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Susitna-Watana Hydroelectric Project Document
ARLIS Uniform Cover Page
Title:
Regional economic evaluation study, Study plan Section 15.5 : Initial study
report -- Part A: Sections 1-6, 8-10
SuWa 223
Author(s) – Personal:
Author(s) – Corporate:
Northern Economics, Inc. and Veritas Economic Consulting
AEA-identified category, if specified:
Initial study report
AEA-identified series, if specified:
Series (ARLIS-assigned report number):
Susitna-Watana Hydroelectric Project document number 223
Existing numbers on document:
Published by:
[Anchorage : Alaska Energy Authority, 2014]
Date published:
June 2014
Published for:
Alaska Energy Authority
Date or date range of report:
Volume and/or Part numbers:
Final or Draft status, as indicated:
Document type:
Pagination:
iii, 19, 16 p.
Related work(s):
The following parts of Section 15.5 appear in separate files:
Part A ; Part B ; Part C.
Pages added/changed by ARLIS:
Notes:
Contents: Part A. Sections 1-6, 8-10 -- Appendix A. Draft: Technical memorandum on long-term
modeling assumptions.
All reports in the Susitna-Watana Hydroelectric Project Document series include an ARLIS-
produced cover page and an ARLIS-assigned number for uniformity and citability. All reports
are posted online at http://www.arlis.org/resources/susitna-watana/
Susitna-Watana Hydroelectric Project
(FERC No. 14241)
Regional Economic Evaluation Study
Study Plan Section 15.5
Initial Study Report
Part A: Sections 1-6, 8-10
Prepared for
Alaska Energy Authority
Prepared by
Northern Economics, Inc. and Veritas Economic Consulting
June 2014
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
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FERC Project No. 14241 Part A - Page i June 2014
TABLE OF CONTENTS
1. Introduction ............................................................................................................................ 1
2. Study Objectives .................................................................................................................... 1
3. Study Area .............................................................................................................................. 1
4. Methods and Variances in 2013............................................................................................ 2
4.1. Data Collection and Analysis.................................................................................. 2
4.2. Variances ................................................................................................................. 2
5. Results ..................................................................................................................................... 2
5.1. Description of Current Power Generation, Transmission, and Demand ................ 3
5.2. REMI Model Development..................................................................................... 8
6. Discussion ............................................................................................................................... 9
7. Completing the Study ............................................................................................................ 9
8. Literature Cited ..................................................................................................................... 9
9. Tables .................................................................................................................................... 11
10. Figures .................................................................................................................................. 12
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FERC Project No. 14241 Part A - Page ii June 2014
LIST OF TABLES
Table 5.1-1. Railbelt Utilities Power Generation Facilities and Fuel Types ................................ 11
Table 5.1-2. Railbelt Utilities Fuel Use for Power Generation, 2011 ........................................... 12
Table 5.1-3. Railbelt Utilities Sales, 2011 .................................................................................... 12
LIST OF FIGURES
Figure 5.1-1. Railbelt Utilities Net Generation by Fuel Type ...................................................... 12
Figure 5.1-2. Average Annual Residential Electricity Rates by Utility, 2005-2012 .................... 13
Figure 5.1-3. Base Rate and Fuel and Purchased Power Components of a Residential Electrical
Bill by Railbelt Utility, Fourth Quarter 2009-2012 ............................................................... 14
Figure 5.1.1-1. Amount and Cost of Power Sold by Chugach Electric Association, 1990-2012 . 15
Figure 5.1.2-1. Amount and Cost of Power Sold by Municipal Light and Power ....................... 16
Figure 5.1.3-1. Amount and Cost of Power Sold by Golden Valley Electric Association ........... 17
Figure 5.1.4-1. Amount and Cost of Power Sold by Homer Electric Association ....................... 18
Figure 5.1.5-1. Amount and Cost of Power Sold by Matanuska Electric Association ................. 19
APPENDICES
Appendix A: Technical Memorandum on Long-Term Modeling Assumptions
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FERC Project No. 14241 Part A - Page iii June 2014
LIST OF ACRONYMS, ABBREVIATIONS, AND DEFINITIONS
Abbreviation Definition
AE Aurora Energy, LLC
AEA Alaska Energy Authority
CEA Chugach Electric Association
CIRI Cook Inlet Region, Inc.
FERC Federal Energy Regulatory Commission
GVEA Golden Valley Electric Association
GWh gigawatt hour
HAGO heavy atmospheric gas oil
HEA Homer Electric Association
ILP Integrated Licensing Process
kWh kilowatt hour
ISR Initial Study Report
MEA Matanuska Electric Association
ML&P Anchorage Municipal Power and Light
MW Megawatt(s)
Project Susitna-Watana Hydroelectric Project No. 14241
REMI Regional Economic Models, Inc.
RSP Revised Study Plan
SPD study plan determination
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FERC Project No. 14241 Part A - Page 1 June 2014
1. INTRODUCTION
On December 14, 2012, Alaska Energy Authority (AEA) filed with the Federal Energy
Regulatory Commission (FERC or Commission) its Revised Study Plan (RSP) for the Susitna-
Watana Hydroelectric Project No. 14241 (Project), which included 58 individual study plans
(AEA 2012). Section 15.5 of the RSP described the Regional Economic Evaluation Study. This
study focuses on assessing regional economics resulting from the operation of the proposed
Project and the power generated by the Project. RSP Section 15.5 provided goals, objectives, and
proposed methods for data collection regarding regional economics.
On February 1, 2013, FERC staff issued its study determination (February 1 Study Plan
Determination, SPD) for 44 of the 58 studies, approving 31 studies as filed and 13 with
modifications. RSP Section 15.5 was one of the 31 studies approved with no modifications.
Following the first study season, FERC’s regulations for the Integrated Licensing Process (ILP)
require AEA to “prepare and file with the Commission an initial study report describing its
overall progress in implementing the study plan and schedule and the data collected, including an
explanation of any variance from the study plan and schedule” (18 CFR 5.15(c)(1)). This Initial
Study Report on Regional Economic Evaluation Study has been prepared in accordance with
FERC’s ILP regulations and details AEA’s status in implementing the study, as set forth in the
FERC-approved RSP (referred to herein as the “Study Plan”).
2. STUDY OBJECTIVES
The goal of this study is to assess potential changes in regional economic conditions in the study
area resulting from the operation of the proposed Project and the power generated by the Project.
The study objectives are established in RSP Section 15.5.1 and include the following:
• Describe the effects of the Project on the regional economy resulting from improvements
in the reliability of the electrical power grid.
• Describe the effects of the Project on the stability of electric prices over time.
• Determine the economic effects of the Project’s power over time.
3. STUDY AREA
As established by RSP Section 15.5.3, the study area encompasses the region where the
economic impacts of the new energy source provided by Project operations will be concentrated.
This region is referred to as the Railbelt, which includes the Fairbanks North Star Borough,
Denali Borough, Matanuska-Susitna Borough, Municipality of Anchorage, and Kenai Peninsula
Borough.
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4. METHODS AND VARIANCES IN 2013
4.1. Data Collection and Analysis
AEA implemented the methods as described in the Study Plan (RSP Section 15.5.4) with no
variances. Information on current power generation, transmission, and demand in Alaska’s
Railbelt was obtained from the utilities or secondary sources and analyzed.
Information was compiled on existing generation facilities and historical trends in power
generation and sales for the major utilities in the Railbelt region. This region is defined as the
service areas of six interconnected utilities: Chugach Electric Association, Anchorage Municipal
Light & Power, Golden Valley Electric Association, Matanuska Electric Association, Homer
Electric Association, and Aurora Energy, LLC. The data collected to date provide a general
description of each utility in terms of the service area, primary fuels, installed capacity, and
amount and cost of power sold. Primary online data sources were the U.S. Energy Information
Administration’s websites for Form EIA-923 and Form EIA-826 information. The survey Form
EIA-923 collects detailed annual electric power data on electricity generation at the power plant
and prime mover level, while the survey Form EIA-826 collects annual retail sales of electricity
and associated revenue from a statistically chosen sample of electric utilities in the United States.
These data are current through 2012.
