HomeMy WebLinkAboutAEA Railbelt Transmission Plan Economic Analysis Project15-0481 EPS 03-03-2017-RB
Alaska Energy Authority
Railbelt Transmission Plan
Economic Analysis
Project #15-0481
March 3, 2017
David A. Meyer. P.E.
Randy Miller, P.E.
Dr. James W. Cote, Jr., P.E.
David W. Burlingame, P.E.
Alaska Energy Authority
Railbelt Transmission Plan – Final Draft
December 2, 2016
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Table of Contents
1 INTRODUCTION ............................................................................................................... 1
2 EXECUTIVE SUMMARY ................................................................................................... 1
3 PRODUCTION COST SIMULATIONS .............................................................................. 5
3.1 The Structure of the Model ....................................................................................... 5
3.2 Assembling the Data .................................................................................................. 5
3.3 Data Sources .............................................................................................................. 6
3.4 Base Case and Sensitivities ........................................................................................ 6
3.5 Loads .......................................................................................................................... 6
3.6 Escalation ................................................................................................................... 7
3.7 Fuel Prices – Base Case .............................................................................................. 8
3.8 Fuel Prices – Sensitivities ........................................................................................... 8
3.9 The Consistency of the Modeling .............................................................................. 8
3.10 Resource Sensitivities ................................................................................................ 9
3.11 Results of this Analysis ............................................................................................... 9
A APPENDIX: A COST/BENEFIT NOTES AND SUMMARY ..............................................12
B APPENDIX B: ECONOMIC ANALYSIS SENSITIVITY ....................................................15
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December 2, 2016
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List of Tables
Table 2-4: Sensitivity Case Summaries ...................................................................................... 4
Table 5-1: Load Alternatives ...................................................................................................... 6
Table 5-2: Load Sensitivities ...................................................................................................... 6
Table 5-3: Escalation Rates ....................................................................................................... 7
Table 5-4: Base Case Projections .............................................................................................. 8
Table 5-5: 2030 Fuel Prices – c/mmBTU .................................................................................... 8
Table 5-8: Production Costs for Each Modeled Case ................................................................10
Table 5-9: Transmission Losses for Different Cases .................................................................11
Table A-1: Historically Displaced Energy...................................................................................13
Table A-2: Left intentionally blank .............................................................................................13
Table A-3: Kenai Loss Analysis .................................................................................................14
1 Introduction
This report includes the findings of the economic studies completed to determine the future composition of the
Railbelt transmission system.
Since the last draft report was issued in March 2014, new reliability and operating standards have been adopted
by the Railbelt utilities, and new generation plants for all utilities have been commissioned. Additionally, the
Railbelt utilities have spent considerable effort reviewing and updating the economic models used to simulate
the Railbelt’s cost of power production. As a result of the new standards, new power plants, and the utilities’
work on the economic model; the transmission studies have been updated to reflect 2016 conditions, and the
economic studies have been updated to use the latest economic models available from the utilities.
This portion of the Transmission Plan provides the data and results used to complete the economic analysis of
the production cost simulations with and without the recommended system improvements. In addition to the
Production Cost simulations, the report identifies other economic benefits that should be considered when the
evaluations required by AKTPL-001-4 are completed.
This portion of the report is not intended to be a complete economic evaluation as it only included limited
evaluation of each projects’ benefits.
2 Executive Summary
Electric Power Systems (EPS) has completed an analysis to determine the recommended future transmission
system in the Railbelt. The need for the transmission plan was driven by the changes in the Railbelt generation
and transmission system since the completion of the 2010 Regional Integrated Resource Plan (RIRP)
administered by the Alaska Energy Authority (AEA).
The recommended transmission system improves reliability and has the potential to mitigate future cost
increases to Railbelt rate payers and allow significant energy transfers between different areas of the Railbelt
system. Constraints to the use of Bradley Lake hydroelectric project energy are removed and the coordination
of hydro and thermal generation resources throughout the Railbelt can be optimized. While the proposed
reliability improvements are far from what would be required for a transmission system in the Lower 48, they do
significantly improve the reliability and economics of the Railbelt and allow the utilities to pursue additional load
and resource pooling options not possible with the existing transmission system. The proposed improvements
allow increased use of variable renewable generation, such as wind and photovoltaic (PV) in the Railbelt system,
which is currently near its limit of renewable resource penetration.
Most transmission improvements are typically justified by the cost of unserved energy, or the value of system
reliability, and are rarely justified purely on hard economic benefits. However, the value of unserved energy was
not factored into the benefit analysis of the proposed transmission improvements in this study. There is currently
no uniform estimate of unserved energy throughout the Railbelt, nor are there available records or criteria to
allow it to be equitably evaluated. Typically, in the Lower 48, these types of reliability improvements are required
as part of the bulk power systems’ mandate to meet NERC’s and/or the transmission areas’ reliability criteria.
Projects are not evaluated solely in terms of the pure economic benefit of the project for fuel savings or reduced
losses.
Since the issuance of the 2014 draft report, the utilities have made a significant effort in updating the economic
model of the Railbelt to more accurately portray the system’s operation, and some of the utilities are in active
discussions on power pooling and its associated benefits. This study assumes the utilities will implement a fully
pooled system prior to 2030. In addition to generation pooling, the study also assumed the utilities would
maximize the benefit of hydro-thermal coordination prior to 2030, including the energy from the new Battle Creek
project at Bradley Lake. The fuel savings possible from the new transmission system were measured from the
baseline assumption that the existing transmission system was utilized to its greatest extent possible by
implementing a fully pooled Railbelt system. The year 2030 was chosen for the study year as the final
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December 2, 2016
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transmission improvements could be completed by that time. The power production cost of Railbelt generation
was first estimated using a model of the fully pooled Railbelt in 2030.The cost of power production was then
identified using the same fully pooled system with the new transmission system. Both simulations utilized hurdle
rates of $1/MW to simulate a tight pool for all cases. The difference between the two simulations indicates the
true value of the transmission system in reducing production costs for the Railbelt.
