STATE OF VERMONT
PUBLIC SERVICE BOARD
Petition of Vermont Transco, LLC, and
Vermont Electric Power Company, Inc.
(collectively, “VELCO”), and Central Vermont
Public Service Corporation (“CVPS”) for a
Certificate of Public Good, pursuant to 30
V.S.A. § 248, for the “Southern Loop Project,”
located in Vernon, Guilford, Brattleboro,
Dummerston, Newfane, Brookline, Townshend,
Grafton, Windham, Andover, Chester, Ludlow
and Cavendish, Vermont, consisting of the
following elements: (1) a new, approximately
51-mile, 345 kV transmission line between
Vernon-Cavendish, to be built parallel to and
within the same utility right-of-way as
VELCO’s existing Vernon-Cavendish 345 kV
line; (2) a new VELCO 345/115 kV Vernon
substation, to be located just north of the
Vermont Yankee Nuclear Power Station; (3) a
new 345/115/46 kV Newfane substation; (4) a
new, approximately one-mile, 345 kV
transmission line loop between the new
Newfane substation and the new VernonCavendish 345 kV line; (5) expansion of
VELCO’s Coolidge substation in Cavendish,
Vermont; and (6) the implementing of
incremental energy efficiency to defer
transmission upgrades in Southern Vermont
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
Docket No. ____
PREFILED TESTIMONY OF
RICHARD S. HAHN
ON BEHALF OF
PETITIONERS
November 8, 2007
The purpose of Mr. Hahn’s testimony is to present and summarize two reports prepared
by La Capra Associates, Inc. entitled: “VELCO Southern Loop Project - Analysis of
Non-Transmission Alternatives to the Coolidge Connector” and “VELCO/CVPS
Southern Loop Project Distributed Generation Study.”
TABLE OF CONTENTS
1.
Introduction ............................................................................................................. 1
2.
La Capra’s NTA Analysis for the Coolidge Connector .......................................... 4
2.1
Background ............................................................................................................. 4
2.2
Alternative Resource Options Evaluated ................................................................ 8
2.3
The Achievable Energy Efficiency Projections .................................................... 10
2.4
Generation Alternatives ........................................................................................ 12
2.5
Process Used to Evaluate and Compare the TA and the ARCs ............................ 13
2.6
Results of the Analyses ......................................................................................... 14
2.7
Risk Evaluation and Feasibility Assessment ........................................................ 18
3.
La Capra’s Generation Analysis for the 46 kV Reliability Concern .................... 18
4.
La Capra’s Assessment of Distributed Generation ............................................... 20
5.
Summary of Conclusions ...................................................................................... 21
EXHIBITS
Exhibit Petitioners RSH-1
Resume of Richard S. Hahn
Exhibit Petitioners RSH-2
VELCO Southern Loop Project Analysis of NonTransmission Alternatives to the Coolidge
Connector (La Capra Associates, Inc., September
2007)
Exhibit Petitioners RSH-3
Map of the Coolidge Connector and the Southern
Loop Project
Exhibit Petitioners RSH-4
VELCO/CVPS Southern Loop Project Distributed
Generation Study (La Capra Associates, Inc., May
2006)
STATE OF VERMONT
PUBLIC SERVICE BOARD
Petition of Vermont Transco, LLC, and
Vermont Electric Power Company, Inc.
(collectively, “VELCO”), and Central Vermont
Public Service Corporation (“CVPS”) for a
Certificate of Public Good, pursuant to 30
V.S.A. § 248, for the “Southern Loop Project,”
located in Vernon, Guilford, Brattleboro,
Dummerston, Newfane, Brookline, Townshend,
Grafton, Windham, Andover, Chester, Ludlow
and Cavendish, Vermont, consisting of the
following elements: (1) a new, approximately
51-mile, 345 kV transmission line between
Vernon-Cavendish, to be built parallel to and
within the same utility right-of-way as
VELCO’s existing Vernon-Cavendish 345 kV
line; (2) a new VELCO 345/115 kV Vernon
substation, to be located just north of the
Vermont Yankee Nuclear Power Station; (3) a
new 345/115/46 kV Newfane substation; (4) a
new, approximately one-mile, 345 kV
transmission line loop between the new
Newfane substation and the new VernonCavendish 345 kV line; (5) expansion of
VELCO’s Coolidge substation in Cavendish,
Vermont; and (6) the implementing of
incremental energy efficiency to defer
transmission upgrades in Southern Vermont
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
Docket No. ____
PREFILED TESTIMONY OF
RICHARD S. HAHN
ON BEHALF OF
PETITIONERS
1
2
1.
Q1.
Introduction
Please state your name, occupation, and business address.
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 2 of 27
1
A1.
My name is Richard S. Hahn. I am employed by La Capra Associates, Inc. (“La
2
Capra”) as a Managing Consultant. My business address is 20 Winthrop Square,
3
Boston, Massachusetts, 02110.
4
5
Q2.
Please describe your education and employment background.
6
A2.
I received my bachelor’s degree in Science, Electrical Engineering, in 1973, and
7
my masters in Science, Electrical Engineering, in 1974, both from Northeastern
8
University. I received my masters degree in Business Administration from
9
Boston College in 1982. Since joining La Capra, I have worked on many projects
10
related to energy markets, forecasts of wholesale market prices, utility resource
11
planning projects, and asset valuations. Prior to joining La Capra, I worked at
12
NSTAR Electric & Gas (formerly Boston Edison Company) from 1973 to 2003.