The forecast of socioeconomic conditions with and without the Project will be based in part on
estimates derived from a data and software program created by REMI (Regional Economic
Models, Inc.). The REMI model assumptions are being obtained from an information collection
process aimed at developing a consensus about long-term modeling assumptions with and
without the Project. Progress was made in developing the model assumptions by conducting
interviews with industry and government representatives who have experience and expertise in
the state’s leading industries and economic policy areas. All key informants were selected for
their first-hand knowledge about Alaska’s current socioeconomic environment, and for their
understanding of the socioeconomic opportunities and obstacles that the state may encounter in
the future. An attempt was made to obtain a diverse set of representatives with different
backgrounds and from different groups or sectors. This diversity provides a broad range of
perspectives. In addition, interviews were conducted with business representatives in the Railbelt
region to ascertain the potential for changes in business opportunities as a result of the new
energy source provided by the Project. The categories of organizations interviewed and examples
of interview questions are presented in Attachment 15-1 of the RSP.
4.2. Variances
No variances occurred when implementing the Study Plan in 2013.
5. RESULTS
As described in Section 4 above, efforts in 2013 focused primarily on collecting data on current
power generation, transmission, and demand in Alaska’s Railbelt. These data will provide
context for changes in regional economic conditions resulting from the power-related effects of
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FERC Project No. 14241 Part A - Page 3 June 2014
the Project. The preliminary results of this effort appear in Section 5.1. In addition, the study
team made progress in developing the REMI model. The preliminary results of this effort appear
in Section 5.2.
5.1. Description of Current Power Generation, Transmission, and
Demand
This section outlines information on existing generation facilities and historical trends in power
generation and sales for the major utilities in the Railbelt region. This region is defined as the
service areas of six interconnected utilities, including: Chugach Electric Association (CEA),
Anchorage Municipal Light & Power (ML&P), Golden Valley Electric Association (GVEA),
Matanuska Electric Association (MEA), Homer Electric Association (HEA), and Aurora Energy,
LLC (AE). Four of these utilities are cooperatives (CEA, GVEA, MEA, and HEA), one is a
municipal utility (ML&P), and one is a private company (AE). Together, these utilities
accounted for approximately 77 percent of the electricity produced statewide in 2011 (Fay et al.
2012).
The City of Seward Electric System currently has three diesel generators in operation, each with
capacities of 2.5 megawatts (MW), and one diesel generator with a capacity of 2.9 MW. In this
analysis, these small existing diesel generators are not included because the City of Seward is a
full requirements customer of Chugach and the existing diesels are mainly used for back-up. In
addition, Copper Valley Electric Association serves two small communities in the Railbelt
region, Lake Louise and Nelchina.
Table 5.1-1 provides a general description of these utilities in terms of power generation
facilities, primary fuels, and electricity net generation. As summarized in Figure 5.1-1, natural
gas is used to generate most of the electricity for the Railbelt, but the region also has significant
coal and hydroelectric capacity.
Railbelt utilities consume all of the coal, most of the natural gas, and around half of the fuel oil
used for power generation in Alaska (Table 5.1-2). With exception of GVEA, the utility that
provides service in the Fairbanks area, the fuel oil is used for stand-by generation. GVEA
depends significantly on both fuel oil and coal for power generation; about 99 percent of all the
fuel oil used in the Railbelt is consumed by GVEA, of which 71 percent is naphtha, 24 percent
heavy atmospheric gas oil (HAGO), and 5 percent distillate and residual fuel oil (Fay et al.
2012).
Among Railbelt utilities, the prime mover type with the largest share of installed capacity is
combustion gas turbines and combined cycle gas turbines, which together account for about 80
percent of net generation. Hydroelectric turbines and steam turbines had shares of 10 percent and
7 percent, respectively. Finally, wind turbines and internal combustion generators were the least
common prime movers, with shares of 2 percent or less.
As expected, most of the electricity sales in Alaska are by Railbelt utilities (Table 5.1-3).
However, the annual average use per residential customer is higher in the Southeast and North
Slope regions of the state. The North Slope region consumption is high because some
communities benefit from natural gas and the borough has a low flat rate structure per kilowatt
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hour (kWh) for all their communities. The Southeast region benefits from lower rates due to high
hydropower production financed in part with public funds (Fay et al. 2012). Railbelt utilities
accounted for about 77 percent of the electricity sold to commercial customers in Alaska. In
2011, the North Slope and Railbelt regions had the highest annual average use per commercial
customer of about 71,085 kWh and 70,987 kWh, respectively (Fay et al. 2012).
Figure 5.1-2 compares average annual residential electricity rates across Railbelt utilities from
2005 through 2012. CEA’s rate showed the least volatility during that time period, while
ML&P’s customers enjoyed the lowest rate due primarily to lower fuel costs. ML&P’s cost for
gas, which comes from its one-third ownership in the Beluga River Gas Field, is around half of
what other utilities pay privately owned producers of Cook Inlet natural gas (Bradner 2011). The
comparatively high rate paid by GVEA customers reflects the utility’s heavy reliance on oil-fired
generation. Rates have increased with rising crude oil prices and the subsequent increase in the
price of refined petroleum products.
Figure 5.1-3 expands the comparison of Railbelt utilities by identifying the fuel/purchased power
and base rate (non-fuel) components of a residential electrical bill effective fourth quarter 2009
to 2012. In 2012, fuel/purchased power made up about half of a typical GVEA residential bill,
but only 17 percent of a ML&P bill. Due to the rise in the price of fuel, especially diesel fuel,
fuel costs have come to represent a much larger portion of consumers’ electricity bills, as
compared to utilities’ base rates, which have remained relatively steady. However, some utilities
have periodically raised base rates to help fund major capital investment programs.
In comparison to the business and operating environment of the utility industry in the U.S., the
Railbelt region is unique. The overall size of the Railbelt region is small when compared to other
utilities or areas. The total combined peak load of all six utilities is approximately 1,600 MW.
When compared to the peak loads of other utilities throughout the U.S., a combined “Railbelt
utility” would still be relatively small. As an example, many electric utilities have single coal or
nuclear plants that exceed 900 MW of capacity (based on Energy Information Administration
plant data, there are 100 generating units in the U.S. with nameplate capacity greater than 900
MW) (Black & Veatch 2008).The Railbelt electric transmission grid is also unique. It has been
described as a long straw, as opposed to the integrated, interconnected, and redundant grid that is
in place throughout the lower-48 states. This characterization reflects the fact that the Railbelt
electric transmission grid is an isolated grid with no external interconnections to other areas and
that it is essentially a single transmission line running from Fairbanks to the Kenai Peninsula,
with limited total transfer capabilities and redundancies. As a consequence, each Railbelt utility
is required to maintain much higher generation reserve margins than elsewhere in order to ensure
reliability in the case of a transmission grid outage (Black & Veatch 2008). The leading cause of
outages among Railbelt utilities is associated with the transmission and distribution system.
However, while customers of Railbelt utilities lose power for an estimated 2 to 3 hours per year
(Thibert 2013), that still compares favorably with the nationwide annual average of 214 minutes
of outages per customer (Apt et al. 2006).
The following sections provide additional information on each major Railbelt utility, including
the service area, installed capacity, and amount and cost of power sold.
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Chugach Electric Association
In 2011, the net generation of the CEA reached over 2.3 million MWhs, nearly half of the total
net generation among major utilities. In 2012, the utility generated approximately 88 percent of
its power from Cook Inlet natural gas, 10 percent from hydro and 1 percent from wind (wind
comprises about 4 percent of retail energy) (Chugach Electric Association 2013). More than 90
percent of the electricity generated or purchased by CEA prior to 2013 came from the Beluga
River Power Plant, which is powered by combined cycle and natural gas and has a power rating
of 374.4 MW. Gas for the facility is delivered from the nearby Beluga River Gas Field, which is
jointly owned by ConocoPhillips, ML&P, and Hilcorp Energy, and via a Hilcorp Energy pipeline
from Granite Point. Two other CEA facilities that generate electricity using natural gas are the
International Airport Road Power Plant (46.3 MW) and Southcentral Power Plant (203.9 MW).
Since commissioning of the new Southcentral Power Plant, which is more efficient than the older
generators at Beluga, that plant has been used to generate a major portion of power requirements
for CEA and MLP.
