HomeMy WebLinkAboutGlennallen to Fairbanks Intertie-Preliminary Assessment 2 of 2 1991
GLENNALLEN TO FAIRBANKS INTERTIE:
PRELIMINARY ASSESSMENT
Prepared by
Alaska Energy Authority
March 4, 1991
At the request of Copper Valley Electric Association, the Alaska Energy
Authority has conducted a preliminary assessment of a_ proposed
transmission line between Glennallen and Fairbanks. The project would
consist of 146 miles of new 138 kV line between the Pump Station 11
substation in Glennallen and the Jarvis Creek substation in Delta
Junction, plus 22 miles of new 138 kV line between the Carney and North
Pole substations in the Fairbanks area. The 22 mile segment would
replace existing 69 kV line.
COST ESTIMATE
The construction cost is estimated at $92.5 million in 1991 dollars.
Supporting worksheets are included in Attachment A. The cost estimate
was prepared for a single circuit line with 556 ACSR Dove conductor and
guyed, steel structures. The estimate is consistent with information
presented in the 1989 Northeast Intertie report by Power Engineers, and
with costs recently developed for the proposed Healy-Fairbanks 138 kV
line by Dryden & LaRue.
The increase in operating and maintenance (0&M) costs is estimated at
$200,000 per year in 1991 dollars, with a present value of $4.0 million
over 50 years. This is consistent on a per-mile basis with O&M costs
estimated for the proposed new line between Healy and Fairbanks, and
covers maintenance only on the 146 miles between Glennallen and Delta
Junction. Additional operating costs are not anticipated, and no
additional O&M is included for the Carney-North Pole replacement section
of the new line.
The total cost of the intertie proposal, including both construction
cost and O&M, is therefore estimated at $96.5 million.
ECONOMIC BENEFIT
The following intertie benefits are considered in this assessment:
1) Diesel generation in the Copper Valley system would be replaced by
purchases over the intertie. The source of this purchased energy
could be either Fairbanks or Anchorage. For this preliminary
analysis, it is assumed that sufficient transmission capacity
would be available for delivering Anchorage gas-fired energy to
Copper Valley throughout the winter. Even with assumed
transmission losses, the benefit estimate is somewhat higher if
Anchorage gas units rather than Fairbanks oi] units are assumed to
be the source of purchased energy. Net savings to Copper Valley
in fuel, O&M, and capacity costs are included.
2) Summer energy from the Solomon Gulch hydro project that is
currently spilled due to inadequate demand in the Copper Valley
system would be sold over the intertie to Fairbanks. The value of
this transfer would be the savings realized by Fairbanks, i.e. the
Fairbanks avoided cost. It is assumed in this analysis that
Fairbanks would otherwise purchase this energy from Anchorage, and
that the avoided cost is therefore the variable cost of gas-fired
generation adjusted for transmission losses.
It is possible that the avoided cost would, at least to some
extent, be based on the variable cost of production from Healy
coal-fired generation. However, primarily due to long-run fuel
price expectations, these costs are likely to be lower than the
variable costs of gas-fired generation. Lower avoided cost would
again mean a lower estimate of intertie benefits.
Key inputs to the analysis include the Copper Valley load forecast and
seasonal load pattern, the assumed monthly energy potential from Solomon
Gulch, the forecast of diesel fuel prices, and avoided 0&M costs of
diesel generation. These inputs are discussed below.
Copper Valley Load Forecast and Seasonal Load Pattern
Three forecasts of Copper Valley energy requirements were considered for
this analysis and are shown on the graph in Attachment B:
1) The “ISER Mid 89" forecast was developed during the Railbelt
Intertie Reconnaissance Study for use in evaluating the Northeast
Intertie proposal.
2) The "CVEA PRS 89" forecast is from the most recent Copper Valley
Power Requirements forecast, which extends to the year 2000.
