Salt Lake City Area/Integrated Projects Notice of Rate Order No. WAPA-63
Federal RegisterNov 3, 1994
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DEPARTMENT OF ENERGY
Western Area Power Administration
Salt Lake City Area/Integrated Projects Notice of Rate Order No.
WAPA-63
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of Rate Order''Salt Lake City Area/Integrated Projects
(Integrated Projects) Firm Electric Service Rate Adjustment.
-----------------------------------------------------------------------
SUMMARY: Notice is given of the confirmation and approval by the Deputy
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-63
and Rate Schedule SLIP-F5 placing firm power rates for capacity and
energy from the Integrated Projects of the Western Area Power
Administration (Western) into effect on an interim basis. The
provisional rates will remain in effect on an interim basis until the
Federal Energy Regulatory Commission (FERC) confirms, approves, and
places them into effect on a final basis or until they are replaced by
other rates.
The provisional firm power rates to be effective from December 1,
1994, through November 30, 1999, consist of an energy charge of 8.90
mills per kilowatthour (mills/kWh) and a capacity charge of $3.83 per
kilowatt month (kW-month), which result in a composite rate of 20.17
mills/kWh. This is a 7.9-percent increase over the current energy
charge of 8.40 mills/kWh and the current capacity charge of $3.54/kW-
month which results in a composite rate of 18.70 mills/kWh. A
comparison of existing and provisional rates follows:
Salt Lake City Area/Integrated Projects Comparison of Existing and
Provisional Firm Power Rates
------------------------------------------------------------------------
Existing Provisional
rates rates
(effective 10/ (effective 12/
92) 94)
------------------------------------------------------------------------
Firm Power Service Rate Schedule.......... SLIP-F4 SLIP-F5
Firm Capacity Charge ($/kW/month)......... $3.54 $3.83
Firm Energy Charge (mills/kWh)............ 8.40 8.90
Composite Rate (mills/kWh)................ \1\18.70 20.17
------------------------------------------------------------------------
\1\The rates calculated at a 58.2-percent load factor can be expressed
as a Combined Rate of 16.72 mills/kWh.
DATES: Rate Schedule SLIP-F5 will be placed into effect on an interim
basis on the first day of the first full billing period beginning on/or
after December 1, 1994, and will be in effect until FERC confirms,
approves, and places the rate schedule in effect on a final basis
through November 30, 1999, or until the rate schedule is superseded.
FOR FURTHER INFORMATION CONTACT:
Mr. Kenneth G. Maxey, Area Manager, Salt Lake City Area Office, Western
Area Power Administration, 275 East 200 South, Suite 475, Salt Lake
City, UT 84111, (801) 524-6372
Ms. Deborah M. Linke, Chief, Rates and Statistics Branch, Western Area
Power Administration, P.O. Box 3402, Golden, CO 80401-0098, (303) 275-
1618
Mr. Joel Bladow, Assistant Administrator for Washington Liaison,
Western Area Power Administration, Room 8G-027, Forrestal Building,
1000 Independence Avenue SW., Washington, DC 20585-0001, (202) 586-5581
SUPPLEMENTARY INFORMATION: By Amendment No. 3 to Delegation Order No.
0204-108, published November 10, 1993 (58 FR 59716), the Secretary of
Energy (Secretary) delegated (1) the authority to develop long-term
power and transmission rates on a nonexclusive basis to the
Administrator of Western; (2) the authority to confirm, approve, and
place such rates into effect on an interim basis to the Deputy
Secretary; and (3) the authority to confirm, approve, and place into
effect on a final basis, to remand, or to disapprove such rates to
FERC. Existing DOE procedures for public participation in power rate
adjustments (10 CFR Part 903) became effective on September 18, 1985
(50 FR 37835).
These power rates are established pursuant to section 302(a) of the
DOE Organization Act, 42 U.S.C. 7152(a), through which the power
marketing functions of the Secretary of the Interior and the Bureau of
Reclamation (Reclamation) under the Reclamation Act of 1902, 43 U.S.C.