It is important to emphasize that the transmission benefits outlined in this report can only be realized following
the construction of projects included in the study. Therefore, the true measure of each project’s value is their
net benefit to the Railbelt utilities and consumers, that is the economic benefit minus the cost of construction. It
is also important to note that the impact these large construction projects would have on the State’s economy
are not estimated or included in the evaluations. The potential impact of these projects include design and
construction using Alaskan labor, and an increased ability of the transmission system to serve additional loads
or make use of renewable energy.
This report is not a mandate to construct these projects, but rather should be considered the first step in the
transmission planning process outlined in the recently completed transmission planning standard, specifically
AKTPL-001-4. Each of the projects must undergo further cost and benefit analysis prior to making the decision
to construct each project. Some projects may be deemed feasible and constructed following the assessment
and others may be put on hold until economic or other conditions warrant their construction.
As the projects are evaluated going forward, the value of unserved energ y, the value of renewable energy, the
value of future load-serving capability, the value of capacity sharing or deferral and the value of a significant
reduction in greenhouse gasses should be computed and utilized in each projects’ analysis. However, some of
the projects are strictly reliability driven project s with little or very small hard economic benefits and can only be
justified by more traditional transmission evaluation methods. These projects should be evaluated separately
from the projects with large economic benefits.
The production cost runs for the existing system assumed the Anchorage-Kenai transmission line was available
100% of the time. However, in the last 10 years, the line has been out of service almost one month out of every
year. If considered in the evaluations, the line outages would increase the production costs of the existing system
and increase the benefits of the proposed transmission system.
The fuel usage with the proposed transmission system resulted in annual savings ranging from $34,752,000 per
year for the low load cases to $83,040,000 per year for the high load cases, with the base case savings being
$55,885,000 per year (in 2030 dollars). Fuel prices do not have a marked influence on the overall fuel savings,
provided the difference between Fairbanks and Southcentral energy prices remain relatively stable. The wide
range in system fuel savings is more a product of the uncertainty in utility load forecasts as opposed to ranges
in the cost of fuel.
Historically, the Bradley Lake participants have received an average of 49,466 MWH/year of Bradley Lake energy
when the project is operated at an output above 90 MW in order to avoid spilling water. That energy will be
unavailable if the Kenai transmission constraints are enacted without mitigation. Further, the utilities have
received 173,884 MWh/year of energy when Bradley Lake is operated at an output above 65 MW. The energy
availability when Bradley is operated above 65 MW is at risk utilizing the existing transmission system. While
the energy Bradley can produce when it is operated between 65 and 90 MW could be utilized by the utilities, it
may not be utilized at a time that provides the same economic benefit as its historical use.
Since 2000, the Railbelt utilities have added various generation plants located within their own service territories
to replace aging generation infrastructure. The capital costs of replacing these plants over the life of the
transmission system was not included in the transmission benefits. At the earliest time the projects
recommended in this plan could be completed, the newest plants in Fairbanks and Southcentral Alaska will be
25 and 15 years old, base-loaded plants on the Kenai will be approaching 50 years old for the frame 6 gas
turbine and the base-loaded steam boiler will be 30 years old. All of these plants will be in the process of
requiring replacement or significant refurbishment as the transmission projects are put in service. Without
additional transmission improvements, generation planning will continue to be completed by individual utilities,
located in geographically dispersed areas. Capacity sharing and deferral will be limited by the existing
transmission system and customer rates will not be at their lowest possible level.
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The economic benefit of improved reliability as measured by unserved energy, capacity deferral of individual
utilities, and reservoir optimization of the Bradley Lake and Cooper Lake hydro plants, made possible with the
improved transmission system, were not evaluated in this report.
Additional production cost simulations were completed to determine the sensitivity of the project benefits to
several different conditions. These sensitivities included differing fuel prices in the Railbelt, LNG availability in
the Fairbanks area, new units in the Fairbanks area, loss of existing load, and addition of new loads in the
system. The sensitivity cases indicate that the availability of LNG at GVEA’s North Pole and the construction of
a new combined cycle unit and six 9 MW reciprocating engines at North Pole results in the lowest savings for
the transmission system at $34,959,000/year (2030 $). However, this low level of savings can only be
experienced after the large capital expenditure for LNG and a new power plant with additional generation
installed at the North Pole facility. Absent this large capital expenditure, the next lowest sensitivity is the loss of
44 MW of load in the Fairbanks area and little or no load growth over the next 50 years, with an associated
savings of $34,752,000/year (2030 $). Sensitivities in gas pricing do not have an appreciable impact on the base
case savings. The retirement of Healy #1 and the Aurora plant in Fairbanks do not have an appreciable impact
on the transmission benefits since the existing system can support additional non-firm sales.
The introduction of LNG into GVEA’s North Pole plant, without an additional unit does not have an appreciable
impact on the transmission benefits.
The only scenario where the benefit/cost ratio is less than 1.0 is the case where LNG is used for the new units,
a new power plant and the existing power plant at North Pole.
A summary of the sensitivity cases is presented in the Table 2-3.
Table 2-3: Sensitivity Case
Scenario Total Pool Load Existing Transmission
Annual GWh
Firm Transmission Non-Firm Transmission
Adjusted Base Case 5202.7 508,524 452,639 452,274 55,885 365
High Load 5202.7 + 573.0 654,571 571,531 543,420 83,040 28,111
Low Load 5202.7 - 306.6 447,996 413,244 413,272 34,752 -28
Aurora & Healy 1 Retired 5202.7 563,792 473,618 472,950 90,175 668
LNG @ NPCC only 5202.7 501,622 452,601 452,424 49,021 177
High Fuel Cost 5202.7 692,556 638,244 638,026 54,312 218
Low Fuel Cost 5202.7 389,489 342,606 342,505 46,883 101
Re-Build of North Pole 5202.7 509,575 474,616 474,549 34,959 67
Annual Savings - K$Annual Production Costs - K$
Upgraded Transmission
Full Pooling From Firm
Transmission
From Non-Firm
Transmission
Full Pooling Non-Firm
Transmission
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December 2, 2016
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The range of benefit/cost ratios of the projects are seen in Table 2-4, where cost is in K$.