13
Throughout my career, I have gained and demonstrated considerable experience
14
and expertise in utility planning activities. I am a registered professional
15
electrical engineer in the Commonwealth of Massachusetts. I am currently an
16
elected Commissioner for the Reading Municipal Light Board, which oversees the
17
Reading Municipal Light Department, the largest municipal electrical system in
18
Massachusetts. I serve on Reading Municipal Light Board subcommittees for
19
Rates, Power Supply, and Green Power. My resume is included with Petitioners’
20
filing in this Docket as Exhibit Petitioners RSH-1.
21
22
Q3.
Have you testified previously before the Public Service Board?
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 3 of 27
1
A3.
No. However, I have testified numerous times before the Massachusetts
2
Department of Public Utilities (MDPU), formerly known as the Massachusetts
3
Department of Telecommunications and Energy (MDTE). I have also testified
4
before FERC and the Congress of the United States.
5
6
Q4.
What is the purpose of your testimony?
7
A4.
The purpose of my testimony is to present and summarize two reports prepared by
8
La Capra under my direction: (1) “VELCO Southern Loop Project – Analysis of
9
Non-Transmission Alternatives to the Coolidge Connector” (the “Coolidge
10
Connector NTA Report” or “Report”), which is included with Petitioners’ filing
11
in this Docket as Exhibit Petitioners RSH-2; and (2) “VELCO/CVPS Southern
12
Loop Project Distributed Generation Study,” which is included as Exhibit
13
Petitioners RSH-4.
14
15
Q5.
What is La Capra’s role in this filing?
16
A5.
La Capra was retained by Vermont Electric Power Company, Inc. (“VELCO”), to
17
develop and coordinate an economic and financial analysis of non-transmission
18
alternative (“NTA”) resource options against which to evaluate the merits of the
19
Coolidge Connector portion of the Southern Loop Project. The results are
20
reported in Exhibit Petitioners RSH-2. The Coolidge Connector upgrade is
21
described in more detail in our Report. It is important to note that our assignment
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 4 of 27
1
was to examine and evaluate the economic and financial performance of potential
2
options that could serve as alternatives to a proposed transmission project.
3
4
In addition, La Capra was retained by Central Vermont Public Service
5
Corporation (“CVPS”) to perform an analysis of the potential for distributed
6
generation in the area of Vermont served by the existing 46 kV line from
7
Brattleboro to Stratton to Bennington. The results are reported in Exhibit
8
Petitioners RSH-4. It is my understanding that CVPS utilized the information on
9
distributed generation provided by La Capra to evaluate NTAs to a proposed 115
10
kV transmission upgrade to that 46 kV line.
11
12
2.
La Capra’s NTA Analysis for the Coolidge Connector
13
2.1
Background
14
Q6.
Please describe what you mean by NTAs.
15
A6.
NTAs can consist of energy efficiency (“EE”), demand response (“DR”), or local
16
generation, or various combinations thereof. The reliability concerns being
17
addressed by VELCO are primarily driven by load levels, particularly in the
18
Northwest and Central load zones as defined in the Report. The critical state-
19
wide load level in 2010 is estimated to be 1,155 MW, with the combined critical
20
loads in the Northwest and Central zones being approximately 882 MW. As load
21
grows in neighboring systems, available transmission system capacity for imports
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 5 of 27
1
into Vermont is used up, and the critical state-wide loads for the purposes of this
2
study decline to 1075 MW in 2016, with 821 MW in the Northwest and Central
3
zones. Therefore, the process of identifying and evaluating NTAs focuses on
4
options that can either on a stand-alone basis or in combination with other
5
options, provide additional local supplies or firm load reductions that keep net
6
loads in these Northwest and Central load zones at or below these load levels in
7
order to meet reliability criteria.
8
9
In determining the amount or level of NTAs required to effectively serve as
10
alternatives to transmission upgrades, it is important to ensure that, to the
11
maximum extent possible, the alternatives provided the same level of reliability
12
improvement as the transmission upgrade. Transmission systems are inherently
13
very reliable, as the probability of an unplanned outage is relatively small and the
14
transmission reliability planning criteria require that these systems be able to
15
withstand the loss of the two most critical network elements. We need to ensure
16
to the maximum degree possible that any Alternative Resource Configurations
17
(“ARCs”) developed to defer or eliminate the need for transmission upgrades
18
meet this criteria.
19
20
21
Q7.
Please describe the process that you undertook to develop and evaluate NTAs for
the Coolidge Connector portion of the Project.
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 6 of 27
1
A7.
VELCO has analyzed multiple potential transmission solutions to the reliability
2
criteria violations that it has identified (discussed in the testimony of Dean
3
LaForest and Christopher Diebold and their accompanying reports), and the
4
Coolidge Connector component of the Southern Loop Project was identified as
5
the desired transmission option. I briefly discuss the benefits of Coolidge
6
Connector component of the Southern Loop Project here as background for our
7
NTA analysis. The Coolidge Connector component of the Southern Loop Project
8
mitigates reliability concerns and the potential violations of reliability criteria by
9
providing an alternative path for power flow into the Central and Northwest
10
Vermont load zones. It involves fewer miles of construction of new transmission
11
facilities than other transmission alternatives considered and evaluated by
12
VELCO, and, therefore, is less costly. It utilizes existing right of ways (ROWs)
13
already owned by VELCO.