One of CEA’s facilities, the Cooper Lake Power Plant (19.4 MW), is hydro-powered. CEA also
purchases the largest share of the power generated by the 126-MW Bradley Lake Hydroelectric
Plant near Homer. This facility provides 5 to 10 percent of the annual Railbelt electric power
need and is most important to the Railbelt electric system during the cold winter months when
demand for both electric power and natural gas for heat is at its highest. CEA and other utilities
limited by available natural gas are able to use Bradley Lake Hydroelectric Plant power to meet
the high electric demand (AEA 2013). CEA’s share of power generated by the Eklutna Lake
Hydroelectric Plant is 30 percent, up to an 11.7 MW maximum
In 2011, CEA signed an agreement with Cook Inlet Region Inc. (CIRI), an Alaska Native
regional corporation, to purchase power from CIRI’s 17.6-MW wind turbine project on Fire
Island, 3 miles off the coast of Anchorage. The facility began operating in late 2012, and it
offsets approximately 0.5 billion cubic feet of CEA’s natural gas consumption for power
generation (Fire Island Wind LLC 2013). However, that gas would have cost CEA about $2.4
million, while the wind power cost the utility $4.6 million. CEA retail customers pay a surcharge
for the wind energy, amounting to about $1.22 on a typical monthly residential bill (Bradner and
Bradner 2013). CIRI has started a $45 million expansion of the wind project, which is expected
to add 11 more turbines by 2015.
Figure 5.1.1-1 shows CEA’s volume and value of electricity sales by customer. Prior to 2009,
CEA purchased natural gas from four separate suppliers, and as gas supplies in Cook Inlet
declined, the price went up. From 2009 to the present, the price CEA paid was based on either a
basket of Lower 48 Production Area price points, as published in Platts Gas Daily, or on gas
futures on the New York Mercantile Exchange. U.S. gas prices have decreased since 2009 due
primarily to a large expansion of domestic production following improvements in drilling
technology that opened immense shale gas fields. As a result, CEA’s electricity rates have also
decreased. Residential and commercial sales declined in the late-2000s, possibly reflecting
increased energy efficiency. For example, during the past several years the Alaska Housing
Finance Corporation has offered programs to promote the energy efficiency of existing and
newly constructed homes.
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Municipal Light and Power
ML&P serves approximately 30,000 residential and commercial customers in a 20-square-mile
area in the northern portion of the Municipality of Anchorage, including the downtown central
business district, Mountain View, East Anchorage, Midtown, and nearby military bases on an
interruptible basis (Posey and Griffith 2003). The utility owns and operates two generation
facilities that utilize seven natural gas-fired turbines and one heat-recovery turbine. The Hank
Nikkels Plant 1 has a capacity of 102.9 MW, while the George M. Sullivan Plant 2 has a capacity
of 266.3 MW. Five of the seven turbines in these facilities are capable of using No. 2 fuel oil as
alternate fuel, and ML&P stores nearly 1 million gallons of diesel fuel as reserve fuel in the
event of a natural gas shortage (Municipal Light and Power 2013). In terms of gas supply,
ML&P has an advantage over other Railbelt utilities through its one-third Beluga River Gas
Field ownership (Harbour 2008). It has a secure gas supply for its two power plants through
2017 (Posey and Griffith 2003). ML&P also owns 53.33 percent of the 44.4-MW Eklutna Lake
Hydroelectric Plant and has rights to 25.9 percent of the power supplied by the Bradley Lake
Hydroelectric Plant. ML&P is currently expanding the generation facilities at its George M.
Sullivan Plant 2. Three gas turbines, which will provide 120 MW of power, are scheduled to be
installed in 2015.
Figure 5.1.2-1 shows ML&P’s volume and value of electricity sales by customer. Power rates
have been relatively stable due to ML&P’s partial ownership of the Beluga River Gas Field. The
rate increase in 2010 is likely due to the costs of maintaining the gas field, including the
installation of a new compressor to increase compression capacity. The growth in commercial
sales in the mid-2000s occurred as a result of Elmendorf Air Force Base agreeing to purchase all
of its bulk electric power requirements from ML&P.
Golden Valley Electric Association
GVEA serves nearly 100,000 Interior residents from Cantwell north along the Parks Highway
and from Fairbanks south to Fort Greely along the Richardson Highway. In addition to
residential customers, the utility provides electrical power to the Ground-based Missile Defense
System at Fort Greeley, Alyeska’s Pump Station 9, the Pogo gold mine, and the Fort Knox gold
mine near Fairbanks.
The North Pole Power Plant generates nearly three-quarters of GVEA’s electricity using
combined cycle and gas turbines. Since the 1970s, GVEA has relied primarily on refined crude
oil products from Fairbanks refineries using crude oil originating from the Trans-Alaska Pipeline
System. Currently, GVEA's 181-MW power plant in North Pole burns HAGO produced at the
oil refineries located in North Pole. The North Pole Expansion Plant, which adds 60 MW of
generation at the North Pole Power Plant site, burns naphtha produced at the nearby Flint Hills
refinery (Golden Valley Electric Association 2009a). Steam is GVEA’s second largest prime
mover source. Electricity generation from steam takes place at the Healy Power Plant, which is
located adjacent to the Usibelli Coal Mine and is coal-fired. GVEA owns two diesel-fired power
plants, the Zehnder Power Plant (42.2 MW) and Delta Power Plant (23.1 MW). In 2012, GVEA
established the Eva Creek Wind Project consisting of 12 turbines with nearly 25 MWs of
capacity; it is the largest wind project in Alaska.
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To further satisfy customer demands, GVEA also purchases power from the Alaska Energy
Authority (16.9 percent of the power generated Bradley Lake Hydroelectric Project, or
approximately 20 MW), Aurora Energy (which operates a 27.5-MW coal-fired power plant in
Fairbanks), CEA, and ML&P (Regulatory Commission of Alaska Undated). Under contracted
terms, the Alaska Energy Authority and Aurora Energy are priority sellers; Bradley Lake energy
is take-or-pay, and Aurora Energy is contracted to be base-load “firm” energy. CEA has priority
for meeting GVEA’s non-firm needs. It has rights to supply two-thirds of GVEA’s first 450
gigawatt hours (GWh), and four-fifths of subsequent, non-firm needs (if any). CEA and ML&P
compete on the “economy energy spot market” for the remainder of GVEA’s non-firm needs.
Competitive supply entry is possible for any utility wishing to provide firm or non-firm power,
subject to conditions imposed under GVEA’s non-firm energy contract with CEA (Regulatory
Commission of Alaska Undated).
Figure 5.1.3-1 shows GVEA’s volume and value of electricity sales by customer. In general,
higher prices of crude oil were transferred to electricity rates, causing economic impacts to
GVEA’s customers. However, to some extent, the utility’s diverse fuel mix helps stabilize costs;
for example, the low-cost power from Bradley Lake helps smooth out the peaks and valleys
associated with price fluctuations of fossil fuels (Golden Valley Electric Association 2009b).
Moreover, in recent years lower fuel costs, together with contracts to buy wholesale gas-fired
power from CEA, have further helped stabilize rates. The Alaska Intertie, a 170-mile long
intertie owned by Alaska Energy Authority that connects Anchorage area utilities (CEA and
ML&P) with GVEA, allows GVEA to take advantage of low cost natural gas (plus hydro and
coal) generation. However, the capacity of the line is currently limited to increases in GVEA’s
industrial sales due to the expansion of mining activities in the Fairbanks area, including the
opening of the Fort Knox gold mine in the late-1990s and the Pogo gold mine in the mid-2000s.
After peaking in 2008, residential sales tapered off. As noted above, residential customers have
been able to take advantage of programs offered by the Alaska Housing Finance Corporation to
promote energy efficiency. While these energy-saving programs were available statewide,
relatively high electricity rates, combined with the harsh winters of Interior Alaska, made the
programs especially attractive to customers in the GVEA service area.
Homer Electric Association
HEA serves about 22,000 member-owners in a 3,166 square-mile service area. Prior to 2014,
HEA had a wholesale purchase power agreement with CEA to purchase power from that utility.
While there were other power generation sources, including HEA’s Nikiski Power Plant (37.9
MW), the Bernice Lake Power Plant (76.7 MW) that HEA purchased from CEA in 2011, and the
state-owned Bradley Lake Hydroelectric Plant (HEA's share is 14.8 MW), these HEA resources
were operated by CEA as part of its overall generation portfolio (Homer Electric Association
2009).