Table 2-4: Sensitivity Case Summaries
The recommended transmission plan meets the requirements of AKTPL-001-4 for system reliability and
contingency evaluation. However, AKTPL-001-4 also requires each project to be evaluated in terms of reliability
and costs to determine whether the project should be constructed. The evaluation required by the standard
includes the costs identified in this report, but also requires the identification of all benefits, including the benefits
not included in the scope of this project, such as generation capacity deferral, value of unserved energy, water
management, additional green energy, firm fuel and energy deliveries for all utilities, and Bradley excess energy
delivery.
It is recognized that both the costs and the benefits included in this report are estimates and that changes in
assumptions can alter the conclusions and recommendations. There are many assumptions and changes that
can be debated to decrease and increase both the costs and benefits of the recommended projects. The fuel
savings presented in this study represent only a 7-15% savings in total 2030 fuel costs over the entire Railbelt.
In formulation of RTOs and generation pooling in the lower 48, the US Department of Energy in its 2005 report
to Congress estimated the reduction in power production costs that could be achieved through economic
dispatch across various power pools ranged from 8-30%. In a 2013 DOE sponsored study for the Eastern
Interconnection State’s Planning Council and the National Association of Regulatory Utility Commissioners, it
Scenario Debt Service M & O Expense Total Costs Benefits
Benefit/Cos
t Ratio
2030 dollars ($/Yr x 10^-3)($/Yr x 10^-3)($/Yr x 10^-3)($/Yr x 10^-3)
1 Base Case 1,531,228$ 588,609$ 2,119,837$ 3,427,333$ 1.62
2 High Load 1,531,228$ 588,609$ 2,119,837$ 4,805,687$ 2.27
3 Low Load 1,531,228$ 588,609$ 2,119,837$ 2,294,614$ 1.08
4 Aurora/Healy 1 Retired 1,531,228$ 588,609$ 2,119,837$ 3,389,772$ 1.60
5 LNG @NPCC only 1,531,228$ 588,609$ 2,119,837$ 3,072,960$ 1.45
6 High Fuel Cost 1,531,228$ 588,609$ 2,119,837$ 3,144,180$ 1.48
7 Low Fuel Cost 1,531,228$ 588,609$ 2,119,837$ 2,812,290$ 1.33
8 Re-build of North Pole 1,531,228$ 588,609$ 2,119,837$ 1,325,511$ 0.63
Scenario Debt Service M & O Expense Total Costs Benefits
Benefit/Cos
t Ratio
2015 dollars ($/Yr x 10^-3)($/Yr x 10^-3)($/Yr x 10^-3)($/Yr x 10^-3)
1 Base Case 1,132,163$ 435,207$ 1,567,370$ 2,534,109$ 1.62
2 High Load 1,132,163$ 435,207$ 1,567,370$ 3,553,240$ 2.27
3 Low Load 1,132,163$ 435,207$ 1,567,370$ 1,696,597$ 1.08
4 Aurora/Healy 1 Retired 1,132,163$ 435,207$ 1,567,370$ 2,506,338$ 1.60
5 LNG @NPCC only 1,132,163$ 435,207$ 1,567,370$ 2,272,092$ 1.45
6 High Fuel Cost 1,132,163$ 435,207$ 1,567,370$ 2,324,751$ 1.48
7 Low Fuel Cost 1,132,163$ 435,207$ 1,567,370$ 2,079,358$ 1.33
8 Re-build of North Pole 1,132,163$ 435,207$ 1,567,370$ 980,060$ 0.63
Note: All costs are discounted life cycle costs expressed in 2030
Note: All costs are discounted life cycle costs expressed in 2015
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was determined that having transmission assets allowing the transfer of power between regions could result in
a 10% decrease in capital costs of future generation and that transmission expansion can play a significant role
in generation capacity planning. Considering the wide variations in Railbelt generation investment, this savings
could appear even larger in the Alaskan grid in future years. Since the DOE study was completed in a
transmission system with few transmission constraints, achieving 7-15% fuel savings in the Railbelt after
relatively severe transmission constraints are relaxed appears significantly lower than savings indicated in
national studies and results.
3 Production Cost Simulations
3.1 The Structure of the Model
The model employed for these analyses was the PROMOD IV® power system production modeling program,
the core of which produces unit commitment and economic dispatch solutions. The particular configuration of
PROMOD for this work included the Hourly Monte Carlo, (HMC), module to simulate generator forced outages
and the Transmission Analysis Module, (“TAM”), to incorporate a branch-by-branch, bus-by-bus model of the
transmission system being studied. The use of these two modules represents the generation dispatch by a set
of deterministic hourly chronological values for each load, generation source and branch flow. This enables the
program to produce an economic dispatch that respects line and interface flow limits, survives contingencies, as
well as respecting the various system and generator constraints.
3.2 Assembling the Data
The data assembly for this configuration of PROMOD begins with importing, into the program, the “raw” file
resulting from a PSS/E load flow run of the transmission system involved in the analysis. The power flow data
is used by PROMOD to set up a bus-by-bus, branch-by-branch model of the system as part of its data.
System data is input to PROMOD to set up an organizational structure of areas, companies and pools and the
relationships among them. In addition, there are included requirements for operating, spinning and regulation
reserves for companies and/or pools.
The individual generation resources are “mapped” to their appropriate busbars in the transmission data, then the
data describing the ownership, nature, operating characteristics and operating costs of each generating resource
are loaded into the production modeling data Tables. Most operating data can vary on a monthly basis, but
where necessary specific items can vary hourly or daily. This data includes fuels, emissions and non-fuel
operation and maintenance costs.
Data defining a particular run is also input to the program and includes the nature of the run, the period involved
and the outputs required. All of the data input up to this point is stored in a data file written in the program’s
portable file format, (“.PFF”).
Load data, including weekly peak load & energy and hourly load shape for each area is provided in a separate
file, which is read into PROMOD at the time of execution. PROMOD converts this data into hour-by-hour
Company loads that it “maps” to the load busses. Also read in at execution, is a file of information, (the EVENT
file,) concerning the various line and interface flow limits and contingencies to be obeyed and considered in
developing a least cost dispatch.