14
15
The construction of the Coolidge Connector component of the Southern Loop
16
Project will also facilitate the resolution of reliability and capacity issues on the
17
46 kV sub-transmission line from Brattleboro to Stratton to Bennington (the other
18
component of the Southern Loop Project). This 46 kV line, which is owned by
19
CVPS, is heavily loaded and vulnerable to reliability problems after
20
contingencies. We understand from discussions with CVPS that presently there
21
are insufficient hours during the year where portions of this line can be removed
22
from service for scheduled maintenance. According to CVPS, the preferred
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 7 of 27
1
transmission solution to this problem is to add a new 115 kV line while keeping
2
the existing 46 kV line, as shown in the map provided in Exhibit Petitioners RSH-
3
3.
4
5
The earliest possible in-service date for the Coolidge Connector component of the
6
Southern Loop Project is estimated to be 2011. As is discussed in greater detail
7
later in the Report, there may be a need to implement DR and/or EE as interim
8
measures in the 2008 – 2010 time period.
9
10
The following lists the steps followed in this study process. Each step is
11
discussed in more detail in the Report.
12

13
Identify load zones within Vermont for purposes of analyzing NTAs. These
14
zones were selected to target as tightly as possible those areas where load
15
reductions or local generation would be most effective in serving as NTAs.

16
Develop a load forecast without Demand Side Management (“DSM”) by load
17
zone. This forecast served as the basis for a study of the potential for energy
18
efficiency measures.

19
Identify resource options that can serve as NTAs. These options include:
20
o EE potential study from Optimal Energy (separate report1)
21
o DR assessment by Grimason Associates (Appendix B to our Report)
1
Assessment of Achievable Potential for Energy Efficiency in the Central and Northwest Vermont
Load Zones (Optimal Energy, Inc., Vermont Energy Investment Corporation, September, 2007)
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 8 of 27
1
o Combined Heat and Power (“CHP”)
2
o Distributed Generation (“DG”)
3
o Larger scale generation (combustion turbines (“CTs”), wood-fired
4
biomass, etc.)

5
6
Perform preliminary cost-effectiveness screening using avoided costs and
externalities values.

7
8
Determine the amount or level of NTAs, or combinations of options, required
to meet reliability criteria.

9
10
Formulate scenarios or combinations of NTA options to create ARCs to meet
reliability criteria.

11
12
Simulate the operation of the ISO-NE energy, capacity, and ancillary services
markets for the transmission alternative and for each of the developed ARCs.

13
Develop a scorecard that summarizes the economic and financial performance
14
of the transmission alternative and each ARC to present the results of the
15
simulations.

16
17
Conduct a risk evaluation and feasibility assessment for the transmission
alternative and for each ARC.

18
Summarize the findings and present conclusions.
19
20
21
22
2.2
Q8.
Alternative Resource Options Evaluated
Please describe the resource options that you identified to serve as potential
NTAs.
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 9 of 27
1
A8.
After reviewing the needs identified by VELCO, we developed four ARCs. We
2
attempted to develop an “all DSM” ARC, but there is insufficient DSM to
3
accomplish this goal. The projected DSM over and above the forecast of savings
4
from status quo budgets available to serve as NTAs is 88 MW by 2016 assuming
5
normal weather. Under extreme weather conditions, we estimate that this figure
6
would increase to 93 MW. This resource level did not satisfactorily meet the
7
needs assessment of 152 MW. Three new 25 MW units are needed to supplement
8
the Achievable EE case. These new units were assumed to be combustion turbine
9
(CT) peaking units installed in 2012, 2014, and 2016.
10
11
ARC 2 is an all new generation ARC. This ARC is based upon the assumption
12
that three new 25 MW CT units be installed by 2011 and a total of eight new units
13
placed in service by 2016.
14
15
ARC 3 is a similar to ARC 1 except that the in-service dates for new 25 MW CT
16
generating units is accelerated, and DR resources after 2011 are eliminated.
17
18
ARC 4 is the same as ARC 3, except that three new 25 MW wood-fired biomass
19
plants replace the three CT units. While ARC 3 and ARC 4 provide the same
20
contribution to reliability, they will have different effects on the results of societal
21
cost test. CTs operate only during peak hours, while biomass plants of the type
22
assumed here operate largely as baseload units. We developed ARC 4 to see if
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 10 of 27
1
there would be significant benefits from net energy revenues from ISO-NE’s
2
energy markets in installing biomass plants.
3
4
In ARCs 2, 3, and 4, where the Coolidge Connector component of the Southern
5
Loop Project is not built, we have included the cost of transmission upgrades
6
associated with the local reliability component of the Southern Loop Project,
7
namely the proposed upgrade to resolve reliability deficiencies in southern
8
Vermont. It is my understanding that this issue is discussed further in the
9
testimonies of other witnesses in this proceeding.
10
11
2.3
The Achievable Energy Efficiency Projections
12
Q9.
Explain the “Achievable EE” projections as used in development of the ARCs.
13
A9.
The amount of EE that is available to serve as NTAs was estimated by Optimal
14
Energy. This was done by first estimating the achievable potential for EE in the
15
Northwest and Central zones, and subtracting out a projection of what is likely to
16
be implemented anyway without regard for specifically geographically targeting
17
NTAs in the Northwest and Central load zones. This projection of what is likely
18
to be implemented anyway is referred to as the “status quo” estimate of EE.
19
20
In order to achieve the unprecedented level of DSM savings identified in the
21
Achievable EE scenario, annual spending would increase dramatically to $67
22
million in 2016, which is more than double the 2008 budget approved for
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 11 of 27
1
Efficiency Vermont. Total spending on EE programs over ten years would be
2
approximately $592 million.