3) The "CVEA Extended" forecast is a simple extrapolation to 2009 of
the Copper Valley forecast. This extended forecast was used by
Stone & Webster Management Consultants in their recent "Least Cost
Plan" for the Copper Valley system.
The "History" of energy requirements shown in Attachment B was developed
by adding assumed system losses of 10.5%! to the reported annual sales.
Energy requirements in 1989 showed a significant increase to roughly 58
GWh, which may have been caused to a great extent by oi] spill clean-up
activity. Though 1990 figures have not yet been reported, preliminary
estimates suggest that energy requirements did not fall back to previous
1 From Copper Valley Power Requirements Study, November 1989, page
34 and succeeding tables.
levels and in fact may have increased a little more. It is unknown
whether this represents an extension of oil-spill clean-up impact that
will not persist in future years, or a lasting shift to a higher demand
level caused by other factors.
The seasonal pattern of demand is important for determining how much of
the Copper Valley requirement can be served from Solomon Gulch and how
much must be served from diesel generators. Because Solomon Gulch is
water limited in the winter but not in the summer, the following effects
can occur:
1) If the Copper Valley load is much heavier in the winter than in
the summer, more diesel generation will be needed in the winter
and more water will spill over the dam in the summer.
2) If the Copper Valley load is spread more evenly throughout the
year, less diesel generation will be needed in the winter and less
water will spill over the dam in the summer.
The available information suggests that roughly 30-33% of the annual
Copper Valley load occurs in the four month period from June through
September, which are the four months during which excess energy is
typically available from Solomon Gulch. This pattern emerges from
review of two sources:
1) The DOE IE-411 form submitted by Copper Valley to the Energy
Authority in January 1991 shows the expected monthly energy
requirement for the Copper Valley system, and presents figures
within the range noted above.
2) The Copper Valley Power Requirements Study of November 1989
includes a graph labeled "CVEA Demand History, 1982 through
October 1989." The monthly peak demand figures presented on the
graph can be converted to monthly energy by assuming a constant
load factor of roughly 60% throughout the year, which produces an
annual energy total of about the right magnitude. This exercise
again yields the result that June-September energy requirements
are between 30% and 33% of annual requirements.
For all of the cases examined, the model developed for this assessment
assumes that June-September energy will be 30% of annual energy. The
following are examples of how the model allocates energy to Solomon
Gulch and diesel generation given this 30% input factor:
1) When total Copper Valley energy requirements are 52.0 GWh, 41.5 is
estimated to come from Solomon Gulch and 10.5 from diesels.
2) When total Copper Valley energy requirements are 61.5 GWh, 44.5 is
estimated to come from Solomon Gulch and 17.1 from diesels.
These results are consistent with the allocation expected from
historical data. REA form 12's submitted by Copper Valley show the
following totals for net generation between 1986 and 1988:
1986 1987 1988
Solomon Gulch 40.8 GWh 42.4 GWh 40.8 GWh
Diesels 10.2 GWh 10.5 GWh 7.6 GWh
Other sources such as the Alaska Electric Power Statistics indicate only
slight differences from these values.
Monthly Energy Potential From Solomon Gulch
The energy potential from Solomon Gulch is estimated for two time
periods:
1) October through May, when project output is typically below Copper
Valley system demand due to limited water availability; and
2) June through September, when project energy potential typically
exceeds Copper Valley system demand due to surplus water
availability.
The amount of diesel generation required for Copper Valley is tied
directly to Solomon Gulch energy potential from October through May.
Higher energy availability from Solomon Gulch during this period means
lower requirements for diesel generation. Actual monthly net generation
from Solomon Gulch was examined for the years 1987 through 1989 based on
monthly sales from the project as reported to the Energy Authority
adjusted for transmission losses:
Net Generation from Solomon Gulch
October through May
1987 1988 1989
GWh 26.0 24.4 25.3
The 1990 estimate recently provided by Copper Valley is 29.3 GWh.