After the agreement with CEA expired at the end of 2013, HEA began producing its own power
under its Independent Light program. The cornerstone of the program is the Nikiski Combined
Cycle Plant, consisting of the Nikiski Power Plant gas turbine and a newly-installed turbine
powered by steam produced from exhaust heat generated by the gas turbine. The capacity of the
Nikiski Combined Cycle Plant is 80 MW, and working in concert with HEA’s share of the
Bradley Lake Hydroelectric Plant, the facility covers all of HEA’s power needs. In addition,
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HEA recently installed a 48-MW combustion turbine at the utility’s property in Soldotna. This
facility, together with the Bernice Lake Power Plant, is used to provide reserve power. To fuel its
power facilities, HEA has secured contracts for natural gas supply with Hilcorp Energy through
March 31, 2016 (Smith 2013).
Figure 5.1.4-1 shows HEA’s volume and value of electricity sales by customer. Power rates
closely tracked those of CEA because of the power purchase agreement between the utilities.
The decline in industrial sales beginning in 2008 is due largely to the closure of the Agrium
ammonia-urea fertilizer plant in Nikiski as a result of natural gas price and availability issues.
Matanuska Electric Association
MEA serves the Matanuska Borough and the community of Chugiak-Eagle River within the
Municipality of Anchorage. Under a current contract, which expires on December 31, 2014,
MEA must purchase all of its power from CEA, and CEA is required to meet all of MEA’s
requirements. MEA is CEA’s largest customer, accounting for nearly 25 percent of all power
sold. MEA’s shares in the Eklutna Lake (16.67 percent) and Bradley Lake (13.8 percent)
hydroelectric projects have been temporarily assigned to CEA to manage in the interest of MEA.
To meet its power needs after the electricity supply contract with CEA expires, MEA is
constructing a new 170-MW power plant northeast of the Eklutna Interchange on the Glenn
Highway. This dual-fuel facility will operate primarily on natural gas, but it will be able to
switch to diesel. The plant is expected to be operational by 2015 and will produce about 90
percent of MEA’s total power output, with the remaining portion coming from the Bradley Lake
Hydroelectric Plant. MEA has negotiated a natural gas supply contract with Hilcorp Energy that
would begin in 2015 and run through to March 2018.
Figure 5.1.5-1 shows MEA’s volume and value of electricity sales by customer. As with HEA,
the electricity rates of MEA closely followed those of CEA because of the power purchase
agreement between the utilities.
Aurora Energy, LLC
Aurora Energy operates a 32-MW coal-fired power plant in Fairbanks. All of its electricity is
sold to GVEA under a long-term contract.
5.2. REMI Model Development
In 2013, progress was made in developing the model assumptions by conducting interviews with
industry and government representatives who have experience and expertise in the state’s leading
industries and economic policy areas. A description of the persons and organizations included in
the interview process and the information collected is available in Appendix A.
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6. DISCUSSION
Data collection was adequate in 2013 to describe current power generation, transmission, and
demand in the Railbelt. These data will provide context for changes in regional economic
conditions resulting from the power-related effects of the Project. The primary data source was
the U.S. Energy Information Administration, which provides online data current through 2012.
Efforts are currently underway to collect data for future conditions under the with and without
Project scenarios, including changes in generation facilities and fuels, megawatt hours sold, and
sales price by customer category.
The assumptions for the REMI model are being obtained from an information collection process
aimed at developing a consensus about reasonably foreseeable future economic activities in
Alaska with and without the Project. Progress was made in developing the model assumptions by
conducting interviews with industry and government representatives who have experience and
expertise in the state’s leading industries and economic policy areas.
7. COMPLETING THE STUDY
[Section 7 appears in the Part C section of this ISR.]
8. LITERATURE CITED
AEA (Alaska Energy Authority). 2012. Revised Study Plan: Susitna-Watana Hydroelectric
Project FERC Project No. 14241. December 2012. Prepared for the Federal Energy
Regulatory Commission by the Alaska Energy Authority, Anchorage, Alaska.
http://www.susitna-watanahydro.org/study-plan.
AEA. 2013. AEA Program and Project Fact Sheets. Available online at
http://www.akenergyauthority.org/BoardMaterials/7-25-2013/8A_AEAPFS.pdf.
Accessed November 11, 2013.
Apt, J., L. Lave and M. Morgan. 2006. Can the U.S. Have Reliable Electricity? Tepper School of
Business, Carnegie Mellon University. Pittsburgh, PA.
Black & Veatch. 2008. Alaska Railbelt Electrical Grid Authority (REGA) Study. Rancho
Cordova, CA.
Bradner, M. and T. Bradner. 2013. Energy: Fire Island wind set to expand. Bradners' Alaska
Economic Report 17 (November):2.
Bradner, T. 2011. Anchorage utility costs will go up across the board. Alaska Journal of
Commerce. Available online at http://www.alaskajournal.com/Alaska-Journal-of-
Commerce/AJOC-October-23-2011/Anchorage-utility-costs-will-go-up-across-the-
board/. Accessed November 24, 2013.
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
Susitna-Watana Hydroelectric Project Alaska Energy Authority
FERC Project No. 14241 Part A - Page 10 June 2014
Chugach Electric Association. 2009. Railbelt Electric Utility Bill Comparison: Fourth Quarter
2009. Anchorage, AK.
Chugach Electric Association. 2010. Railbelt Electric Utility Bill Comparison: Fourth Quarter
2010. Anchorage, AK.
Chugach Electric Association. 2011. Railbelt Electric Utility Bill Comparison: Fourth Quarter
2011. Anchorage, AK.
Chugach Electric Association. 2012. Railbelt Electric Utility Bill Comparison: Fourth Quarter
2012. Anchorage, AK.
Chugach Electric Association. 2013. Facilities. Available online at
http://www.chugachelectric.com/inside-chugach/the-company/facilities. Accessed
November 11, 2013.
Fay, G., A. Villalobos-Meléndez and C. West. 2012. Alaska Energy Statistics 1960-2011
Preliminary Report. Institute of Social and Economic Research, University of Alaska
Anchorage. Anchorage, AK.
Fire Island Wind LLC. 2013. Project Overview. Available online at http://fireislandwind.com/.
Accessed November 11, 2013.
Golden Valley Electric Association. 2009a. North Pole Expansion Power Plant. Available online
at http://www.gvea.com/about/generation/npe/. Accessed July 17.
Golden Valley Electric Association. 2009b. Bradley Lake Hydroelectric Project. Available
online at http://www.gvea.com/about/generation/bradlake.php. Accessed July 17.
Harbour, D. 2008. South-Central Alaska Natural Gas Storage/Supply Issues: A Ratepayer’s
Review of Our Gas and Electric Challenges. Energy in Alaska, Law Seminars
International. Anchorage, AK.
Homer Electric Association. 2009. HEA's Power Supply & Generation. Available online at
http://www.homerelectric.com/WhereOurPowerComesFrom/tabid/202/Default.aspx.
Accessed November 11, 2013.
Municipal Light and Power. 2013. About ML&P. Available online at
http://www.mlandp.com/redesign/about_mlp.htm. Accessed November 11, 2013.
Posey, J. and J. Griffith. 2003. Electric Power Update. Presentation to the Anchorage Chamber
of Commerce, March 10. Anchorage, AK.
Regulatory Commission of Alaska. Undated. Railbelt Contract Summary: Fuel, Wholesale
Electric, and Transmission. Anchorage, AK.
Smith, B. 2013. HEA predicts busy year ahead. Homer News. Available online at
http://homernews.com/stories/010913/business_hea.shtml. Accessed November 11, 2013.
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
Susitna-Watana Hydroelectric Project Alaska Energy Authority
FERC Project No. 14241 Part A - Page 11 June 2014
Thibert, L. 2013. Chugach Electric Association, Strategic Development and Regulatory Affairs.
Personal communication with Northern Economics, October 29.
U.S. Energy Information Administration. 2013a. Form EIA-923. Available online at
http://www.eia.gov/electricity/data/eia923/index.html. Accessed November 11, 2013.
U.S. Energy Information Administration. 2013b. Form EIA-826. Available online at
http://www.eia.gov/electricity/data/eia826/. Accessed November 11, 2013.