3
4
It is interesting to compare the amount of DSM contained in the Vermont
5
Department of Public Service’s (the “Department”) October 2006 draft update to
6
the State Energy Plan, to the projections made for this study. The Department’s
7
draft update estimated 192 MW2 of state-wide summer peak load reduction in
8
2016. In our study, the total of the status quo EE forecast for the State of
9
Vermont plus 100% of the Achievable EE in the Northwest and Central load
10
zones, is 227 MW. Thus, our Achievable EE scenario exceeds the Department’s
11
forecast of DSM savings by 43 MW in 2016.
12
13
For the Achievable EE scenario, we project that by 2016, 88 MW of incremental
14
(i.e., above the status quo projection) summer peak load reduction and 253 GWH
15
per year in incremental energy savings is possible in the Northwest and Central
16
zones (see page 26 of our Report). The cost of obtaining this level of incremental
17
EE savings is estimated to be $292 million over the next ten years. The above
18
figures represent only the incremental EE over and above the status quo
19
projections. When the status quo projections are added to these incremental
20
savings and costs to arrive at total state-wide EE activity, the annual summer peak
See Table 3-3, page 43 of the Department’s draft update. We understand that this estimate is
based upon 100% of the economic potential as forecast by GDS Associates in July 2006.
2
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 12 of 27
1
savings are 227 MW, annual energy savings are 1,171 GWH, and the cumulative
2
costs are approximately $594 million over ten years.3
3
4
The La Capra Report shows that in the Achievable EE scenario, annual spending
5
on EE increases to $67 million in 2016 from $47 million in 2008. These spending
6
levels represent only utility expenditures on EE, and do not include the customer
7
component of the EE measure costs. Customer implementation costs for the
8
Achievable EE scenario are estimated to be an additional $34 million over ten
9
years.
10
11
2.4
Generation Alternatives
12
Q10.
Please describe the generation options included in the NTAs.
13
A10.
The generation options selected for inclusion as NTAs were those that were
14
appropriately sized and were dispatchable. Thus, the generating options that are
15
typically installed in larger sizes, such as combined cycle units, coal plants, or
16
nuclear plants, were not considered as new resource alternatives for developing
17
ARCs. Resources also needed to have operational control or dispatchability, such
18
that we would have a high degree of confidence of the resource being available
19
when needed. Therefore, wind generation options were not considered viable, as
20
these resources are not always available at the time of the system peak load. Solar
3
Note that these figures do not include any targeted EE in the Northern or Southern zones for areas
such as the Southern Loop phase I or Newport.
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 13 of 27
1
PV did not pass the screening analysis, as this option had a benefit / cost ratio that
2
was lower than the CHP options considered.
3
4
The two most attractive options for new generation resources to include in ARCs
5
are peaking units such as CTs or wood-fired biomass units, such as the existing
6
unit at Ryegate. Both can be implemented in relatively small units (e.g., 25 MW).
7
Peaking units have relatively simple construction processes and once built, can be
8
placed on-line quickly and successfully dispatched to react to system conditions.
9
Wood-fired biomass plants are an attractive option because of the availability of
10
fuel supply in Vermont and the successful experience with existing projects such
11
as McNeil and Ryegate.
12
13
14
2.5
Q11.
15
16
Process Used to Evaluate and Compare the TA and the ARCs
Please describe the process that you used to evaluate and compare the ARCs to
each other and to the Coolidge Connector.
A11.
La Capra evaluated the cost-effectiveness of the ARCs against each other and as
17
compared to the Coolidge Connector component of the Southern Loop Project.
18
For economic and financial comparisons, we evaluated societal costs, system
19
costs, capital costs, impact of regional cost support through Pool Transmission
20
Facilities (“PTF”) rate treatment4, and expected rate impacts. It is our
4
For purposes of this analysis, we assumed that all of the Coolidge Connector components of the
Southern Loop Project costs qualify as PTF treatment. However, PTF funding is not available for any
portion of the Project unless the entire Vernon to Cavendish line is built.
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 14 of 27
1
understanding that the Vermont Public Service Board has defined a societal cost
2
test that includes externalities and a risk adjustment for DSM, but does not
3
include benefits from PTF rate treatment, Production Tax Credits, REC revenues,
4
or Forward Capacity Market (“FCM”) revenues to new generators and new DSM.
5
These multiple perspectives enable the Board to fully weigh the relative cost
6
advantages and disadvantages of each NTA compared to the transmission
7
solution.
8
9
2.6
VELCO COOLIDGE CONNECTOR - NON-TRANSMISSION ALTERNATIVES
OF COST-EFFECTIVENESS ANALYSES
ResultsSUMMARY
of the Analyses
10
Q12.
Please describe the results of your analysis.
11
A12.
Transmission
ARC1
ARC2
ARC3
ARC4
Our results are summarized in
the following
table, and
are discussed
in greater
Achievable EE
NPV 2007 - 2022
All Figures in 1,000's of 2007 Dollars
Achievable EE
12
+ CT
Achievable EE
earlier)
Generation)
detail in the body of the Report.
Please +note
that the(All$CT
difference
and %
(Coolidge
DR + CT
Generation
+ DR + Biomass
Connector)
Generation)
Generation)
13
difference rows under System Costs and Systems Costs w/o PTC’s in the
Vermont Societal Costs [1]
14
Relative to the Transmission Alternative
1,200,400
1,085,246
1,244,658
1,085,993
1,207,469
44,258
Coolidge Connector NTA Report reference(115,153)
societal costs
rather (114,406)
than system 7,069
costs.