Because two different transmission systems were involved in this study, the existing transmission and the
upgraded transmission, two different Transmission/Production datasets were created as described above, as
well as two different Event files. Only one Load file was required.
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3.3 Data Sources
EPS provided the PSS/E raw files for the two transmission systems, as well as a description of the reserve
requirements and transmission flow limitations for the two cases.
With the exception of the fuel price data, the production data was mainly the result of the modeling process
recently carried out with the utilities as part of the activities of their Economic Dispatch Group, (“EDG”). The
exception being the updated transmission constraints produced by the new PSS/e model and the inclusion of
transmission constraints between Healy and Fairbanks for the existing system that were omitted in the EDG
model.
Because the EDG data was developed for the 2020 year, and this study was being performed for the year 2030,
various cost items such as Variable O&M costs and Natural Gas transportation costs had to be escalated. The
year-to-year escalation rates used for this task were the GDP deflators implicit in the Tables of the projected fuel
price information found in the Energy Information Administration’s, (“EIA’s”), 2016 Annual Energy Outlook,
(“AEO”), Reference Case.
The load projection used in the Base Case of this study was based on the EDG load projections, but were not
as pessimistic. The lower load levels of the EDG study formed the low load case in this study. The non-mining
load was escalated from 2020 to 2030 at very low rates, which were different for each company, and the Fort
Knox mine was assumed to remain in production. The low load scenario in this study assumed Ft. Knox would
close and the high load scenario assumed that the Livengood Mine would be developed by 2030 and the Fort
Knox load would remain on the GVEA system.
The Fuel prices in the Base Case were derived from the 2020 EDG fuel prices with adjustments intended to
remove the effect of current contracting and adjustments to include the price movements in the EIA 2016 AEO
Reference Case. High and Low price projections made use of two other AEO cases, as recorded in Section 3.4
below. Discussions were also held with Mapco refinery to assess the probability of the current GVEA pricing
structure remaining constant through the study period. Based on these discussions, it was determined that the
GVEA fuel pricing could not be guaranteed through the life of this study and market costs for fuel was used.
Details of the Base Case and sensitivity runs developed in this study are in the following Section 3.4.
3.4 Base Case and Sensitivities
Eight Cases were developed to explore the value of the transmission upgrades in alternative future conditions.
The alternatives were made up of various cases for loads, fuel costs and generation resources, as shown in
Tables 5-1 and 5-2.
Table 5-1: Load Alternatives
Sensitivity Load Fuel Costs Resources
Base Case Base Case Base Case Base Case
High Load High Load Base Case Base Case
Low Load Low Load Base Case Base Case
Retire Old Coal Base Case Base Case Ret. Aurora-Healy 1
LNG for NPCC Base Case Base Case LNG for NPCC
High Fuel Base Case High Fuel Cost Base Case
Low Fuel Base Case Low Fuel Cost Base Case
Rebuild North Pole Base Case Base Case Rebuild North Pole
3.5 Loads
Table 5-2: Load Sensitivities
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GWh
Year 2020 Railbelt GVEA MEA ML&P CEA/SES HEA
Base Case 5078.6 1467.9 782.0 1079.8 1283.9 465.1
Lower Load
Sensitivity 4771.2 1160.5 782.0 1079.8 1283.9 465.1
Higher Load
Sensitivity 5653.2 2042.5 782.0 1079.8 1283.9 465.1
Year 2030
Base Case 5175.4 1491.3 813.8 1090.6 1309.8 469.8
Lower Load
Sensitivity 4868.0 1183.9 813.8 1090.6 1309.8 469.8
Higher Load
Sensitivity 5750.0 2065.9 813.8 1090.6 1309.8 469.8
Notes
1 The Lower Load sensitivity represents the loss of the GVEA Fort Knox mine load.
2 The Base Case load represents the retention of Fort Knox load
3 The Higher Load sensitivity represents the addition of the Livengood mine load to GVEA’s load.
4 The remainder of GVEA’s load is grown at a rate of 0.2 %/year.
5 MEA, ML&P, CEA/SES and HEA loads are grown at 0.4, 0.1, 0.2 and 0.1 %/year respectively.
3.6 Escalation
As a general escalation rate, used for cost items such as non-fuel operation and maintenance expense and
natural gas transportation costs, the GDP deflator, used by the EIA in the 2016 AEO Reference Case, was
chosen (Table 5-3).
Table 5-3: Escalation Rates
Year GDP
Deflator
2016 2.04
2017 2.04
2018 2.04
2019 2.04
2020 2.04
2021 2.06
2022 2.06
2023 2.06
2024 2.06
2025 2.06
2026 2.00
2027 2.00
2028 2.00
2029 2.00
2030 2.00
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3.7 Fuel Prices – Base Case
The Base Case fuel prices were first developed for the year 2020 from the fuel prices contributed by the utilities.
As far as possible, the effects of contract timing and short term special deals were removed from the individual
utility projections. Commodity price changes beyond 2020 were derived for the individual fuels from the
“Reference case” projections of the EIA’s 2016 AEO. Table 5-4 shows Base Case projections for 2020 and
2030. NG delivery was escalated at the GDP deflator.
Table 5-4: Base Case Projections
Fuel Item Location 2020 Price
c/mmBTU
2030 Price
c/mmBTU
Coal 397 485.4
NG - Commodity 750 1075
NG -
Transportation
Beluga, Bernice, Nikiski 48.875 59.754
Uklutna GS 50.0 61.129
MLP, MLP2A 32.5 39.734
Soldotna 66.175 80.904
SPP 20.0 24.452
Naptha 1413 2207.7
ULSD Most locations 1815 2818.8
Delta, Small Diesels 1900 2950.8
3.8 Fuel Prices – Sensitivities
The source material for the High and Low Fuel Price sensitivities came from comparison Tables for three case
projections that were part of the EIA’s 2016 Annual Energy Outlook. The three cases were the Reference Case
which was the basis for the Base Case Fuel Prices, the “Low Oil and Gas Resource and Technology Case,”
which provided the basis for the High Fuel Price sensitivity, and the “High Oil and Gas Resource and Technology
Case,” which provided the basis for the Low Fuel Price sensitivity. The 2030 prices for the sensitivities are
shown in Table 5-5.