The estimate for October through May energy used in the Railbelt
Intertie Reconnaissance Study is 25.9 GWh. This is still considered
reasonable in view of the historical data shown above, and was therefore
assumed in all cases examined for this preliminary intertie assessment.
The estimate of energy available from June through September is harder
to develop from historical data because it is based on estimates of
water availability rather than metered sales. Two alternatives are
considered:
1) The Railbelt Intertie Reconnaissance Study assumed 28.6 GWh could
be generated during this period, which would be equivalent to
constant project output of 9.8 MW throughout these four months.
2) Copper Valley suggests that 36.5 GWh could be generated during
this period, which would be equivalent to constant project output
of 12.5 MW throughout these four months. Though Solomon Gulch is
considered a 12 MW project, Copper Valley indicates that output
above the 12 MW rating can be achieved when the reservoir is full.
Overall, then, the preliminary assessment considers two alternatives for
Solomon Gulch energy availability, labeled as shown below:
BASE ALT
October through May (GWh) 25.9 25.9
June through September (GWh) 28.6 36.5
TOTAL (GWh) 54.5 62.4
Diesel Energy Requirements and Solomon Gulch Summer Spill Availabilty
Attachment C shows annual diesel energy requirements by year for each of
the three load forecasts based on the factors described above,
specifically:
1) 25.9 GWh output from Solomon Gulch from October through May; and
2) 30% of annual Copper Valley energy requirement projected to occur
from June through September (i.e. 70% of annual load occurs
October through May) .
Attachment D shows annual Solomon Gulch summer spill availability for
each of the three load forecasts and each of the two summer hydro
scenarios. This is the amount of energy that would be available to
export to Fairbanks during the summer months.
Diesel Fuel Price Forecasts
Two alternative forecasts of diesel fuel prices delivered to Copper
Valley were used in the preliminary assessment:
1) The probability weighted average used in the Energy Authority's
Railbelt Intertie Reconnaissance Study; and
2) The prices used by Stone & Webster Management Consultants in their
recent Least Cost Plan for Copper Valley.
These price forecasts are shown in Attachment E. In nominal dollars,
the forecast from the Energy Authority Reconnaissance Study for 1992 is
$0.81 per gallon while the Stone & Webster forecast is $0.96 per gallon.
Avoided O&M Costs of Diesel Generation
The REA Form 12's provided by Copper Valley for the last several years
include the costs of operation and maintenance for the diesel facilities
in Glennallen and Valdez, plus data on diesel net generation. These
figures are presented below:
1987 1988 1989 ($000s) ($000s) ($000s)
Non-fuel Operating Expense $541.8 $508.3 $453.3
Maintenance Expense 272.0 268.2 301.4
TOTAL $813.8 $776.5 $754.7
Diesel Net Generation (GWh) 7.6 10.5 19.5"
* Solomon Gulch transmission line to Glennallen inoperative
from 12/88 - 9/89.
There is nothing in these figures that suggests an allocation of O&M
costs into fixed and variable components. The fact that total O&M did
not increase as net generation increased suggests that the variable
component may be a small part of the total. For most of the cases
examined, the preliminary assessment makes the following assumptions:
1) Fixed O&M is assumed to be $650,000. It is further assumed that
all of this amount would be avoided if a Glennallen-Fairbanks
intertie were constructed.
2) Variable O&M is assumed to be $0.01 per kWh, consistent with the
estimate of diesel variable O&M developed for the Energy
Authority's recent analysis of a Tyee-Swan intertie. If diesel
generation amounts to 10 GWh per year, variable O&M would amount
to $100,000 using this assumption. The analysis further assumes
that all diesel variable O&M is avoided if the proposed intertie
is built.
Concern has been expressed by Copper Valley that the diesel O&M costs
reflected in the REA Form 12's may understate the full extent of
avoidable costs due either to accounting issues or to a _ possible
misinterpretation of the data presented. As a result, the preliminary
assessment includes a sensitivity test based on the assumption that
avoidable fixed O&M for the diesel facilities is $1 million per year
rather than $650,000.