371 et seq., as amended and supplemented by subsequent enactments;
particularly section 9(c) of the Reclamation Project Act of 1939, 43
U.S.C. 485h(c); and other acts specifically applicable to the project
system involved, were transferred to and vested in the Secretary.
The main issues raised at public meetings and in written comments
included (1) cost projections used in the Power Repayment Study (PRS),
(2) water depletion schedules assumed for future power projections, and
(3) estimated future prices for purchased power. Western has considered
all comments in preparation of the provisional rates.
Rate Order No. WAPA-63, confirming, approving, and placing the
proposed Integrated Projects rate adjustment into effect on an interim
basis, is issued, and the new Rate Schedule SLIP-F5 will be promptly
submitted to FERC for confirmation and approval on a final basis.
Issued in Washington, D.C. October 24, 1994.
William H. White,
Deputy Secretary.
Order Confirming, Approving, and Placing the Salt Lake City Area/
Integrated Projects Firm Power Service Rates Into Effect on an Interim
Basis
In the Matter of Western Area Power Administration Rate
Adjustment for Salt Lake City Area/Integrated Projects
October 24, 1994.
[Rate Order No. WAPA-63]
These power rates are established pursuant to section 302(a) of the
Department of Energy (DOE) Organization Act, 42 U.S.C. 7152(a), through
which the power marketing functions of the Secretary of the Interior
and the Bureau of Reclamation (Reclamation) under the Reclamation Act
of 1902, 43 U.S.C. 371 et seq., as amended and supplemented by
subsequent enactments, particularly section 9(c) of the Reclamation
Project Act of 1939, 43 U.S.C. 485h(c), and other acts specifically
applicable to the project system involved, were transferred to and
vested in the Secretary of Energy (Secretary).
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993 (58 FR 59716), the Secretary delegated (1) the
authority to develop long-term power and transmission rates on a
nonexclusive basis to the Administrator of Western Area Power
Administration (Western); (2) the authority to confirm, approve, and
place such rates into effect on an interim basis to the Deputy
Secretary; and (3) the authority to confirm, approve, and place into
effect on a final basis, to remand, or to disapprove such rates to the
Federal Energy Regulatory Commission (FERC). Existing DOE procedures
for public participation in power rate adjustments (10 CFR Part 903)
became effective on September 18, 1985 (50 FR 37835).
Acronyms and Definitions
As used in this rate order, the following acronyms and definitions
apply:
$/kW/month: Monthly charge for capacity (i.e., $ per kilowatt (kW)
per month).
AF: Acre-foot. The amount of water necessary to cover 1 acre of
land to a depth of 1 foot.
Basin Fund: That account in the U.S. Department of the Treasury,
established by the Colorado River Storage Project (CRSP) Act.
Billing Demand: The greater of (1) the highest 30-minute demand
measured during the month up to, but not in excess of, the delivery
obligation under the power sales contract or (2) the contract rate of
delivery.
Capacity Component: Part of a firm power rate; shown in the power
repayment study (PRS) as a dollar per kW per year charge. Billed on a
dollar per kW per month basis. Applied each billing period to each kW
which each contractor is entitled by contract.
Categorical Exclusion: Characterizes an action which does not
individually or cumulatively have a significant effect on the human
environment and which has been found to have no such effect in
procedures adopted by a Federal agency and for which, therefore,
neither an environmental assessment nor an environmental impact
statement is required.
CME: Capitalized movable equipment.
Collbran: Collbran Project.
CREDA: Colorado River Energy Distributors Association.
CROD: Contract rate of delivery. Capacity the supplier of electric
service agrees to have available for delivery. It may or may not be
accompanied by energy.
CRSM: Colorado River Simulation Model.
CRSP: Colorado River Storage Project.
CRSP Act: Act of April 11, 1956, ch. 203, 70 Stat. 105, as amended,
43 U.S.C. 620-620o.
CWIP: Construction work in progress.
Customer Brochure: A document prepared for public distribution
explaining the background of the rate proposal.
Demand: The rate at which electric capacity is delivered to or by a
system over any designated period of time.
DOE: U.S. Department of Energy.
DOE Order RA 6120.2: An order dealing with power marketing
administration financial reporting.