Table 5-5: 2030 Fuel Prices – c/mmBTU
Fuel Item Location Low Price
Sensitivity
High Price
Sensitivity
Coal 466.5 511.9
NG - Commodity 729.2 1665.9
NG -
Transportation
As in Base Case
Naptha 1725.7 2489.1
ULSD Most locations 2203.3 3177.9
Delta, Small Diesels 2306.5 3326.8
3.9 The Consistency of the Modeling
The original intent in performing the production cost simulation studies was to utilize the ProMod model
developed by the Railbelt utilities as part of their studies on power pooling and unified system operator studies.
Slater had recently performed dispatch analyses of the Railbelt System for the Utilities’ Economic Dispatch
Group, (EDG,) aimed at exploring the benefits of pooled operation in the 2020 year. Accordingly, it was advisable
to show that the modeling for this study was consistent with the modeling in the EDG work.
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However, after completing a benchmark study to show the model proposed for this study produced similar results
to the work completed by the utilities, there were several major errors uncovered in the original model that formed
the basis for the comparison. The errors are summarized as follows:
The original model had no transmission constraint between Healy and Fairbanks, potentially allowing
more transactions than were physically possible. The transmission constraints were inserted into the
model for both the existing and proposed transmission system.
GVEA’s Fort Knox load was intended to be removed from the model, but the load was relocated to the
Healy area and load in the Fairbanks area reduced to maintain the desired overall load. The result was
that more load was served out of Healy and did not need to utilize the Healy – Fairbanks transmission
system. This was corrected and the GVEA load was correctly modeled in the final simulations.
The transmission constraints between Anchorage – Healy were incorrectly applied, artificially restricting
transfers from south to north. The constraints were corrected and resulted in a significant increase in
transfers to GVEA.
The final model has considerable changes that were not anticipated at the start of the project. We would
encourage the utilities to take ownership of the model and update any system modifications within the model to
continue to refine its accuracy.
3.10 Resource Sensitivities
In addition to the four sensitivities involving variation in system load and fuel costs, three sensitivities were
examined which dealt with changes to generation resources. The first of these, “Retire Old Coal” made no
changes to loads or fuel cost, but retired, prior to 2030, the two old coal fired resources, the Aurora Energy LLC
units in the Fairbanks area and the GVEA Healy 1 unit. In this sensitivity, no generating capacity was added to
replace the old coal capacity.
The second resource sensitivity involved changing the fuel for the North Pole combined cycle unit from Na ptha
to LNG shipped into Fairbanks. In this sensitivity, the price of the LNG was set at 1300 c/mmBTU in 2020,
escalating to 1863.33 c/mmBTU in 2030.
The third resource sensitivity involved major changes to GVEA generation prior to 2030. The old coal uni ts
(Aurora and Healy 1) would be retired, along with the two old CT’s at North Pole. A second combustion turbine
would be added to the North Pole combined cycle unit, and six 9 MW Wartsila Diesel generators would also be
installed at North Pole.
An new LNG supply is required to fuel all generation at the North Pole generating station. The cost of the LNG
supply or the cost of the new generators and power plant are not included in this analysis.
3.11 Results of this Analysis
For each of the Base Case and seven sensitivities, two computer model runs were made. The first, “Existing
Transmission – Full Pooling” was developed to simulate a fully pooled system with minimal hurdles between
utilities. Although the utilities are far from this type of arrangement, this insures that any changes in production
cost simulations are the result of the transmission improvements as opposed to the benefits of increased pooling.
The hurdles were set at 1/MWh for commitment and $1/MWh for dispatch. These hurdle values don’t represent
any actual economic relationships among the utilities, but were set at these values to achieve the “full pool”
behavior described above.
The third model run for each case, “Upgraded Transmission – Full Pooling,” was set up the same way as the
fully pooled model run, described above, except that the data bases, including EVENT files, were those created
on the power flow data for the upgraded transmission. The differences between the runs were recorded as the
benefits of the upgraded transmission.
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Table 5-8 shows the production cost results for each modeled case, while Table 5-9 records the atmospheric
emissions for each case, and Table 5-10 displays the transmission losses.
Table 5-8: Production Costs for Each Modeled Case
Scenario Total Pool Load Existing Transmission
Annual GWh
Firm Transmission Non-Firm Transmission
Adjusted Base Case 5202.7 508,524 452,639 452,274 55,885 365
High Load 5202.7 + 573.0 654,571 571,531 543,420 83,040 28,111