$ difference in societal costs from lowest case
% difference in societal costs from lowest case
15
115,153
-
159,412
15%
747
0%
122,222
11%
1,160,310
84,185
1,015,324
(60,801)
1,093,469
17,344
This error has been corrected on the11%following0%
table.
16
System Costs [2]
1,076,125
Relative to the Transmission Alternative
17
1,019,425
(56,700)
Summary of Cost-Effectiveness
Analysis
109,007
52,307
193,193
$ difference in system costs from lowest case
% difference in system costs from lowest case
18
19
System Costs w/o PTC's
11%
5%
20%
48,207
5%
126,352
13%
1,076,125
1,019,425
(56,700)
1,160,310
84,185
1,015,324
(60,801)
1,121,755
45,630
Relative to the Transmission Alternative
From the perspective of the Vermont
Societal
Test 5, ARC
1 has the
lowest154,637
net
109,007
52,307
193,193
48,207
20
$ difference in system costs from lowest case
% difference in system costs from lowest case
11%
5%
20%
5%
16%
present value (“NPV”) societal costs,
400 followed
166very closely
158 by ARC
1523 and then
166
21
Effective Firm Capacity in 2016
System Cost per firm kW
2,700
6,100
7,300
6,700
6,800
the transmission alternative (“TA”) followed closely by ARC 4. As anticipated,
22
Capital costs paid by Vermont ($millions)
With PTF Treatment
Without PTF Treatment
23
13
258
517
517
359
359
500
500
735
735
the costs for ARC 1 and ARC 3 are very close, with a slight edge to ARC 1 in
Illustrative Retail Cost in 2016 (cents/KWH)
Difference in revenues 2007 to 2016 (nominal$)
5
[1]
16.40
-
17.60
17.00
17.60
18.40
153
118
155
265
Seeno appendix
a description
of this
cost
test.
Assumes
PTF treatment forD
the for
Coolidge
Connector, no Production
Tax Credit
or REC
revenues for new renewable projects,
and no Forward Capacity Market revenues for new generators or new DSM. DSM risk adjustment and externailites are included.
[2] Assumes PTF treatment for the Coolidge Connector, Production Tax Credit and REC revenues for new renewable projects,
and Forward Capacity Market revenues for new generators or new DSM. DSM risk adjustment and externailites are included.
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 15 of 27
1
societal costs. Assuming wood-fired biomass units continue to receive a
2
production tax credit (“PTC”) currently available to renewable energy projects
3
over the life of these assets, REC revenues, PTF rate treatment for the Coolidge
4
Connector, and FCM market revenues for new generation and DSM, ARC 3 has
5
the lowest net present value (“NPV”) of system costs. ARC 1 has the next lowest
6
system costs, followed by the TA. These three scenarios yield NPV of system
7
costs that differ by approximately $60 million between one another, or 6% of the
8
total costs. Without the PTC but with PTF rate treatment and FCM revenues,
9
ARC 3 has the lowest NPV of costs, followed by ARC 1, and then the TA.
10
Without PTCs, the differences in the NPVs of system costs narrow slightly.
11
12
ARC 2, the all-CT solution, has higher societal and system costs than the TA, but
13
has the second lowest capital costs.
14
15
Associated with each ARC’s economic outcomes are different capital
16
requirements and rate impacts. The Coolidge Connector component of the
17
Southern Loop Project (the TA) has the lowest capital costs to Vermont
18
(approximately $13 million assuming PTF rate treatment as compared to ARC 4
19
at $735 million, ARC 1 at $517 million, and ARC 3 at $500 million). The TA
20
also yields the lowest average retail rates. By contrast, ARC 4 produces the
21
highest rates.
22
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 16 of 27
1
Combining the cost-effectiveness of EE resources with other higher cost options,
2
such as peaking generation, produces an ARC that has overall lower NPV societal
3
costs than the TA. To test whether the combination of EE and the TA would
4
produce an even lower NPV societal cost, we analyzed a TA-NTA Hybrid
5
scenario (previously referred to in public discussions as ARC 5), which combined
6
the Achievable EE option with the TA. While combining the TA with an NTA
7
does not qualify as a logical alternative reliability solution to the TA itself, it does
8
give a good idea of the likely outcome if Vermont were to end up pursuing
9
additional EE and the TA simultaneously. The result of including the TA-NTA
10
Hybrid in the cost-effectiveness analysis is shown in the table below. Please note
11
that the $ difference and % difference rows under System Costs and Systems
12
Costs w/o PTC’s in the Coolidge Connector NTA Report reference societal costs
13
rather than system costs. This error has been corrected on the following table.
14
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 17 of 27
1
2
3
4
Summary of Cost-Effectiveness Analysis including the TA-NTA Hybrid
VELCO COOLIDGE CONNECTOR - NON-TRANSMISSION ALTERNATIVES
SUMMARY OF COST-EFFECTIVENESS ANALYSES
5
NPV 2007 - 2022
From the Vermont societal cost test perspective,
this TA-NTA hybrid would be
All Figures in 1,000's of 2007 Dollars
6
ranked third, closely behind ARCs 1 and 3 but ahead Achievable
of the EE
TA alone and ARCs 2
7
Transmission
ARC1
ARC2
ARC3
(Coolidge
Connector)
Achievable EE
+ DR + CT
Generation)
(All CT
Generation)
+ CT
Generation
earlier)
1,200,400
Relative to the Transmission Alternative
9
1,076,125
14
15
16
17
1,085,993
(114,406)
1,207,469
7,069
1,131,107
(69,293)
0%
15%
0%
11%
4%
1,019,425
(56,700)
1,160,310
84,185
1,015,324
(60,801)
1,093,469
17,344
967,117
(109,007)
low system costs. However,109,007
the hybrid52,307
scenario193,193
requires 48,207
significantly
more
126,352
$ difference in system costs from lowest case
% difference in system costs from lowest case
11%
5%
20%
5%
-
13%
0%
capital than the TA alone ($337 million for the TA-NTA Hybrid as compared to
1,076,125
Relative to the Transmission Alternative
13
1,244,658
44,258
savings associated with EE with the transmission alternative does indeed yield
System Costs w/o PTC's
12
1,085,246
(115,153)
11%
Relative to the Transmission Alternative
11
Achievable EE Achievable EE
+ DR + Biomass
+ Coolidge
Generation)
Connector)
terms of lowest system costs.