9. TABLES
Table 5.1-1. Railbelt Utilities Power Generation Facilities and Fuel Types
Plant Name
Plant Owner (percent ownership)
Net Generation (MWh)3
Gas Coal Oil Hydro Wind Total
Beluga River CEA 2,009,571
2,009,571
Cooper Lake CEA
77,589 77,589
International Airport Road CEA 56,163 56,163
Fire Island Cook Inlet
Region, Inc.1
50,092 50,092
Hank Nikkels 1 ML&P 54,582 51 54,633
George M. Sullivan 2 ML&P 1,005,890 1,199 1,007,089
Delta Power GVEA
-32 -32
Zehnder GVEA
10,667 10,667
Healy GVEA
215,310 114 215,424
North Pole GVEA
423,592 167,379 590,971
Eva Creek GVEA
65,443
(Jan./13-
Nov./13) 65,443
Chena 5 AE
201,405 201,405
Bernice Lake HEA 78,818 78,818
Nikiski HEA 239,080 239,080
Seldovia HEA
201 201
Southcentral CEA (70%),
ML&P (30%)
607,739
(Jan./13-
Aug./13) 607,739
Eklutna Lake
CEA (30%),
ML&P
(53.33%),
MEA (16.67%) 71,126 71,126
Bradley Lake Alaska Energy
Authority2 397,373 397,373
1Cook Inlet Region Inc. sells all the energy from the Fire Island Wind Project to CEA.
2Alaska Energy Authority distributes energy from the Bradley Lake Hydroelectric Plant as follows: CEA (30.4%); ML&P (25.9%); GVEA (16.9
%); MEA (13.8%); HEA (12%); Seward Electric Utility (1%)
3 Data are for 2012 unless otherwise noted.
Source: U.S. Energy Information Administration (2013a)
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
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FERC Project No. 14241 Part A - Page 12 June 2014
Table 5.1-2. Railbelt Utilities Fuel Use for Power Generation, 2011
Fuel Oil (Barrels) Gas (Mcf Coal (Short Tons)
821,105 40,181,450 397,367
Percent of Statewide Total 49.8% 98.2% 100.0%
Source: Fay et al. (2012)
Table 5.1-3. Railbelt Utilities Sales, 2011
Residential Commercial Other1 Total (MWh)
1,640,126 2,125,764 1,050,834 4,817,024
Percent of Statewide Total 76.6% 77.1% 76.2% 76.7%
1 Other includes sales to community and governmental facilities and industrial customers.
Source: Fay et al. (2012)
10. FIGURES
Figure 5.1-1. Railbelt Utilities Net Generation by Fuel Type
Source: U.S. Energy Information Administration (2013a)
Gas
69%
Coal
17%
Oil
3%
Hydro
11%
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
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FERC Project No. 14241 Part A - Page 13 June 2014
Figure 5.1-2. Average Annual Residential Electricity Rates by Utility, 2005-2012
Source: U.S. Energy Information Administration (2013b)
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
Susitna-Watana Hydroelectric Project Alaska Energy Authority
FERC Project No. 14241 Part A -Page 14 June 2014
Figure 5.1-3. Base Rate and Fuel and Purchased Power Components of a Residential Electrical Bill by Railbelt Utility, Fourth Quarter 2009-2012
Source: Chugach Electric Association (2009; 2010; 2011; 2012)
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
CEA GVEA HEA MEA ML&P
2009 Base 2010 Base 2011 Base 2012 Base 2009 Fuel 2010 Fuel 2011 Fuel 2012 Fuel
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
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FERC Project No. 14241 Part A -Page 15 June 2014
Figure 5.1.1-1. Amount and Cost of Power Sold by Chugach Electric Association, 1990-2012
Source: U.S. Energy Information Administration (2013b)
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
$/kWhMWh SoldResidential Sales Commercial Sales
Industrial Sales Average Residential Rate $/kWh
Avgerage Commercial Rate $/kWh Avgerage Industrial Rate $/kWh
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
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FERC Project No. 14241 Part A -Page 16 June 2014
Figure 5.1.2-1. Amount and Cost of Power Sold by Municipal Light and Power
Source: U.S. Energy Information Administration (2013b)
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
$/kWhMWh SoldResidential Sales Commercial Sales
Average Residential Rate $/kWh Avgerage Commercial Rate $/kWh
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
Susitna-Watana Hydroelectric Project Alaska Energy Authority
FERC Project No. 14241 Part A -Page 17 June 2014
Figure 5.1.3-1. Amount and Cost of Power Sold by Golden Valley Electric Association
Source: U.S. Energy Information Administration (2013b)
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
$/kWhMWh SoldResidential Sales Commercial Sales
Industrial Sales Average Residential Rate $/kWh
Avgerage Commercial Rate $/kWh Avgerage Industrial Rate $/kWh
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
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FERC Project No. 14241 Part A -Page 18 June 2014
Figure 5.1.4-1. Amount and Cost of Power Sold by Homer Electric Association
Source: U.S. Energy Information Administration (2013b)
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
MWh SoldResidential Sales Commercial Sales
Industrial Sales Average Residential Rate $/kWh
Avgerage Commercial Rate $/kWh Avgerage Industrial Rate $/kWh
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
Susitna-Watana Hydroelectric Project Alaska Energy Authority
FERC Project No. 14241 Part A -Page 19 June 2014
Figure 5.1.5-1. Amount and Cost of Power Sold by Matanuska Electric Association
Source: U.S. Energy Information Administration (2013b)
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
$/kWhMWh SoldResidential Sales Commercial Sales
Average Residential Rate $/kWh Avgerage Commercial Rate $/kWh
INITIAL STUDY REPORT REGIONAL ECONOMIC EVALUATION STUDY (15.5)
Susitna-Watana Hydroelectric Project Alaska Energy Authority
FERC Project No. 14241 June 2014
PART A - APPENDIX A: TECHNICAL MEMORANDUM ON LONG-TERM
MODELING ASSUMPTIONS
Memorandum
Date: December 13, 2013
To: The Project File
From: Marcus Hartley, Patrick Burden, and Leah Cuyno
Re: Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
This technical memorandum summarizes our long-term modeling assumptions (LTMAs) which
will form the basis for the analyses of socioeconomic impacts under the “With Watana Dam”
and the “Without Watana Dam” scenarios. In general, the LTMAs create a qualitative
framework within which the quantitative economic impact models and analyses will be
developed. The description of future events or activities provided in this memorandum is general
in nature, without any specific amounts or terms provided except for a few of the key
assumptions directly related to the proposed Watana project. These long-term sets of
assumptions represent two logical futures of the Alaska economy. Choosing any one of the
assumptions may preclude use of another assumption. While some of the assumptions may be
mutually exclusive in this regard, they are not necessarily independent from each other as
assumptions about events that occur later in time are path-dependent and the selection of an
earlier assumption may preclude certain activities in later years.
Sources of LTMAs
The LTMAs are the result of an information collection process aimed at deriving a consensus of
the most probable economic future for Alaska. The LTMAs reflect the combined information from
published reports, project proponents, statements from industry and government
representatives, and opinions from other stakeholders. In addition to a review of published
reports and news articles, the study team interviewed more than 30 Alaskan stakeholders with
experience and expertise in the state’s leading industries and policy areas. These interviews took
place from August–November 2013 and their collective responses played a significant role in
shaping many of the LTMAs. The list of persons interviewed, and the businesses and
organizations that they represent, are listed in the table at the end of the document. Ultimately,
Northern Economics was responsible for assessing the likelihood of the future outcomes
identified by these sources and compiling the information into the consistent set of assumptions
presented in the memorandum.
Organization of the LTMAs
There are 25 LTMAs organized into different categories. The categories start at the national level
(LTMAs 1–3), then move on to describe Alaska oil and gas production and prices (LTMAs 4–9).
From there a description of the future power generation infrastructure in the Railbelt is provided
(LTMA 10), followed by assumptions on other major industries in the state (LTMAs 11–16). The
Part A - Appendix A - Page 1 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
2
State of Alaska’s fiscal assumptions are described in LTMAs 17–20, followed by assumptions on
large transportation (road and port) projects (LTMA 20–21). Finally, the memo describes
assumptions on statewide population, labor availability, and rural issues (LTMAs 22–25).
1 U.S. Economy
No Action / Without Watana Dam
The REMI model generates a baseline forecast that incorporates a time series of historical data
about the U.S. economy over the last three decades. The REMI model’s baseline forecast covering
the entire project timeline (2013–2060) will be used in the Without Watana Dam or No Action
analysis.