EA: Environmental assessment.
EIS: Environmental impact statement.
Energy Component: Part of a firm power rate; expressed in mills per
kilowatthour (kWh). Applied to each kWh made available to each
customer.
Exception Criteria: An agreement between Reclamation and Western
setting forth conditions for operating the Glen Canyon Dam outside of
test flows and subsequent interim operating criteria, including system
regulation, emergency situations, and for the specific purpose of
avoiding high-cost replacement power purchases.
FERC: Federal Energy Regulatory Commission.
FPOD: Federal point of delivery.
FY: Fiscal year.
Glen Canyon Dam: The dam on the Colorado River which forms Lake
Powell.
Glen Canyon Dam EIS: Glen Canyon Dam Environmental Impact
Statement.
GCPA: Grand Canyon Protection Act of 1992.
IDC: Interest during construction.
Integrated Projects: The Salt Lake City Area/Integrated Projects,
which encompass the combined sales and resources of the CRSP, Collbran,
and Rio Grande Projects.
Interior: U.S. Department of the Interior.
kW: Kilowatt; 1,000 watts.
kWh: Kilowatthour; the common unit of electric energy, equal to one
kW taken for a period of 1 hour.
Load: The amount of capacity or energy delivered or required at any
specified point or points on a system. Load originates primarily with a
customer's energy-consuming equipment.
M&I: Municipal and industrial.
Mill: Unit of monetary value equal to .001 of a U.S. dollar; i.e.,
1/10th of a cent. Used to express wholesale energy and composite
electric rates.
Mills/kWh: Mills per kilowatthour.
MW: Megawatt; 1,000 kW; 1,000,000 watts.
NEPA: National Environmental Policy Act of 1969.
OMB: Office of Management and Budget.
O&M: Operation and maintenance. Pinch-Point: The FY in which the
level of the rate is set as dictated by a revenue requirement in some
future year to meet relatively large annual costs or to repay
investments which come due.
PMA: Power marketing administration.
PRS: Power repayment study.
Reclamation: Bureau of Reclamation, U.S. Department of the
Interior.
Regional Office: Bureau of Reclamation's Regional Office.
RGP: Rio Grande Project.
SLCA: Salt Lake City Area.
SLCAO: Salt Lake City Area Office.
Upper Basin States: Colorado, New Mexico, Utah, and Wyoming.
UCRC: Upper Colorado River Commission.
Watt: The electrical unit of power or rate of doing work. It is
analogous to horsepower or foot-pounds per minute of mechanical power.
One horsepower is equivalent to approximately 746 watts.
Western: Western Area Power Administration, U.S. Department of
Energy.
WSCC: Western Systems Coordinating Council.
Effective Date
The new rates will become effective on an interim basis on the
first day of the first full billing period beginning on or after
December 1, 1994, and will be in effect pending FERC's approval of them
or substitute rates on a final basis through November 30, 1999, or
until superseded.
Public Notice and Comment
The Procedures for Public Participation in Power and Transmission
Rate Adjustments and Extensions, 10 CFR Part 903, have been followed by
Western in the development of this firm power rate. The provisional
firm power rate represents an increase of more than 1 percent in total
Integrated Projects revenues; therefore, it is a major rate adjustment
as defined at 10 CFR Secs. 903.2(e) and 903.2(f)(1). The distinction
between a minor and a major rate adjustment is used only to determine
the public procedures for the rate adjustment.
The following summarizes the steps Western took to ensure
involvement of interested parties in the rate process:
1. A preliminary Federal Register notice (FRN), published July 1,
1993 (58 FR 35449), invited interested parties to participate in the
determination of whether an Integrated Projects' firm power rate
increase was necessary. Western also invited participation in deciding
the issues that should be addressed in the process.
2. Several informal meetings were held between the publication of
the July 1, 1993, FRN and the beginning of the public rate adjustment
process. These meetings, involving personnel from Western, Reclamation,
and represen- tatives from organizations of interested parties,
produced many issue papers that identified and discussed the items
which should be considered in a firm power rate adjustment. Agreement
as to how to approach many of the issues was reached during this time,
considerably reducing the number of unresolved issues and easing the
later formal public process.