This supports
our159,412
hypothesis747
that combining
the
115,153
122,222
45,861
$ difference in societal costs from lowest case
% difference in societal costs from lowest case
System Costs [2]
10
TA-NTA Hybrid
and 4. Comparing system costs, the hybrid scenario would be ranked first in
Vermont Societal Costs [1]
8
ARC4
1,019,425
(56,700)
1,160,310
84,185
1,015,324
(60,801)
1,121,755
45,630
967,117
(109,007)
$13 million for the TA, assuming
PTF),
and higher
rate impacts
than
the TA.
109,007
52,307
193,193
48,207
154,637
$ difference in system costs from lowest case
% difference in system costs from lowest case
Effective Firm Capacity in 2016
System Cost per firm kW
Capital costs paid by Vermont ($millions)
With PTF Treatment
Without PTF Treatment
11%
400
2,700
5%
166
6,100
20%
158
7,300
5%
152
6,700
-
16%
166
6,800
0%
493
2,000
No single combination of options
highest
of the
13 ranked
517consistently
359
500 in each735
258
517
359
500
735
337
583
categories considered. For example,
the17.60
transmission
alternative
has18.40
the lowest
16.40
17.00
17.60
17.30
Illustrative Retail Cost in 2016 (cents/KWH)
Difference in revenues 2007 to 2016 (nominal$)
-
153
118
155
265
capital requirements and rate impacts, but the third lowest NPV societal costs.
66
[1] Assumes no PTF treatment for the Coolidge Connector, no Production Tax Credit or REC revenues for new renewable projects,
and no Forward Capacity Market revenues for new generators or new DSM. DSM risk adjustment and externailites are included.
[2] Assumes PTF treatment for the Coolidge Connector, Production Tax Credit and REC revenues for new renewable projects,
and Forward Capacity Market revenues for new generators or new DSM. DSM risk adjustment and externailites are included.
ARC 1 has low societal costs, but very high capital requirements and rate impacts.
18
Given the relative parity in the cost-effectiveness analysis among some of the
19
ARCs, no single ARC dominates all others with respect to societal costs, capital
20
requirements, and rate impacts. With the system cost test, the TA-NTA Hybrid
21
yields the lowest costs, but has significantly higher Vermont capital costs,
22
assuming PTF rate treatment for the TA.
23
24
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 18 of 27
1
2
2.7
Q13.
Risk Evaluation and Feasibility Assessment
Above you outlined a step in your analytical process where you developed a risk
3
evaluation and feasibility assessment for implementation and performance of the
4
ARCs as compare to the Coolidge Connector. Please describe the results of that
5
assessment.
6
A13.
Appendix F to our Report provides a summary of the risk evaluation and
7
feasibility assessment developed of each option within the ARCs. The
8
development, construction, and operation of energy resources, including
9
transmission, EE and DR, is difficult, and the selection of each resource within
10
one or more ARCs carries some risks that the implementation will not come off
11
exactly as planned. In some cases, there are concerns about the feasibility of
12
implementation. Consideration of these issues is most often done qualitatively,
13
and they do not lend themselves to numerical analysis. Thus, the matrix provided
14
in Appendix F to our Report lays out these issues and concerns in tabular form to
15
facilitate comparison of the ARCs.
16
17
18
3.
Q14.
La Capra’s Generation Analysis for the 46 kV Reliability Concern
Earlier you explained that costs of a transmission solution to solve the local
19
reliability problem were included in ARCs 2, 3 and 4. Would you please explain
20
why and how these costs are reflected in the table above?
21
A14.
CVPS and VELCO have engaged in a public process to assess possible non-
22
transmission alternatives to the supplementation of the Brattleboro to Stratton to
23
Bennington 46 kV sub-transmission line with a new 115 kV line. I understand
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 19 of 27
1
that CVPS plans to defer the 51 miles of new 115 kV transmission upgrades from
2
Newfane to Stratton to Bennington by implementing specific non-transmission
3
alternatives, including: (1) installing synchronous condensers at Stratton for
4
voltage support; and (2) pursuing the implementation of targeted energy
5
efficiency. However, the results of the CVPS NTA analysis for the local
6
reliability problem concludes that in order for these NTAs to effectively serve as
7
alternatives to the 115 kV upgrade, the VELCO transmission system between
8
Brattleboro and Newfane must be upgraded. This could involve building the “A”
9
line portion of the Southern Loop Project between Vernon and Newfane as shown
10
in Exhibit Petitioners RSH-3 above, or it might involve some other project that
11
achieves the needed level of system improvement.
12
13
The Vermont Yankee 345 / 115 kV autotransformer serves a vital transmission
14
function in southeastern Vermont and southwestern New Hampshire. This
15
transformer connects the 345 kV system to the 115 kV, 69 kV, and 46 kV
16
networks that serve CVPS’s service territory and communities such as
17
Brattleboro, as well as southwest New Hampshire communities such as Keene.