With Watana Dam
This set of assumptions will include additional economic activity from construction and operation
of Watana Dam.
2 U.S. Oil Prices
No Action / Without Watana Dam
EIA forecasts for oil prices out to 2040 will be taken from the 2013 Annual Energy Outlook. The
EIA assumes increased prices as the world economy recovers from the recent recession. By 2040,
oil is expected to cost $163 per barrel (Brent 1 crude oil price in 2011 dollars). Oil prices from
2041 to 2060 will be extrapolated based on the trend of EIA prices from 2031–2040.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
3 Federal Spending and Permitting Activities in Alaska
No Action / Without Watana Dam
Federal per capita spending will remain at current levels in real terms through the remainder of
the study period. Permitting policies are also assumed to remain generally constant with those in
place today.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
1 In the 2013 Annual Energy Outlook, the Brent crude oil price is tracked as the main benchmark for world oil
prices. The WTI crude oil price has recently been discounted relative to other world benchmark crude prices.
The divergence between WTI and other world crude oil prices over the last few years has made WTI a less
reliable indicator of U.S. average refiner crude oil costs and petroleum product prices (EIA). Note that Alaska
North Slope oil is delivered aboard tankers almost exclusively to West Coast refineries. It competes against
foreign oils priced off Brent for space in the refineries. Lately, however, West Coast refineries have also been
bringing in crude oil by rail from the Midwest and Canada.
Part A - Appendix A - Page 2 June 2014
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3
4 Alaska On-shore Oil Production
No Action / Without Watana Dam
Oil production from currently producing on-shore fields continues to decline and will follow the
forecasts of the Alaska Department of Revenue annual production through 2022 (the endpoint
of ADOR’s forecasts). Beyond 2022, production from these existing fields will continue to decline
at a rate equal to the projected rate of decline from 2013–2022 (an average annual decline of 8
percent).
The “2013 More Alaska Production Act” (2013 MAP Act) reforming Alaska’s oil and gas tax
regime is expected to create incentives that will result in an increase in oil production. The
ADOR projects that new oil would increase total ANS oil production by 10 percent in 2014, and
about 27 percent by 2022. The study will also assume that the construction of the Alaska-LNG
project will further induce onshore oil production.
The following future activities/development are assumed to take place in the North Slope:
• Liberty is developed and comes on line in 2021 with peak production in 2023.
• Point Thomson condensates production will commence in 2016. With the start-up of
Alaska-LNG project in 2025 condensate production increases significantly.
• Permitting delays push first production in NPRA to 2017. Production peak occurs in
2027.
• The development of the Trans-NPR-A pipeline (TNP) to move oil from the Chukchi to
TAPS will spur additional development of previously marginal fields in the NPR-A. These
marginal fields will contribute an average of 70,000 bod from 2030–2060.
• Some of the North Slope shale oil fields will be sanctioned in 2015 and subsequently
developed with first oil production in 2022. However, regulatory and capital constraints
as well as technical and cost issues result in limited field development until 2030. After
that date, shale oil begins to add significant oil production to total North Slope
production and TAPS throughput for the remainder of the study period.
• The combination of the 2013 MAP Act and later on the construction of the Alaska-LNG
project will lead to oil production from previously marginal or sub-economic oil fields
beginning in 2016.
• Development in ANWR will not be permitted during the study period.
Part A - Appendix A - Page 3 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
4
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
5 Alaska OCS Oil Production
No Action / Without Watana Dam
OCS oil production from the Chukchi Sea and the Beaufort Sea will begin in 2030 and 2034,
respectively. Oil produced in the Beaufort Sea will be transported through TAPS. Oil produced in
the Chukchi Sea will be transported through an onshore pipeline across the NPR-A to TAPS with
construction beginning in 2027. There are no changes from the current rules for federal OCS
royalties; the State of Alaska will not receive any portion of the royalties from OCS activity that
are paid to the federal government. OCS production will create a significant number of jobs both
in the oil and gas sector and the support sectors.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
6 TAPS
No Action / Without Watana Dam
With increased production from the 2013 MAP Act, induced production related to Alaska LNG,
and most importantly development of large OCS oil fields in the Beaufort and Chukchi Sea, the
owners of TAPS make the necessary investments to keep the pipeline open and flowing. With
throughput from the OCS expected to continue through the study period, and with the
development of the shale oil plays, TAPS is reauthorized to operate for another 30 years in 2033.
With Watana Dam
The study will use the same primary assumptions as in the Without Watana Dam Scenario.
Part A - Appendix A - Page 4 June 2014
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5
7 North Slope/Arctic OCS Natural Gas Production
No Action / Without Watana Dam
Prior to the Alaska LNG project, natural gas will be produced in sufficient quantities to meet
localized demand in the NSB and for field consumption. Long-term purchase agreements with
one or more of the Fairbanks natural gas utilities results in the construction of a small-scale (16
to 25 mmcfd) modular LNG plant on the North Slope that begins production in 2016. When the
Alaska LNG project begins operations, the small LNG plant supplies LNG to industrial users on
the North Slope.
The Alaska LNG project is sanctioned and export of gas (LNG) starts in 2027. An average of 3.0
bcfd of ANS natural gas will be supplied to the Alaska LNG pipeline starting in 2027 through the
end of the study period. Several off-take points are built along the route to supply natural gas to
communities with large populations or large industrial users that can justify the capital cost of
the facilities (e.g., Livengood gold mine). The study assumes that most of the NGLs (liquid
petroleum gases) associated with ANS gas will also be exported; with some propane distribution
to communities on the road system.
The route of the Alaska LNG pipeline will transit from Livengood south along the Tanana River to
Nenana and will not parallel the existing road system. As a result, a spur pipeline will be required
to bring gas from an off-take point to Fairbanks. This spur pipeline is not part of the Alaska LNG
project but will be another construction project to incorporate into the assumptions.
Prudhoe Bay and Point Thomson will be primary gas sources for the Alaska LNG project during
the early years of operation. Later, gas production from other fields will begin to meet Alaska
LNG needs, primarily from NPR-A, and the Foothills of the Brooks Range. Gas production from
Beaufort Sea OCS will begin in 2043 and will be transported to markets via the Alaska LNG
project. Some Chukchi OCS gas is used for field use with the balance re-injected and not fully
developed until after the study period.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario except that the
Livengood gold mine is assumed to use electric power from Watana after transmission lines are
built.
Part A - Appendix A - Page 5 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
6
8 Cook Inlet Natural Gas Production
No Action / Without Watana Dam
Natural gas production in Cook Inlet recovers as a result of state incentive programs and long-
term contracts with Southcentral gas and electric utilities.
Gas production from Cook Inlet continues at levels sufficient to meet regional utility needs
throughout the study period, although the natural gas storage facilities must be expanded in
2015 to ease winter peak demand issues.
Some Southcentral utilities purchase gas from the Alaska LNG project when it begins
operation to seek diversity in their fuel supplies. The ConocoPhillips LNG facility in Nikiski re-
opens in 2014 and operates through 2030; the facility continues to operate on a seasonal basis
beyond 2030.
The Agrium fertilizer facility in Nikiski also reopens (in 2015) and operates using a single train
through 2030.
Other discussions related to in-state use of natural gas are described under Prices for Users
of Natural Gas in Alaska and Mining.
With Watana Dam
Watana reduces the demand for gas from Southcentral electrical utilities, which leaves enough
supply of Cook Inlet gas for both the ConocoPhillips LNG plant and Agrium to remain in
operation using Cook Inlet Gas. The Agrium plant closes in 2030, but the Conoco LNG Plant
operates through 2040 and then seasonally after that year.
With Watana, the natural gas storage facilities are expanded again in 2022 to ease winter peak
demand issues.
Part A - Appendix A - Page 6 June 2014
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7
9 Prices for Users of Natural Gas in Alaska
No Action / Without Watana Dam
Natural gas prices for consumers in Alaska will be higher than Lower 48 prices in order to
generate adequate returns to local gas producers that operate in a high-cost Alaskan
environment. In general, prices paid by consumers for natural gas will not be subsidized by the
state and will equal the sum of the wellhead value of the gas plus transportation costs. Prior to
the beginning of operations of the Alaska LNG project, the wellhead value of the gas will be
linked to the sales price of ANS oil sold on the West Coast and the ratio of $5.71 per mmBtu (the
current prevailing value for Cook Inlet gas) of gas to $100 per barrel oil, with a floor of $5.00 per
mmBtu. According to AIDEA project documents for the Interior Energy Plan (2013), natural gas
prices in Fairbanks prior to the operations of the Alaska LNG project are expected to range
between $14.50 and $17 for the end user.