Low Load 5202.7 - 306.6 447,996 413,244 413,272 34,752 -28
Aurora & Healy 1 Retired 5202.7 563,792 473,618 472,950 90,175 668
LNG @ NPCC only 5202.7 501,622 452,601 452,424 49,021 177
High Fuel Cost 5202.7 692,556 638,244 638,026 54,312 218
Low Fuel Cost 5202.7 389,489 342,606 342,505 46,883 101
Re-Build of North Pole 5202.7 509,575 474,616 474,549 34,959 67
Annual Savings - K$Annual Production Costs - K$
Upgraded Transmission
Full Pooling From Firm
Transmission
From Non-Firm
Transmission
Full Pooling Non-Firm
Transmission
Alaska Energy Authority
Railbelt Transmission Plan – Final Draft
December 2, 2016
Page 11
Table 5-9: Transmission Losses for Different Cases
Scenario Debt Service M & O Expense Total Costs Benefits
Benefit/Cos
t Ratio
2030 dollars ($/Yr x 10^-3)($/Yr x 10^-3)($/Yr x 10^-3)($/Yr x 10^-3)
1 Base Case 1,531,228$ 588,609$ 2,119,837$ 3,427,333$ 1.62
2 High Load 1,531,228$ 588,609$ 2,119,837$ 4,805,687$ 2.27
3 Low Load 1,531,228$ 588,609$ 2,119,837$ 2,294,614$ 1.08
4 Aurora/Healy 1 Retired 1,531,228$ 588,609$ 2,119,837$ 3,389,772$ 1.60
5 LNG @NPCC only 1,531,228$ 588,609$ 2,119,837$ 3,072,960$ 1.45
6 High Fuel Cost 1,531,228$ 588,609$ 2,119,837$ 3,144,180$ 1.48
7 Low Fuel Cost 1,531,228$ 588,609$ 2,119,837$ 2,812,290$ 1.33
8 Re-build of North Pole 1,531,228$ 588,609$ 2,119,837$ 1,325,511$ 0.63
Scenario Debt Service M & O Expense Total Costs Benefits
Benefit/Cos
t Ratio
2015 dollars ($/Yr x 10^-3)($/Yr x 10^-3)($/Yr x 10^-3)($/Yr x 10^-3)
1 Base Case 1,132,163$ 435,207$ 1,567,370$ 2,534,109$ 1.62
2 High Load 1,132,163$ 435,207$ 1,567,370$ 3,553,240$ 2.27
3 Low Load 1,132,163$ 435,207$ 1,567,370$ 1,696,597$ 1.08
4 Aurora/Healy 1 Retired 1,132,163$ 435,207$ 1,567,370$ 2,506,338$ 1.60
5 LNG @NPCC only 1,132,163$ 435,207$ 1,567,370$ 2,272,092$ 1.45
6 High Fuel Cost 1,132,163$ 435,207$ 1,567,370$ 2,324,751$ 1.48
7 Low Fuel Cost 1,132,163$ 435,207$ 1,567,370$ 2,079,358$ 1.33
8 Re-build of North Pole 1,132,163$ 435,207$ 1,567,370$ 980,060$ 0.63
Note: All costs are discounted life cycle costs expressed in 2030
Note: All costs are discounted life cycle costs expressed in 2015
Alaska Energy Authority
Railbelt Transmission Plan – Final Draft
December 2, 2016
Page 12
A Appendix: A Cost/Benefit Notes and Summary
A.1 Notes on Benefit/Cost Ratios
The costs completed for these projects were developed based on a 2015 cost basis using information supplied
by various Railbelt utilities and conceptual designs for each project. The cost estimates are estimated to be +/-
20% of actual construction costs. The project costs were reviewed in 2015 and appear to be within the +/- 20%
range of project construction costs.
The production cost benefits for the projects are simplified simulations based on one year of the project’s
operation. The identified benefits are assumed to be constant for the life of the project. The actual ben efit of
any project will vary over time as energy resources, load, transmission lines and operating practices change in
the Railbelt.
The development of benefits for individual projects was not completed for this final phase of the study. The intent
of this study was to develop a transmission plan compliant with the initial steps of AKTLP 1-4. Within that
standard, once a project has been identified, additional studies and cost/benefit analysis is required prior to
construction of the project.
The Benefit/Cost Analysis was completed in accordance with the guidelines of Circular A-94 “Guidelines and
Discount Rates for Benefit-Cost Analysis of Federal Programs”. It utilized a discount of 1.5% and a cost of debt
of 4.0% and cost of O&M of 1.5%/year. The O&M assumed no benefit in O&M for the replacement of aged
infrastructure.
The actual construction of the projects will consume 10-15 years and as such the construction sequence will
have an impact on the benefits available for each project. Certain projects for instance, depend on other projects
being constructed in order to obtain the identified benefits. For the feasibility level analysis completed in this
study, it was assumed all projects were available in year one.
Benefits associated with capacity deferral allowed by an improved transmission system, improved hydro water
management and efficiency, increased use of renewables, decrease in greenhouse gas emissions, value of
unserved energy, Bradley Lake excess energy delivery, and the ability to contract for firm energy and fuel
deliveries throughout the system are not included within the scope of this project, but should be included in the
project evaluations completed for AKTPL-001-4.
A.2 Loss/Energy/Capacity
The following table summarizes the historical usage of Bradley Lake energy compared to the current use of the
project.
Alaska Energy Authority
Railbelt Transmission Plan – Final Draft
December 2, 2016
Page 13
Table A-1: Historically Displaced Energy
Table A-2: Left intentionally blank
Annual
MWh
Historical
losses
Projected
Losses Difference
HEA energy 47,289 946 1,419 473
Northern users 193,973 3,879 21,337 17,458
Battle Creek - HEA 4,680 0 140 140
Battle Creek - Northern Users 34,320 0 3,775 3,775
Wheeled energy 152,738 4,582 16,801 12,219
Total energy losses 34,065
Historically wheeled energy to Northern users (MWh)
Historically Displaced Energy (MWh)