Other Savings -- Diesel Capacity Costs
It is assumed that Copper Valley would purchase new diesel generation
equipment in the future if the proposed intertie is not built. With the
intertie, however, it is assumed that Copper Valley would not buy any
new generators.
If new diesel generators are purchased, the analysis assumes that 3.0 MW
will be acquired in 1996 at a cost of $1.35 million (1991 dollars); and
that an additional 1.5 MW will be acquired in 2004 at a cost of $675,000
(1991 dollars). This pattern is repeated every 15 years. The present
value of these capacity additions, assumed to be saved in the event an
intertie is built, is $3.3 million.
RESULTS OF THE ANALYSIS
A spreadsheet was constructed to estimate the present value of benefits
that would be realized as a result of the proposed intertie over the 50
year period from 1996 through 2045.¢ These benefits were compared with
the estimated life-cycle cost of $96.5 million to yield the "net benefit
(loss)" estimates shown in the table below:
A copy of the spreadsheet on a floppy disk has been provided to
Copper Valley Electric Association.
NET BENEFIT (LOSS) OF PROPOSED INTERTIE
BETWEEN GLENNALLEN AND FAIRBANKS
(Millions of 1991 Dollars)
Solomon Diesel NET
Load Gulch Diesel Fixed BENEFIT
Forecast Energy Price O&M Benefit Cost (LOSS)
ISER BASE AEA -65 37.1 96.5 (59.4)
ISER ALT AEA 65 40.6 96.5 (55.9)
ISER ALT SWMC -65 46.9 96.5 (49.6)
CVEA BASE AEA -65 43.5 96.5 (53.0)
CVEA ALT AEA +65 47.0 96.5 (49.5)
CVEA ALT SWMC -65 53.5 96.5 (43.0)
CVEA EXT ALT SWMC -65 61.1 96.5 (35.4)
CVEA EXT ALT SWMC 1.0 68.1 96.5 (28.4)
While alternative assumptions can be used that would result in a higher
benefit estimate, the range of outcomes in this preliminary assessment
indicates that the proposed intertie project would not result in net
economic benefits given assumptions that appear reasonable today.
A State-funded intertie would allow a reduction in Copper Valley retail
rates. If the full measure of savings estimated in the preliminary
assessment were allocated to Copper Valley consumers, the rate reduction
would be on the order of 5 to 6 cents per kWh (in nominal dollars) by
the year 2000. The actual rate reduction may be somewhat less, however,
because the Anchorage utility providing winter energy would be expected
to include a margin in its wholesale rate, the Fairbanks utility
purchasing summer energy from Solomon Gulch would be expected to pay
somewhat less than its avoided cost, and wheeling charges would also be
incurred to some extent.