18
Loss of the Vermont Yankee 345 / 115 kV autotransformer places all of the load
19
in this area (southeast VT / southwest NH) on a very weak 115 / 46 kV network
20
served out of Bennington in the west and southeastern New Hampshire / central
21
Massachusetts in the east. Loss of transmission lines in this configuration results
22
in loss of significant amounts of local load. A second Vermont Yankee 345 / 115
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 20 of 27
1
kV autotransformer, with associated substation upgrades, resolves these regional
2
reliability concerns.
3
4
If the entire 51 mile 345 kV line (Coolidge Connector) from Vernon to Cavendish
5
is built, then the investment required to construct the A and B lines will very
6
likely qualify for PTF rate treatment and those costs will be socialized across all
7
transmission customers throughout New England. Under PTF rate treatment,
8
Vermonters will pay approximately 4% of those costs. However, if only the first
9
portion of the 345 kV line from Vernon to West Dummerston or Newfane were
10
built, and not the entire Vernon to Cavendish line, the investment required to
11
construct the partial line upgrade and the new transformer at West Dummerston or
12
Newfane, or a comparable project, will not qualify for PTF rate treatment. In that
13
case, Vermont ratepayers will bear 100% of the cost of the “A” line and the new
14
transformer at West Dummerston or Newfane or the comparable project. Thus,
15
the construction of the entire Coolidge Connector component of the Southern
16
Loop Project will result in lower costs to ratepayers in Vermont relative to a
17
partial transmission upgrade that solves only the CVPS 46 kV reliability problem
18
but not the regional reliability problem.
19
20
21
22
4.
Q15.
La Capra’s Assessment of Distributed Generation
Please describe the work La Capra performed for CVPS and VELCO regarding
distributed generation.
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 21 of 27
1
A15.
La Capra was retained by VELCO and CVPS to identify potential distributed
2
generation options, provide cost and operating parameters, and conduct a
3
preliminary screening analysis. A copy of our report is provided in Exhibit
4
Petitioners RSH-4.
5
6
Q16.
7
8
How does the work on distributed generation related to the NTA analysis for the
Coolidge Connector component of the Southern Loop Project.
A16.
9
The technologies and costs for generation options described in Exhibit Petitioners
RSH-4 were utilized in the NTA study for the Coolidge Connector. There are
10
several significant differences in the analysis performed by CVPS for the
11
proposed 115 kV upgrade and our NTA study for the Coolidge Connector. The
12
Central and Northwest load zones in our study are summer peaking regions, while
13
the load in the Newfane to Stratton to Bennington area is winter peaking. Also,
14
the amount of load reductions and / or new generation needed to serve as an NTA
15
is very much larger for the Coolidge Connector Study, and it is spread out over a
16
much larger geographic area. While these differences may lead to different
17
outcomes and conclusions, the process and the underlying data from La Capra’s
18
perspective are very consistent in both studies.
19
20
21
5.
Q17.
Summary of Conclusions
Please summarize your conclusions.
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 22 of 27
1
A17.
A significant element of the initial Southern Loop Project upgrades, the proposed
2
115 kV line upgrade to an existing 46 kV line from Brattleboro to Stratton to
3
Bennington, is being deferred by CVPS with a combination of synchronous
4
condensers and EE. The consequences of failure (i.e., that NTAs will not be
5
implemented, or will not effectively serve as a reliable alternatives to a new
6
transmission line) are relatively low in deferring this element of the transmission
7
upgrade, as any outages, although important, will only affect a limited geographic
8
area within Vermont. However, the remaining portions of the Southern Loop
9
Project are necessary to reinforce the local and regional transmission networks
10
and maintain VELCO’s transmission network’s compliance with national and
11
regional reliability standards. Failure to effectively mitigate reliability concerns
12
associated with VELCO’s transmission network has much greater consequences,
13
as a widespread collapse of the electric grid affecting multiple states could occur.
14
While NTAs appear to be able to serve as effective solutions to reliability
15
concerns, pursuit of NTAs in lieu of the Southern Loop Project would pose some
16
uncertainties and risks.
17
18
No single combination of options ranked consistently highest in each of the
19
categories considered. For example, the transmission alternative has the lowest
20
capital requirements and rate impacts, but the third lowest NPV societal costs.
21
ARC 1 has low societal costs, but very high capital requirements and rate impacts.
22
Given the relative parity in the cost-effectiveness analysis among some of the
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 23 of 27
1
ARCs, no single ARC dominates all others with respect to societal costs, capital
2
requirements, and rate impacts. With the system cost test, the TA-NTA Hybrid
3
yields the lowest costs, but has significantly higher Vermont capital costs,
4
assuming PTF rate treatment for the TA.
5
6
The scorecard results presented in our report depict the results if each component
7
of each alternative is actually implemented and performs as expected. Every
8
component of every alternative solution, including transmission and non-
9
transmission options, carries some uncertainty and risk that it might not be
10
feasible to implement fully or it might perform differently than expected. Prudent
11
utility planning requires that such risks be assessed and factored into any
12
conclusions that might be drawn from this analysis and any implementation
13
strategy that might result. Therefore, we also evaluated the risks and feasibility
14
issues associated with each ARC component, including the transmission
15
alternative, energy efficiency, demand response, and new generating units. Each
16
resource option considered and included in the ARCs has significant
17
implementation risks and feasibility issues, which are discussed in greater detail
18
in the body of our Report.