After the Alaska LNG project is operating, ANS gas will be purchased by utilities on long term
contracts (20+ years). The cost of natural gas to Southcentral Alaska customers will be a blend of
ANS and Cook Inlet pricing, and it is anticipated that ANS gas prices will be higher than prices for
natural gas from Cook Inlet production. It is assumed that the wellhead value of ANS gas will be
the netback price from LNG sold in Asia.
With Watana Dam
When Watana comes online, demand for Cook Inlet (CI) gas by utilities will decline, and result in
Cook Inlet gas becoming a smaller percentage of the total gas supply. Cook Inlet gas prices may
not drop because production will be negatively affected by the decline in demand. Since ANS
gas is priced higher than CI gas, the blended gas price in Southcentral increases. Other
assumptions in the Without Watana Dam scenario hold.
Part A - Appendix A - Page 7 June 2014
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8
10 Electrical Generation Infrastructure
No Action / Without Watana
HEA’s Soldotna LM6000 turbine comes online in 2014, and MEA’s Eklutna Generation Station
(EGS) comes online in 2015. ML&P’s George M. Sullivan Plant 2 Generation Replacement Project
comes online in 2016 with a 120-MW capacity.
The Healy Clean Coal plant comes online in 2015. In Fairbanks, GVEA converts one of their North
Pole generator units to natural gas in 2016 with the availability of LNG from the North Slope.
Proposed upgrades to the existing Railbelt electrical transmission system are completed in 2020.
Beginning in 2027, the availability of propane and LNG from the Alaska LNG project leads to the
replacement of diesel powered generation plants use by Copper Valley Electric Association
(CVEA) and other Railbelt communities on the road system that are not served by the Railbelt
transmission system.
No additional thermal generation plants are developed in the Railbelt, although aging plants are
replaced with similar-sized but more efficient gas-fired generators as maintenance costs increase.
Some relatively small renewable energy projects are brought online, but the goal to generate 50
percent of electricity from renewable sources by 2025 is not achieved.
The Mount Spur geothermal project is built as a private/public partnership and comes online in
2026.
LNG and propane from Alaska LNG are shipped to rural Alaska to replace high-cost diesel
generators in communities that have year-round road or marine access.
With Watana
Power from Watana dam becomes available in 2024. The goal of generating 50 percent of
electrical power from renewable sources is met. Because energy from Watana is available, the
state elects not to partner with the developer of the Mt. Spur geothermal project and plans are
shelved.
Additional transmission lines connect CVEA to the Railbelt transmission system in 2028 and to
Tok in 2030.
Unless otherwise discussed here the Without Watana Dam scenario holds.
Part A - Appendix A - Page 8 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
9
11 Alaska In-state Oil Refining and Imports of
Petroleum Fuels
No Action / Without Watana Dam
In-state refineries are assumed to continue to operate at current levels through 2026. With the
opening of Alaska LNG in 2027, and the availability of low cost natural gas, refineries in North
Pole (Flint Hills and Petro Star) convert to natural gas as their primary source of energy. This
situation results in cost savings for the refineries and operations at current levels through the end
of the study period. However, the cost of petroleum imports is higher than production from in-
state refiners which means there is no noticeable reduction of in-state gasoline or distillate
prices.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
Part A - Appendix A - Page 9 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
10
12 Mining
No Action / Without Watana Dam
Mining activity expands with development of several large prospects and expanded resource
utilization at existing operations. In general, mine developers determine that they cannot afford
to wait for the state to develop energy infrastructure and therefore provide their own
infrastructure in a way that allows future flexibility if new energy sources become available. The
major new mining projects are described separately below, but other smaller mining operations
also come on line during the study period.
1) The Donlin Creek Mine begins production in 2019. The project would require 150
megawatts of electricity to power the mill and facilities. The power would be produced
using on-site natural gas fired generation. The gas is transported to Donlin Creek via a
gas pipeline from Cook Inlet. Revitalized production of Cook Inlet natural gas (see LTMA
#8) generates sufficient gas supply until the opening of Alaska LNG in 2027. The mine
operates for 27+ years (from 2019–2046 and produces a total of 30 million ounces of
gold.
2) Pebble begins production in 2040, after permitting delays. The mine has a smaller
footprint than currently envisioned, but is still able to access known mineral resources.
The mine utilizes natural gas as its primary energy source. The gas is transported to the
mine via a sub-sea pipeline from Anchor Point to Insikin Bay and then a 90-mile pipeline
that runs from Iniskin Bay to the mine. The mine operates throughout the remainder of
the study period. The copper and gold are exported via the port facility in Iniskin Bay.
3) Livengood mine comes on line in 2028, two years after the opening of Alaska LNG. A gas
off-take point at Livengood enables the mine to generate its own electricity and to use
co-generated steam in the milling process. The mine would produce 16 million ounces of
gold during the study period.
4) Red Dog Mine expands operations to adjacent resource deposits and operates through
2045.
5) Coal exports increase from the Usibelli Mine through the Port of Seward.
6) Smaller unspecified mines with road/port access and access to energy will generate
additional mining jobs each year from 2013–2060. These have the effect of replacing jobs
from older mines that are reaching the end of their production cycles.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario with the
following difference: Livengood mine comes on line in 2024, two years after the opening of
Watana Dam. Livengood builds a transmission line from GVEA’s distribution system to access
electricity. The mine would produce 16 million ounces of gold during the study period.
Part A - Appendix A - Page 10 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
11
13 Fisheries
No Action / Without Watana Dam
Harvest volumes of most species are expected to stay within the ranges of the last 10 years.
Revenues from seafood are expected to increase as demand in Asia continues to grow and wild-
caught seafood attains a premium over farm-raised seafood in the marketplace. Trends
associated with global climate change continue with some northward movement of fish stocks
and densities. The industry is able to adapt to the gradual changes, as stocks that were formerly
found in more southerly waters are now more abundant in Alaska waters. Commercial fish
harvests in the Chukchi and Beaufort Seas continue to be prohibited.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario. Assumptions
on Watana’s impact on salmon stocks in Cook Inlet or on recreation fishing in the main stem of
the Susitna River will await more information from fisheries related studies.
14 Tourism
No Action / Without Watana Dam
Growth in Alaska’s tourism industry continues, but at a lower rate than in the past decade due to
competition from other global tourist destinations, and a limited number of communities that
can meet the needs of the cruise ship industry. The growth rate in the tourism sectors is
constrained to two-thirds of the prior decade’s growth rates.
With Watana Dam
Watana Dam is assumed to have no net impact on the number of out-of-state visitors to Alaska.
There may be in-state distributional impacts resulting from enhancement of certain sites as a
result of the dam. The studies on recreational impacts will inform these assumptions when they
become available.
15 Air Transportation
No Action / Without Watana Dam
Air cargo support in Alaska will continue to grow, but at lower rates than in prior decades.
Tourism accounts for a substantial portion of air transportation activity and future growth rates
are constrained to two-thirds of the prior decade’s growth rates.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
Part A - Appendix A - Page 11 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
12
16 Economic Diversification
No Action / Without Watana Dam
A liquid petroleum gas (LPG) handling facility and marine terminal is developed at Nikiski to
export the LPGs to the Pacific Rim countries. The facility uses gas liquids from the Alaska LNG
project as inputs. Some of the propane is shipped to rural Alaska ports with ice-free access.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
17 State Revenues
No Action / Without Watana Dam
The State of Alaska will continue to depend on revenues from the oil industry. Long-term
projections on state revenues will therefore depend on assumptions regarding future oil
production and prices (as stated in the LTMAs above).
The “2013 More Alaska Production Act” is expected to incentivize additional investments in
exploration and development of oil and gas resources that would result in additional oil and
gas production, and State revenues.
When significant volumes of OCS oil begin to flow through TAPS, the value of TAPS will
increase substantially. Prior to the value increase, the legislature is assumed to rewrite the
existing oil and gas property tax statutes to limit the local government take of the shared tax
and increase the amount available to the state. The oil and gas property tax mill rate is also
assumed to increase at the same time.