ATTACHMENT A
ALASKA ENERGY AUTHORITY
PROJECT COST ESTIMATE
PROJECT: 1. Glennallen (PS No. 11)-Delta Junction (Jarvis) 138 kv lin
2. Carney-North Pole 138 kV Line
DATE: February 8, 1991
Revised: February 13,1991
1. PS No. 11 Substation to Jarvis Substation 138 kV Line
Line Length: 146 Miles
Item Unit Description Labor Material Total
1 Mob. & Demob. $1,750,000 $o $1,750,000
2 Survey $1,250,000 $o $1,250,000
3 Clearing $1,500,000 $0 $1,500,000
4 Geotech Program $1,200,000 $o $1,200,000
5 Steel Structures $17,600,000 $15,400,000 $33,000,000
6 Conductor $6,000,000 $4,500,000 $10,500,000
7 Foundations $4,800,000 $5,000,000 $9,800,000
8 Miscellaneous $o $o $o
Subtotal Transmission Line $59,000,000
Substations Modification $500,000
Compensation Equipment $2,500,000
Subtotal Transmission Line and Equipment $62,000,000
Design Engineering (7%) $4,300,000
Construction Management (5%) $3,000,000
Administration (4%) $2,500,000
ROW Acquisition and Permit $5,000,000
Subtotal $76,800,000
Contingency (10%) $6,200,000
TOTAL (146 Miles T/L) $83,000,000
2. Carney to North Pole 138 kV Transmission Line
Line Length: 22 Miles
Item Unit Description Labor Material Total
1 Mob. & Demob. $300,000 $0 $300,000
2 Survey $200,000 $o $200,000
3. Clearing $o $0 $o
4 Geotech Program $oO $o $o
5 Steel Structures $1,600,000 $2,000,000 $3,600,000
6 Conductor $875,000 $425,000 $1,300,000
i Foundations $950,000 $650,000 $1,600,000
8 Miscellaneous $o $o $o
Subtotal Transmission Line $7,000,000
Substations Modification $500,000
Compensation Equipment $o
Subtotal Transmission Line and Equipment $7,500,000
Design Engineering (7%) $525,000
Construction Management (5%) $375,000
Administration (4%) $300,000
ROW Acquisition and Permit $o
Subtotal $8,700,000
Contingency (10%) $800,000
TOTAL (22 Miles T/L) $9,500,000
ATTACHMENT B
CVEA ENERGY REQUIREMENTS
History and Forecasts
GWh
80F
History
BOF
EE
40F -
r-orecasts
20)
O ee {i 1 L L l 1 1 I I 1 I aie 1 if l 1 1 l I L 1 1 1 1 1 L
82 86 90 94 98 O02 Oo6 10
—— |ISER Mid 89 —— CVEA PRS 89 —=]—- CVEA Extended
ATTACHMENT C
2010
BASE
CUR
Z Ey
2
Sa° Tt
Cur
ATTACHMENT D
‘ULCH SUMMER
CURD
1 c
\
3.6
py
1¢ 1é
13
16
1 a
11.6
10.9
ATTACHMENT E
DIESEL FUEL PRICE FORECASTS
* * ae xe
AEA S&W AEA S&W AEA S&W
RECON LCP RECON LCP RECON LCP
$91 per $91 per $91 per $91 per $Nom per $Nom per
MMBtu MMBtu Gallon Gallon Gallon Gallon
1992 5.54 6.58 0.78 @.92 @.81 @.96
1993 5.65 6.72 @.79 @.94 @.86 1.03
1994 5.76 6.85 @.81 @.96 @.92 1.09
1995 5.87 6.99 @.82 @.98 @.98 LoL?
1996 5.98 7413 @.84 1.00 1.04 1.24
1997 6.09 Tat @.85 1.02 ult 1.33
1998 6.20 7.41 @.87 1.04 t15 1.41
1999 6.31 7.56 @.88 1.06 1.26 1451
2000 6.42 Todt 0.90 1.08 i33 1.61
2001 6.49 7.87 @.91 1.10 1.41 1.71
2002 6.57 8.@3 @.92 1.12 1.49 1.82
2003 6.65 8.19 @.93 1.15 1.58 1.94
2004 6.73 8.35 @.94 1.37 1.67 2.07
2005 6.81 8.52 @.95 1.19 1.76 2.21
2006 6.88 8.69 @.96 1.22 1.87 2.35
2007 6.96 8.86 @.97 1.24 1,97 2.51
2008 7.04 9.04 @.99 1.27 2.08 2.67
2009 Tett 9.22 1.00 1.29 2.20 2.85
2010 has 9.40 1.01 b.32 2.324 3.04
* Conversion to $ per gallon assumes 140,000 Btu per gallon
** Conversion to nominal dollars assumes 4.5% annual inflation
AEA RECON = 1989 AEA Railbelt Intertie Reconnaissance Study,
(probability weighted average)
S&W LCP = 1991 Least Cost Plan for CVEA prepared by Stone &
Webster Management Consultants