19
20
The transmission alternative involves some permitting risk, but once built,
21
transmission lines present little operating risk, but are subject to outages primarily
22
due to trees and storm events that can be managed with proper right-of-way
23
maintenance. The transmission alternative proposed here utilizes an existing right
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 24 of 27
1
of way. Generation options also present permitting and siting risk, and present
2
additional operating and cost risk over their lives. Some generation options, such
3
as biomass plants, have potential for benefits from the ISO-NE energy markets,
4
but these benefits are affected by the price of wood fuel.
5
6
The risks associated with implementing individual EE measures and programs are
7
generally low, but there is uncertainty regarding the long-term sustainability of
8
the required budgetary commitments, particularly at the levels assumed in our
9
Achievable EE scenarios. The Achievable EE scenario calls for utility
10
expenditure of $594 million over the next ten years. Status quo spending by
11
Efficiency Vermont (before any NTAs) was assumed to be $302 million over ten
12
years (average $30 million per year) in the La Capra analysis. Efficiency
13
Vermont budgets approved for 2007 and 2008 are $24 million and $31 million
14
respectively. The Achievable EE scenario in Central and Northwest Vermont
15
load zones requires increasing this amount to $56 million in 2009 and gradually
16
increasing to $67 million by 2016, representing a ten-year commitment to
17
approximately $594 million. This requires a substantial, long-term increase in
18
state-wide EE budgets. The approval of such an aggressive budget is uncertain
19
over the extended period of time needed for full implementation and realization of
20
the requisite EE. In addition, as Optimal Energy noted in its analysis of potential
21
EE resources for this Project: “An important source of uncertainty, however, is
22
the fact that no utility has ever sustained such large distributed resource
23
commitments for so long in so many markets simultaneously and actually
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 25 of 27
1
achieved the relative magnitudes of peak demand savings projected over the next
2
decade as indicated in this report.”
3
4
From a cost perspective, the key to determining which alternative is the preferred
5
one lies in the specification of the cost-effectiveness test to be utilized. The
6
largest impact comes from PTF treatment. If the Vermont societal cost test as we
7
have defined it here (without PTF treatment) is utilized, then ARC 1 yields the
8
lowest societal cost. In order to have ARC 1 as the preferred NTA scenario,
9
Vermont would need to commit in the very near future to an extremely aggressive
10
and unprecedented EE implementation schedule and budget. In addition, a
11
commitment would also have to be made to install new generating capacity by the
12
beginning of 2011. Further, if either of these options falls short of their firm load
13
reduction targets, or the demand for electricity increases, mandatory reliability
14
standards will not be met.
15
16
If a cost-effectiveness test is to be utilized that affords PTF treatment to the
17
Coolidge Connector, then the TA-NTA Hybrid scenario yields the lowest system
18
cost, and provides the greatest amount of capacity. However this proposal
19
requires the same commitment to an extremely aggressive EE implementation
20
schedule and budget to achieve the societal benefits associated with the EE. The
21
capital costs are significantly higher than the TA alone. Regardless of how much
22
EE is implemented, EE alone will not be sufficient to serve as an NTA.
23
Something else must be added. With PTF treatment, adding the transmission
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 26 of 27
1
alternative to whatever level of EE is finally decided is superior to adding
2
generation options to the same level of EE.
3
4
Given the results presented above, the choice of a preferred solution is an
5
extremely difficult decision that requires a balancing of interests. Regardless of
6
the choice of the preferred alternative, there is considerable risk associated with
7
each. The Coolidge Connector may provide a larger, more certain reliability
8
benefit, is further along in its development as a project, and allows time to further
9
discussions about EE schedules and budgets. However, the permitting of the line
10
is far from certain. And as discussed previously, there is also uncertainty about
11
the ability to construct new generation and in the process of establishing EE
12
budgets and schedules.
13
14
La Capra recommends a two-pronged, parallel path approach to mitigating the
15
risk of implementing solutions to the identified reliability needs. One parallel
16
path is to pursue permitting and construction activities for the Coolidge Connector
17
component of the Southern Loop Project via the §248 process. The other parallel
18
path is to pursue additional EE measures and also pursue the development of
19
additional generation resources (gas combustion turbines or biomass generation).
20
In this scenario, the proceeding with the permitting of new generation alternatives
21
would serve as a backstop measure and an insurance policy if the line cannot be
22
permitted or constructed. It is our understanding the Vermont’s Distribution
23
Utilities (“DUs”) already have a process in place to explore future generation
Southern Loop Project, PSB Docket No._____
Prefiled Testimony of Richard S. Hahn
November 8, 2007
Page 27 of 27
1
options, and that several DUs are proposing to develop peaking generation.
2
Those processes should continue.
3
4
Proceeding to develop parallel options could help mitigate many of the risks and
5
uncertainties associated with each alternative, and provide an insurance policy
6
against failure of the preferred option. During these parallel processes, the
7
permitting activities of the Coolidge Connector should be monitored, as should
8
progress made on new generation options and EE budgets. Peak loads should also
9
be monitored to ensure that the need levels do not increase faster than expected.
10
Implementing parallel solutions for a short period of time may result in some
11
expenditure of resources (time and money) to investigate development of options
12
that ultimately might not get implemented, but this amount is likely to be modest
13
compared to the overall cost of a complete solution and provides a valuable hedge
14
to assure the cost-effective and reliable provision of service. The parties who
15
expend these resources should receive some form of compensation and / or cost
16
recovery in a manner to be determined.
17
18
Q18.
Does this conclude your testimony at this time?
19
A18.
Yes, it does.