3. On December 27, 1993, letters were mailed from Western's
Loveland, Phoenix, and Salt Lake City Area Offices to all Integrated
Projects customers and other interested parties announcing an informal
public meeting to be held on January 31, 1994.
4. At the informal meeting held on January 31, 1994, Western and
Reclamation representatives explained the need for a rate increase and
answered questions.
5. An FRN was published on April 21, 1994 (59 FR 19008), officially
announc- ing the proposed firm-power rate adjustment, initiating the
public consultation and comment period, announcing the public
information and public comment forums, and presenting procedures for
public participation.
6. On April 22, 1994, a rate announcement package was mailed from
Western's Salt Lake City Area Office to all Integrated Projects
customers and other interested parties announcing the publication of
the FRN of April 21, 1994, and the beginning of the formal public
process to adjust firm power rates. The package contained (1) a letter
announcing the upcoming public information and comment forums, (2) a
copy of the April 21 FRN, and (3) a copy of the April 1994 Integrated
Projects Firm Power Rate Adjustment brochure. Rate announcement
packages were mailed to customers served by Western's Loveland and
Phoenix Area Offices on April 25, 1994.
7. At the public information forum held on May 24, 1994, Western
and Reclamation representatives explained the need for the rate
increase in greater detail and answered questions.
8. The comment forum was held on June 30, 1994, to give the public
an opportunity to comment for the record. Four persons representing
customers and customer groups made oral comments.
9. Nine comment letters were received during the 97-day
consultation and comment period. The consultation and comment period
was originally scheduled to end on July 20, 1994. A letter was sent to
all interested parties from the SLCAO on July 19, 1994, stating that
Western would continue to accept written comments through July 27,
1994. Letters were mailed from the Loveland and Phoenix Area Offices on
July 20, 1994. All comments submitted by the end of the comment period
have been considered in the preparation of this rate order.
Project History
The Integrated Projects consist of the CRSP and the Rio Grande and
Collbran Projects. The projects were integrated for marketing and
ratemaking purposes on October 1, 1987. The goals of integration were
to increase marketable resources, simplify contract and rate
development and project administration, assure repayment of Collbran
and Rio Grande Projects' costs, and create a common rate. The projects
maintain their individual identities for financial accounting and
repayment purposes, but their revenue requirements are integrated into
one PRS for ratemaking.
Power Repayment Studies
PRSs are prepared each FY to determine if power revenues will be
sufficient to pay, within the prescribed time periods, all costs
assigned to power. Repayment criteria are based on law, policies,
authorizing legislation, and DOE Order RA 6120.2.
Existing and Provisional Rates
A comparison of the existing and provisional rates follows:
Salt Lake City Area Integrated Projects Comparison of Existing and
Provisional Firm Power Rates
------------------------------------------------------------------------
Existing Provisional
rates rates
(effective 10/ (effective 12/
92) 94)
------------------------------------------------------------------------
Firm power service rate schedule.......... SLIP-F4 SLIP-F5
Firm capacity charge ($/kW/month)......... $3.54 $3.83
Firm energy charge (mills/kWh)............ 8.40 8.90
Composite rate (mills/kWh)................ 18.70\1\ 20.17
------------------------------------------------------------------------
\1\The rates calculated at a 58.2-percent load factor can be expressed
as a combined rate of 16.72 mills/kWh.
Certification of Rate
Western's Administrator has certified that the Integrated Projects
firm power rate placed into effect on an interim basis herein is the
lowest possible consistent with sound business principles. The rate has
been developed in accordance with agency administrative policies and
applicable laws.
Discussion
Many factors influenced this rate adjustment. The items having an
impact upon the proposed Integrated Projects firm power rates are
summarized in the table below. Because rates must earn sufficient
revenues to pay for estimated future costs, the table compares the
change in the average annual projections used in the FY 1991 Rate Order
PRS (which set the rate effective October 1, 1992) and the ratesetting
PRS prepared for this rate adjustment.