Alaska Energy Authority
Railbelt Transmission Plan – Final Draft
December 2, 2016
Page 14
Table A-3: Kenai Loss Analysis
base upgraded base upgraded
University Indian 1 1.0 0.3 1.8 0.5
Indian Girdwood 1 0.6 0.2 1.2 0.3
Girdwood Portage 1 0.5 0.2 1.0 0.4
Portage Hope 1 1.4 0.4 2.6 0.7
Hope Daves Creek 1 1.3 0.3 2.2 0.6
Daves Creek Quartz Creek 1 0.7 0.2 1.1 0.3
Quartz Creek XFMR 1 no line 0.0 no line 0.0
Quartz Creek Soldotna 1 3.7 1.0 6.7 1.8
Quartz Creek Soldotna 2 no line 1.0 no line 1.8
9.2 3.4 16.7 6.2
Soldotna Bradley Lake 1 2.2 0.8 4.2 1.5
Soldotna Bradley Lake 2 no line 0.8 no line 1.5
2.2 1.5 4.2 3.0
Soldotna Thompson 1 0.0 0.0 0.0 0.0
Thompson Kasilof 1 0.0 0.0 0.2 0.0
Kasilof Anchor Pt 1 0.4 0.1 1.0 0.3
Anchor Pt Diamond Ridge 1 0.2 0.1 0.4 0.1
Diamond Ridge Fritz Crk 1 0.2 0.1 0.3 0.1
Fritz Crk Bradley Lk 1 0.7 0.4 1.1 0.6
1.6 0.7 3.0 1.1
12.9 5.6 23.9 10.3
77.6 81.5 100.2 107.6
-3.4 -2.7 -8.8 -7.3
-3.9 -3.1 -9.2 -7.7
39.5 20.2 51.5 24.0
42.9 22.9 60.3 31.3
Notes:
Cooper Lake unit 1 online, at 9.8 MW
Cooper Lake unit 2 online, at 9.8 MW
only changes are Bradley Lake output
swing bus at Beluga 7
tie flow measured on Dave's Creek - Hope line
HEA taking 14.4 MW of Bradley Lake
Total: University - Bradley Lake (All Lines)
Kenai tie flow
SPP 138 kV angle
University 138 kV angle
Bradley Lake 115 kV angle
Subotal: University - Soldotna
Subtotal: Soldotna - Bradley Lake
Subtotal: Soldotna - Bradley Lake
Kenai Loss Analysis
Bradley Output
90 120From Bus To Bus Ckt ID
Values Line Losses / Bus Angles
20.0 28.9Reduction of angle
Angle Difference Bradley Lake - SPP
Reduction of losses 7.3 13.6
Alaska Energy Authority
Railbelt Transmission Plan – Final Draft
December 2, 2016
Page 15
B Appendix B: Economic Analysis Sensitivity
Scenario Total Pool Load Existing Transmission
Annual GWh
Firm Transmission Non-Firm Transmission
Adjusted Base Case 5202.7 508,524 452,639 452,274 55,885 365
High Load 5202.7 + 573.0 654,571 571,531 543,420 83,040 28,111
Low Load 5202.7 - 306.6 447,996 413,244 413,272 34,752 -28
Aurora & Healy 1 Retired 5202.7 563,792 473,618 472,950 90,175 668
LNG @ NPCC only 5202.7 501,622 452,601 452,424 49,021 177
High Fuel Cost 5202.7 692,556 638,244 638,026 54,312 218
Low Fuel Cost 5202.7 389,489 342,606 342,505 46,883 101
Re-Build of North Pole 5202.7 509,575 474,616 474,549 34,959 67
Annual Savings - K$Annual Production Costs - K$
Upgraded Transmission
Full Pooling From Firm
Transmission
From Non-Firm
Transmission
Full Pooling Non-Firm
Transmission
Alaska Energy Authority
Railbelt Transmission Plan – Final Draft
December 2, 2016
Page 16
Adjusted Base Case -Base Case plus Updates to HEA (Increase Load by 6%, adjustment to Soldotna, Import limit changed to 18 MW (Existing Transmission))
Existing Transmission Upgraded Transmission Upgraded Transmission From Upgraded From Transmision Existing Transmission Upgraded Transmission Upgraded Transmission Existing Transmission Upgraded TransmissionUpgraded Transmission
Full Pooling Full Pooling Full Pooling Transmission Constraints Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling
Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained
System 508,524 452,639 452,274 55,885 365 0.0 0.0 0.0 8.1 0.0 0.0
GVEA 211,298 184,798 184,687 26,501 110 371.0 587.2 589.3 33.4 0.0 0.0
MEA 79,051 71,639 71,556 7,412 83 -128.0 -112.6 -113.4 219.4 23.9 22.0
ML&P 62,770 50,278 50,090 12,492 188 -482.5 -470.2 -471.3 0.0 0.0 0.0
CEA + SES 103,013 103,065 103,094 -52 -29 108.3 115.3 115.6 0.0 0.0 0.0
HEA 52,392 42,858 42,846 9,534 12 131.4 -119.8 -120.3
371.1 587.3 589.4
-0.1 -0.1 -0.1
High Load
Existing Transmission Upgraded Transmission Upgraded Transmission From Upgraded From Transmision Existing Transmission Upgraded Transmission Upgraded Transmission Existing Transmission Upgraded TransmissionUpgraded Transmission
Full Pooling Full Pooling Full Pooling Transmission Constraints Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling
Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained
System 654,571 571,531 543,420 83,040 28,111 0.0 0.0 0.0 87.6 9.0 0.0
GVEA 371,304 328,090 306,438 43,214 21,652 426.6 923.7 1,124.9 271.5 47.0 0.9
MEA 73,853 60,051 60,744 13,802 -693 -177.3 -300.7 -307.9 401.1 215.9 81.2
ML&P 54,277 40,421 37,192 13,856 3,229 -480.0 -586.3 -692.6 2.4 0.0 0.0
CEA + SES 102,419 103,509 105,403 -1,090 -1,894 108.2 112.7 114.3 5.2 0.0 0.0
HEA 52,719 39,461 33,643 13,258 5,817 122.5 -149.4 -238.9
426.6 923.7 1,124.9
0.0 0.0 0.0
Low Load
Existing Transmission Upgraded Transmission Upgraded Transmission From Upgraded From Transmision Existing Transmission Upgraded Transmission Upgraded Transmission Existing Transmission Upgraded TransmissionUpgraded Transmission
Full Pooling Full Pooling Full Pooling Transmission Constraints Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling
Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained
System 447,996 413,244 413,272 34,752 -28 0.0 0.0 0.0 1.3 0.0 0.0
GVEA 141,817 129,547 129,518 12,270 29 175.7 291.2 291.3 5.8 0.0 0.0
MEA 81,227 75,188 75,300 6,039 -113 -3.0 103.2 104.5 128.2 5.6 5.5
ML&P 70,303 60,088 60,071 10,215 17 -437.3 -430.4 -432.6 0.0 0.0 0.0
CEA + SES 102,737 102,990 102,966 -253 24 116.5 122.6 122.6 0.0 0.0 0.0
HEA 51,912 45,432 45,418 6,481 14 148.1 -86.5 -85.8
