognition
for technical services providers.
• William Scott, - TDX Power's chief design engineer, provides the detailed engineering and
modeling associated with all TDX utilities, projects and consulting contracts. He is a
Registered Professional Engineer with 35 years experience in power generation, and an
acknowledged authority in renewable as well as fossil fueled reciprocating and rotating prime
mover technology and thermodynamic cycles.
Specific project experience the TDX Power management team draws on that is similar in size
and scope to the proposed project on St. Paul includes:
• St. Paul Island - two stage development of 675 kw high penetration wind diesel plant in
Alaska. Designed, constructed and managed by principal TDXP management team.
• Tin City - 225 KW medium penetration wind diesel system designed and constructed for the
US Air Force, through a competitive solicitation at their long range radar site north of Nome.
Project deploys a Vestas V27 turbine (similar to St. Paul), and was/will be designed,
constructed and managed by principal TDXP management team.
• Sand Point - 1 MW high penetration wind diesel project currently under construction.
Project deploys 2 Vestas V39 wind turbines and upgrades to existing utility controls.
Designed, constructed and managed by principal TDXP management team. 40% of the
project funding secured in competitive solicitation from AEA.
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• Nikolski - 50 KW high penetration wind diesel project in remote Aleutian community.
TDXP selected to design/build the project for the Aleutian Pribilof Island Association.
Project currently under construction and scheduled for completion in 2007. Designed,
constructed and managed by principal TDXP management team.
• Painted Hills - 15 MW, Palm Springs, CA. Designed, constructed and managed by TDXP
management team members Bruce Levy and Clare Lees.
• White Water Hill - 20 MW, Palm Springs, CA. Designed, constructed and managed by
TDXP management team members Bruce Levy and Clare Lees.
• Selawik - 260 kw high penetration wind diesel project in Selawik, AK deploying four
Entegrity Wind Systems 65 kw wind turbines. As Operations Manager for AVEC, John
Lyons was one of three principals involved in the design and development of this project.
• Four Burrows - 4.5 MW, Cornwall, UK - grid connected project. Designed, constructed and
managed by TDXP management team members Bruce Levy and Clare Lees.
• Port Heiden - 300 KW high penetration project designed for AEA to be added to a Denali
Commission funded rural power systems upgrade project. Construction timeline has not
been determined yet. Designed by principal TDXP management team.
• Wales - 130 KW high penetration wind diesel project in remote Alaskan community north of
Nome. This project is noteworthy for the numerous design problems, and lessons learned.
As Operations Manager for AVEC, John Lyons was one of three principals, along with US
DOE'S National Renewable Energy Lab, involved in the design and development of this
project.
• Dyffryn Brodyn - 5.5 MW, Ceredigion, UK - grid connected project. Designed, constructed
and managed by TDXP management team members Bruce Levy and Clare Lees.
• Caton Moor - 3 MW, Lancashire, UK - grid connected project. Designed, constructed and
managed by TDXP management team members Bruce Levy and Clare Lees.
• Drumlough Hill - 6 MW, Donegal County, Ireland - grid connected project. Designed,
constructed and managed by TDXP management team members Bruce Levy and Clare Lees.
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