Major Factors Affecting the Integrated Projects' Firm Power Rate
------------------------------------------------------------------------
Change in
average
annual Estimated
Event revenue rate effect
requirement (mills/kWh)
($000,000)
------------------------------------------------------------------------
Increase in Colorado River Storage Project
(CRSP) Transmission and Other Miscellaneous
Revenues: primarily, compensation for new
Phase-Shifter services (for Western System
Coordinating Council loop-flow mitigation). $-2.6 -0.33
Increase in CRSP Operation & Maintenance
(O&M) Expense: $2.8 million per year due to
inclusion of CME interest (inadvertently
omitted from current rate); Remainder due
to shifting of field crews from
construction to maintenance work........... 8.2 1.05
Increase in Small Project O&M Expense: Rio
Grande Project is one of Western's oldest
projects, and O&M increases with age;
Collbran has many small irrigation dams
needing repair............................. 1.1 0.14
Increase in Purchased Power and Transmission
Expense: The environmentally-related flow
restrictions already in place at CRSP
powerplants require Western to purchase
additional power to meet contractual
delivery obligations....................... 1.6 0.20
$51.2 million in historical environmental
expenses made nonreimbursable by Grand
Canyon Protection Act (plus $9.1 million
associated with deferred interest expense);
Applied to outstanding deficits............ -0.5 -0.06
Passage of Grand Canyon Protection Act made
certain future environmental costs
nonreimbursable............................ -1.0 -0.13
Increase in Interest on Project Investment:
The increase in power investment and unpaid
deficits since the October 1992 rate
adjustment resulted in an increase in
annual interest due........................ 2.1 0.27
Increase in Project Additions and
Replacements: As noted on page 13 of Rate
Brochure, $80.5 million was omitted from
CWIP in the October 1992 rate adjustment... 1.2 0.15
Increase in aid to CRSP irrigation and
participating projects: Investment is very
similar to October 1992 rate adjustment;
however, there are 63 total years to pay
for the investment, rather than the 65
years used previously since both studies
have the pinch-point year of 2057. The
change in the divisor results in the annual
increase................................... 1.4 0.18
---------------------------
Totals.................................. $11.5 1.47
------------------------------------------------------------------------
The existing and proposed revenue requirements for the Integrated
Projects are as follows:
Integrated Projects Average Annual Firm-Power Revenue Requirements
------------------------------------------------------------------------
Estimated average
annual FY 1995-99 firm
power revenue ($000)
-----------------------
SLIP-F4 SLIP-F5
------------------------------------------------------------------------
Firm power revenue.............................. \1\$109,26
5 \2\$122,41
3
------------------------------------------------------------------------
\1\From FY 1991 Rate Order PRS.
\2\From Ratesetting PRS.
The rate increase is necessary to satisfy the cost-recovery
criteria set forth in DOE Order No. RA 6120.2. This rate schedule,
which will be effective on an interim basis beginning December 1, 1994,
replaces Rate Schedule SLIP/F4 which FERC approved through September
30, 1996 at 62 FERC 61,159 (February 18, 1993).
Statement of Revenue and Related Expenses
The following table provides a summary of revenue and expense data
through the 5-year proposed rate approval period.
Salt Lake City Area/Integrated Projects Comparison of 5-Year Rate Period
Revenues and Expenses ($1,000)
------------------------------------------------------------------------
Ratesetting FY 1991 rate
Revenues PRS 1995- order PRS Difference
1999 1995-1999
------------------------------------------------------------------------
Revenue Distribution:
O&M......................... $237,483 $218,540 $18,943
Environmental............... 19,295 37,223 -17,928
Net purchased power\2\...... 972 -1,953 2,925
Transmission................ 35,785 31,695 4,090
Interest.................... 229,029 188,103 40,926
Miscellaneous expenses\3\... 45,976 20,430 25,546
Investment repayment........ 102,255 99,189 3,066
-----------------------------------------
Total\4\.................. \1\670,795 \5\593,227 \6\77,568
------------------------------------------------------------------------
\1\To be comparable with the FY 1991 Rate order PRS, the ratesetting
PRS' ``Other Miscellaneous Revenues'' (from sales of surplus off-peak
energy) were deducted from the total revenues and were combined with
total purchased power expense.