188.6 299.5 299.6
-12.9 -8.3 -8.3
Aurora & Healy 1 Retired
Existing Transmission Upgraded Transmission Upgraded Transmission From Upgraded From Transmision Existing Transmission Upgraded Transmission Upgraded Transmission Existing Transmission Upgraded TransmissionUpgraded Transmission
Full Pooling Full Pooling Full Pooling Transmission Constraints Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling
Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained
System 563,792 473,618 472,950 90,175 668 0.0 0.0 0.0 47.3 0.3 0.0
GVEA 278,296 229,209 227,321 49,087 1,888 450.3 963.1 960.7 128.7 0.8 0.0
MEA 74,606 59,532 60,471 15,075 -939 -187.4 -319.4 -311.7 399.3 56.9 60.4
ML&P 56,511 41,239 41,320 15,273 -81 -490.9 -596.4 -602.7 0.3 0.0 0.0
CEA + SES 102,499 103,956 103,986 -1,457 -30 106.8 111.8 112.1 0.3 0.0 0.0
HEA 51,880 39,683 39,852 12,197 -169 121.1 -159.1 -158.4
450.3 963.1 960.7
0.0 0.0 0.0
LNG @ NPCC only
Existing Transmission Upgraded Transmission Upgraded Transmission From Upgraded From Transmision Existing Transmission Upgraded Transmission Upgraded Transmission Existing Transmission Upgraded TransmissionUpgraded Transmission
Full Pooling Full Pooling Full Pooling Transmission Constraints Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling
Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained
System 501,622 452,601 452,424 49,021 177 0.0 0.0 0.0 7.6 0.0 0.0
GVEA 203,596 182,144 182,062 21,452 82 366.2 577.5 578.8 32.9 0.0 0.0
MEA 78,943 72,139 72,262 6,804 -123 -131.8 -109.5 -108.3 224.6 33.4 32.2
ML&P 63,242 51,696 51,733 11,546 -37 -475.9 -466.8 -466.9 0.0 0.0 0.0
CEA + SES 103,317 103,144 103,118 173 26 108.8 114.8 115.4 0.0 0.0 0.0
HEA 52,524 43,478 43,249 9,046 229 132.6 -115.9 -118.9
366.3 577.6 578.9
-0.1 -0.1 -0.1
High Fuel Cost
Existing Transmission Upgraded Transmission Upgraded Transmission From Upgraded From Transmision Existing Transmission Upgraded Transmission Upgraded Transmission Existing Transmission Upgraded TransmissionUpgraded Transmission
Full Pooling Full Pooling Full Pooling Transmission Constraints Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling
Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained
System 692,556 638,244 638,026 54,312 218 0.0 0.0 0.0 15.7 0.1 0.0
GVEA 239,288 212,533 212,321 26,754 213 343.7 568.4 568.8 36.0 1.0 0.9
MEA 116,873 109,544 109,581 7,329 -37 -135.3 -121.9 -121.6 234.1 40.8 40.6
ML&P 104,275 91,762 91,794 12,513 -32 -457.0 -460.6 -461.0 0.0 0.0 0.0
CEA + SES 153,868 155,064 155,032 -1,197 32 114.4 116.2 116.3 0.0 0.0 0.0
HEA 78,253 69,342 69,299 8,912 43 134.3 -102.3 -102.7
344.1 568.5 568.9
-0.4 -0.1 -0.1
Low Fuel Cost
Existing Transmission Upgraded Transmission Upgraded Transmission From Upgraded From Transmision Existing Transmission Upgraded Transmission Upgraded Transmission Existing Transmission Upgraded TransmissionUpgraded Transmission
Full Pooling Full Pooling Full Pooling Transmission Constraints Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling
Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained
System 389,489 342,606 342,505 46,883 101 0.0 0.0 0.0 5.8 0.0 0.0
GVEA 178,218 156,182 156,095 22,036 87 383.2 601.6 601.7 33.1 0.0 0.0
MEA 58,305 51,937 52,114 6,368 -177 -121.0 -108.3 -105.7 220.1 15.4 15.3
ML&P 42,711 32,443 32,360 10,267 84 -495.5 -482.4 -484.4 0.0 0.0 0.0
CEA + SES 73,223 72,763 72,748 460 15 102.2 114.1 114.3 0.0 0.0 0.0
HEA 37,033 29,281 29,188 7,752 93 131.0 -125.0 -126.0
383.3 601.6 601.7
-0.1 0.0 0.0
Re-Build of North Pole (New Units & LNG)
Existing Transmission Upgraded Transmission Upgraded Transmission From Upgraded From Transmision Existing Transmission Upgraded Transmission Upgraded Transmission Existing Transmission Upgraded TransmissionUpgraded Transmission
Full Pooling Full Pooling Full Pooling Transmission Constraints Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling Full Pooling
Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained Existing Constraints Proposed Constraints Unconstrained
System 509,575 474,616 474,549 34,959 67 0.0 0.0 0.0 159.1 16.3 16.4
GVEA 215,732 208,175 208,148 7,557 27 410.9 781.6 781.1
MEA 77,672 68,204 68,246 9,468 -42 -185.1 -283.6 -283.9 457.1 216.0 216.4
ML&P 62,082 52,604 52,608 9,479 -4 -462.6 -472.0 -471.6 0.0 0.0 0.0
CEA + SES 102,569 103,214 103,198 -645 16 107.0 112.9 114.2 0.1 0.0 0.0
HEA 51,520 42,420 42,350 9,100 70 129.7 -138.8 -139.6
410.9 781.6 781.1
0.0 0.0 0.0
Annual Production Costs - K$Annual Savings - K$Net Purchases - GWh GVEA CC, CT, Transactions - GWh
Annual Production Costs - K$Annual Savings - K$Net Purchases - GWh GVEA CC, CT, Transactions - GWh
Annual Production Costs - K$Annual Savings - K$Net Purchases - GWh GVEA CC, CT, Transactions - GWh
Annual Production Costs - K$Annual Savings - K$Net Purchases - GWh GVEA CC, CT, Transactions - GWh
Annual Production Costs - K$Annual Savings - K$Net Purchases - GWh GVEA CC, CT, Transactions - GWh
Annual Production Costs - K$Annual Savings - K$Net Purchases - GWh GVEA CC, CT, Transactions - GWh
Annual Production Costs - K$Annual Savings - K$Net Purchases - GWh GVEA CC, CT, Transactions - GWh
Annual Production Costs - K$Annual Savings - K$Net Purchases - GWh GVEA CC, CT, Transactions - GWh