However, despite near and medium-term assumptions regarding new fields coming on line
that would slow down the decline rate of producing oil fields, in the long run, it is anticipated
that the State of Alaska will need to create additional revenue sources from new taxes in order
to fund government services.
The fiscal model will determine the level of taxes that would have to be generated in order to
balance the operating budget. The operating budget will be consistent with assumptions
stated in the LTMA regarding state spending. Any taxes that are implemented would be
considered temporary and would be eliminated or reduced if operating budget surpluses are
generated. The timing of imposition of these taxes, if they are required, would be determined
by initial model runs specific to the Without Watana Dam Scenario.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario, except the
timing of imposition of taxes, if required, would be determined by initial model runs specific to
the With Watana Dam Scenario.
Part A - Appendix A - Page 12 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
13
18 Permanent Fund and Permanent Fund Dividends
No Action / Without Watana Dam
As mandated by the Alaska Constitution, 25 percent of state oil and gas royalties continue to be
paid into the Permanent Fund (PF) and the principal balance of the PF continues to grow.
Earnings from the PF continue to be paid as dividends (PFDs) unless it is determined by initial
model runs that state budget deficits have fully depleted the Constitutional Budget Reserve
(CBR). At that time, all PFD payments are eliminated and investment earnings from the PF are
used to balance the state budget. PFDs would resume only if the PF earnings are not required to
balance the budget.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
19 Spending by the State of Alaska
No Action / Without Watana Dam
Unless constrained by budget deficits, the state operating budget plus the capital budget and
receipts from the federal government is set to equal state revenues less dedicated contributions
to the Permanent Fund, the CBR, Education Fund, and other accounts.
In years when the CBR is needed to balance the budget, the operating budget is reduced by two
percent per year, and in years after the CBR is depleted and a budget deficit is facing the state,
the operating budget, plus a modest capital budget of $200 million (in 2013 $ and adjusted for
inflation in future years), is set to equal total revenues. In years when there is a budget surplus,
the state capital budget is assumed to be approximately 75 percent of the available surplus (total
revenues less operating budget), with 25 percent going into the CBR.
Future capital projects include:
• Railbelt transmission upgrades
• North Slope LNG facility for Fairbanks
• Port MacKenzie rail
• Port of Anchorage upgrade
• State investment in Alaska LNG pipeline (including at least some of off-take points and a
pipeline to supply gas to Fairbanks.)
• Road projects (see State Funded Road projects)
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario. In addition,
the State of Alaska will subsidize the cost of the Watana Dam construction. The project will be
funded in a manner similar to the Bradley Lake hydroelectric project. Project financing
assumptions will be further fine-tuned in collaboration with the Alaska Energy Authority.
Part A - Appendix A - Page 13 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
14
20 State Funded Road Projects
No Action / Without Watana Dam
Because of the recognition that the state government needs to spend within its means, only
those new road projects that appear to generate positive economic development will be built. In
general, the state will require these road projects to be funded through private/public
partnerships and local improvement programs. The only road projects that are foreseeable under
these conditions is an upgrade of the road from Iniskin Bay to Pebble, the Umiat Road on the
North Slope, and the road to Ambler.
Following construction of the Alaska LNG project, the Parks Highway, and the Dalton Highway
and the Glenn Highway between Anchorage and Palmer are refurbished to repair construction
related damage.
With Watana Dam
The road projects assumed under the “Without Watana” Scenario will be undertaken. In addition,
a new road providing access to Watana Dam and the Watana Reservoir will be developed in
2018. This road may or may not be accessible to the public; public access will be determined in
the decision-making process.
21 Port Projects
No Action / Without Watana Dam
Port of Seward improvements will be completed in 2020 to support coal exports. An expanded
LNG port will be developed at Nikiski by 2022. The port in Iniskin Bay will be built to support
development of the Pebble Mine in 2035. A port on the Chukchi Sea coastline will be developed
in 2026 to support OCS and TNP development. The Port of Anchorage expansion will be
completed in 2018 (this is included in the list of State-funded projects).
With Watana Dam
All port projects assumed under the Without Watana Dam Scenario will be built.
22 Statewide Population growth
No Action / Without Watana Dam
Statewide population is an output of the REMI model; no specific assumptions regarding
population will be made.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario. Population will
be determined independently for the With Watana Dam Scenario.
23 Rural and Urban Changes
No Action / Without Watana Dam
Population for modeled boroughs and census areas will be an output of the REMI model.
Borough and census area totals from the model will be allocated down to the community level
Part A - Appendix A - Page 14 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
15
using existing trends, but modified by any of the model assumptions that are specific to
individual communities.
Other assumptions that affect community populations include:
• State funding of schools in communities as long as 10 students remain.
• Revenue sharing formulas that are currently in place will remain unchanged.
• Bypass mail subsidies continue.
With Watana Dam
The study will use the same assumptions as in the Without Watana Dam Scenario.
24 Resident v. Non-Resident Labor
No Action / Without Watana Dam
The trends of resident versus non-resident labor over the past 10 years will continue through the
study period and any differences by major industry groups will be utilized.
With Watana Dam
Specific assumptions regarding resident and non-resident workforce for construction and
operation of the Watana Dam, in-migration, and similar topics will be developed in concert with
ADOLWD. Otherwise, the study will use the same assumptions as in the Without Watana Dam
Scenario.
25 Subsistence
No Action / Without Watana Dam
Subsistence activities are not addressed in the REMI or the fiscal model.
With Watana Dam
Subsistence activities are not addressed in the REMI or the fiscal model.
Part A - Appendix A - Page 15 June 2014
Draft: Technical Memorandum on Long-term Modeling Assumptions (LTMAs)
16
Persons Interviewed
Person Interviewed Company or Organization Title
Mr. Phil Steyer Chugach Electric Association Government Affairs Manager
Mr. Lee Thibert Chugach Electric Association Vice President, Regulatory
Affairs
Mr. Arthur Miller Chugach Electric Association Director, Regulatory Affairs
Mr. Mark Fouts Chugach Electric Association Marketing Director
Mr. Cory Borgeson Golden Valley Electric President & CEO
Mr. Brad Janorschke Homer Electric Association General Manager
Mr. Joe Griffith Matanuska Electric Association General Manager
Mr. James Posey Anchorage Municipal Light and Power General Manager
Mr. Ed Fogels Alaska Department of Natural Resources Deputy Commissioner
Mr. Kevin Banks Alaska Department of Natural Resources Petroleum Market Analyst
Ms. Karen Matthias Council of Alaska Producers Executive Director
Mr. Jeff Cook Flint Hills Refinery Refinery Manager
Mr. Dan Dickinson Dan Dickinson, CPA CPA
Ms. Cindi Bettin Alaska Mental Health Trust Authority Senior Lands Manager
Mr. Glen Haight Alaska Department of Commerce, Community, &
Economic Development Executive Director
Mr. Andrew Halcro Anchorage Chamber of Commerce
Ms. Deantha Crockett Alaska Miners Association Executive Director
Mr. JR Wilcox Cook Inlet Energy President
Mr. Neal Fried Alaska Department of Labor & Workforce
Development Economist
Mr. Scott Goldsmith University of Alaska, Institute of Social & Economic
Research Economist
Mr. Larry Persily Federal Pipeline Coordinator
Ms. Colleen Starring ENSTAR Natural Gas Company President
Mr. Curtis McQueen Eklutna, Inc. CEO
Mr. James Hemsath Alaska Industrial Development & Export Authority Deputy Director
Ms. Sarah Leonard Alaska Travel Industry Association President
Mr. Bill Popp Anchorage Economic Development Corporation President & CEO
Mr. Robert Wilkinson Copper Valley Electric Association CEO
Mr. Jim Dodson Fairbanks Economic Development Corporation President & CEO
Mr. Kurt Gibson Hillcorp Vice President, AK Midstream
Mr. Jim Jansen Lynden Transportation
Mr. John Parrott Ted Stevens Anchorage International Airport Manager
Ms. Lorali Simon Usibelli Coal Vice President, External Affairs
Mr. Scott Jepsen ConocoPhillips Alaska, Inc. Vice President, External Affairs
Mr. Tim Buller Agrium US Inc. Senior Specialist, Engineer
Part A - Appendix A - Page 16 June 2014