\2\Net Purchased Power Expenses (Ibid.). Negative net purchase power
expense figures imply surplus sales in excess of total purchase power
expenses. Likewise, positive net purchase power expense figures imply
total purchase power expenses in excess of total power sales.
\3\Interest on undepreciated CME, annual liability for the Civil Service
Retirement System, and annual gross power-related requirements for the
Collbran, Provo River, Rio Grande, and Seedskadee Projects.
\4\Includes repayment of capitalized deficits.
\5\Does not equal Total Revenues due to rounding.
\6\Ibid.
Basis for Rate Development
The provisional Integrated Projects rate was designed to continue
to maintain an approximate 50/50 split between revenue earned from
demand charges and that earned from energy charges. The cost to
individual customers will vary because of differences in the amounts of
capacity and energy they purchase from the Integrated Projects.
The provisional rate contains a $3.83/kW/month firm-capacity charge
and an 8.90 mills/kWh firm-energy charge in FY 1995. The necessary
composite rate is 20.17 mills/kWh, which is an increase of 7.9 percent
above the existing rate. The rate terminates on November 30, 1999.
Comments
During the 97-day comment period, Western received nine letters
commenting on the rate adjustment. One letter was received after the
close of the comment period. Additionally, four persons commented
during the June 30, 1994, public comment forum. All comments received
by the end of the comment period were reviewed and considered in the
preparation of this rate order. Written comments were received before
the comment deadline from the following sources:
Bountiful City Light and Power (Utah)
Bridger Valley Electric Association (Wyoming)
Colorado River Energy Distributors Association (Arizona, Colorado,
Nevada, New Mexico, Utah, and Wyoming)
Energy Strategies, Inc. (Utah)
Garkane Power Association, Inc. (Arizona and Utah)
Intermountain Consumer Power Association (Nevada and Utah)
Irrigation and Electrical Districts Association of Arizona (Arizona)
Upper Colorado River Commission (Colorado, New Mexico, Utah, and
Wyoming)
Utah Municipal Power Agency (Utah)
Representatives of the following organizations made oral comments:
Colorado River Energy Distributors Association (Arizona,
Colorado, Nevada, New Mexico, Utah, and Wyoming)
Intermountain Consumer Power Association (Nevada and Utah)
Irrigation and Electrical Districts Association of Arizona
(Arizona)
Platte River Power Authority (Colorado)
Most of the comments received at the public meetings and in
correspondence dealt with cost, purchased power, and water depletion
projections.
The comments and responses, paraphrased for brevity when it does
not affect the meaning of the statement(s), are discussed below. Direct
quotes from comment letters are used for clarification where necessary.
The issues discussed are: (1) Depletion-related issues, (2)
purchased power expense, (3) future flow restrictions at Glen Canyon
Dam, (4) O&M-related issues, (5) construction-related projections, (6)
environmentally-related expenses, (7) miscellaneous comments, and (8)
issue paper resolution.
1. Depletion-Related Issues
Extensive comments were made regarding the deferred recognition of
water depletions for water projects in the Colorado River Basin after
FY 2010. Western's responses are listed sequentially:
a. Comment: Western is being guided solely by RA 6120.2 in the
rate-setting process without paying sufficient attention to the CRSP
Act of 1956 and other relevant legislation. The rate does not
accurately reflect the intent of the CRSP Act, which is to produce
rates that result in full repayment of the power system costs.
Response: Western disagrees. Western complies with requirements of
the CRSP Act of 1956, other relevant legislation, and DOE Order RA
6120.2 in assuring repayment of all CRSP costs assigned to power.
Legislation takes precedence when there is conflict with DOE Order RA
6120.2.
Treatment of depletions in the same manner has been approved by
FERC twice prior to the present rate adjustment. Two of FERC's criteria
for rate approval are whether the proposed rate will repay all
obligations assigned to power in full and on time consistent with
requirements of the CRSP Act and whether the methodology which achieves
this result is in compliance with DOE Order RA 6120.2. The requested FY
1995 rate adjustment meets these criteria and satisfies all repayment
requirements.
b. Comment: If power rates are set without providing for future
depletions, it will affect Upper Basin development under the (Colorado
River and Upper Colorado River Basin) compacts. Every time someone
wants to build a project or open a business that will deplete water,
the power rates will have to go up if those increased depletions have
not already been factored into the rates.
Can full repayment be truly represented by rates derived assuming
water is available for release through powerplants when that water will
not be available because of depletions by the Upper Division States
above the powerplants?
Response: Total depletions forecasted by the Basin States for the
use of Colorado River water have been included in the proposed rate.
The water has been allocated by compacts for use by the Upper Basin
States. Furthermore, Western is obligated to assure that funds are
available on schedule to meet repayment requirements regardless of
depletion schedules.
In its proposed treatment (deferral) of uncertain depletions,
Western assumes that greater amounts of Colorado River water will be
available for release through CRSP powerplants than would be suggested
by current rapid-growth forecasts of water development projects and
their associated depletions.
Western's experience has been that out-year depletion estimates are
subject to frequent revision. It is reasonable, therefore, to give more
weight to near-term projections. Western prepares an annual PRS for
every project to assure that repayment is proceeding satisfacto- rily.
Thus, there will be many future opportunities to revise the Integrated
Projects rate appropriately as the near-term projections are changed
and more accurate long-term estimates are made available.
Western has determined that depletions affect the firm power rate,
at most, by 0.32 mills/kWh (composite). The impact is small enough so
that power rates could (and would) be adjusted to assure full
repayment, if more rapid depletions take place in the Upper Basin
States. It is not likely that this small impact on power rates would
constrain water depletions.
c. Comment: By its own terms the 1983 Agreement between Reclamation
and Western does not apply to State and private projects or
developments and that the agreement reveals the parties' intent to use
full depletion levels in setting rates under the terms of the
Agreement.
Response: Western disagrees that the intent of the 1983 Agreement
was for Western to use ``full'' (or ultimate) depletion levels in
setting rates. Rather, a provision of the agreement that addresses
depletions only requires that water depletion schedules used for power
repayment studies ``. . . be consistent with construction schedules for
participating projects.''
Western agrees that provisions of the 1983 Agreement between
Western and Reclamation did not explicitly address State and private
projects or developments. In defining a ``reasonable expectation
standard,'' the 1983 Agreement establishes necessary steps by
Reclamation to demonstrate the potential for construction of future
Federal participating projects before the costs of these projects would
be included in the ratesetting years. This reasonable expectation
standard has been applied to the future development of all water
development projects for ratesetting purposes by Western in setting the
lowest possible rates consistent with sound business principles.
Therefore, Western has included total depletions forecasted by the
Upper Basin States for the use of Colorado River water for all
projects, with deferral of less-certain water developments (depletions)
beyond the ratesetting period in the proposed rate. Future rate
adjustments will allow for movement of depletions into the rate-
setting years.
d. Comment: Western arbitrarily suppressed depletions from 2010
through 2090 only justified by the fact that such a method of
suppression (capping) was utilized in the 1990 study and did so without
adequate consultation with Reclamation.
Response: The decision by Western to defer uncertain depletions
beyond the ratesetting period is not arbitrary. In the 1990 rate
process, Western gave considerable attention to the reasonableness of
the then-proposed depletion deferral and to the associated rate effect
when applied. Further, Western has given renewed and height- ened
attention to the treatment of depletions in the proposed rate through
preparation of numerous issue papers, informal discussions with both
customer and water user representatives, and in Western's April 1994
rate brochure.
Figure 1, on page 12-5 of the rate brochure, shows that Western
presently assumes full development (full depletions) of all Upper Basin
water projects by FY 2090.
Projects with uncertain schedules have been placed in the PRS so
that they do not impact the rate at this time, in accordance with
Western's practice to set the lowest possible rate consistent with
sound business principles.
Western also disagrees with the claim that inadequate consultation
occurred with Reclamation in the past on this deferral treatment.
Reclamation, along with other interested parties, has either
participated in or has attended many of the public forums scheduled in
the development of all Integrated Projects rate proposals. In these
public forums, Western has detailed the components of the rate
adjustment, including the treatment of depletions. Reclamation and
interested parties have been and will continue to be afforded ample
notice and opportunity to comment on future rate proposals.
e. Comment: Five comments said: DOE RA 6120.2 seems to require the
use of operation studies based on historical streamflows including
hydrologic data current to within 5 years.
Response: Western believes that it is in compliance with DOE RA
6120.2. This requirement is valid for most projects. However,
exceptions, as discussed in DOE RA 6120.2, Section 10.e.(4), are
provided for those projects which are anticipated to have extensive
water development in the future. CRSP operation studies are based on
historic streamflows, which are then reduced by projected water
depletions supplied by the Upper Basin States and modified by
Reclamation.
f. Comment: Western suggests that its departure from the 1990
depletion schedule represents better data than utilized by Reclamation
in its energy and capacity studies.
Response: Both Reclamation and UCRC staff have told Western infor-
mally that the depletion schedule used in this process is a more
accurate reflection of the current situation than the earlier ``Energy
and Capacity Studies'' which was available when the ratesetting PRS was
prepared.
g. Comment: The 1990 cap at 2010 resulted in an approximate 11-
percent reduction of Basin States' depletions and an artificially low
power rate. The proposed super-imposition of a 1990 mentality beginning
in 2010 to a substantially revised 1992 unofficial depletion schedule
results in excess of 20-percent reduction of depletions and does not
even fully recognize the future depletions of projects currently under
construction.
Response: Western agrees that the deferral of some estimated deple-
tion effects until 2060 suggests a significant (20-percent) reduction
from the 1992 depletion schedule contained in the CRSM demand data.
Western believes there should be greater certainty of development
regarding this 20-percent prior to including the associated reduction
in hydrogeneration in the PRS in a way that affects the firm power
rates. Also, Western agrees that its deferral postpones future
depletions of projects currently under construction, based on the
principles of the 1983 agreement. Again, because the timing of the
development of the associated consumptive use is uncertain, Western
chooses to not include future depletions within the ratesetting years.
As more current information is supplied by the UCRC to Reclamation,
Western will apply the ``reasonable expectation'' standard to these
updated depletions.
h. Comment: Western did not use the depletion schedule dated July
1994 which was received in draft form in April 1994.
Response: Western was provided a draft work-in-progress depletion
schedule by UCRC representatives in April 1994. This latest unofficial
schedule demonstrated a reduced and delayed schedule for development of
Upper Basin projects. However, the schedule had yet to be approved by
the Basin States and, once received by Reclamation, would still have
required considerable work by Reclamation staff to modify depletion
(demand) data used by the CRSM. In addition, subsequent analysis by
Western's power resources and rates staff would have taken considerable
time and effort before new information could be verified and supported
for inclusion in any revised PRS for this proposed rate process. For
example, the final PRS used for the April 1994 rate brochure was
created in March of 1994. Its power projections were the end result of
several months of work by Western and Reclamation resources staff. An
official depletion schedule ready for use in July of 1994 would have
delayed the public process for the current rate adjustment by several
additional months.
Western is responsible for seeing that the Integrated Projects earn
sufficient revenues to pay all of their obligations on time. Such a
lengthy delay in implementing the rate adjustment would have resulted
in increased interest cost to customers, lost revenues, and, as a
result, higher firm power rates.
Western has assured UCRC that when official depletion information
is available, has been incorporated into Reclamation's CRSM data files,
and there is a common understanding of the reasonable certainty of
future water projects, the associated generation effects will be
weighed and a decision made by Western regarding their inclusion in any
future PRS.
i. Comment: The attorney for a customer stated:
. . . the treatment of depletions in this rate case has nothing to
do with the water rights of the Upper Basin States. Nor does it have
anything to do with how those rights will be exercised in the future.
Western has no power over the water rights of the Upper Basin States.
Conversely, the power users should not be punished because of delays in
Upper Basin water use development and fears of Upper Basin water users
that such development may ultimately not occur.
Response: Western agrees with this comment.
2. Purchased Power Expense
Four large customer organizations all commented extensively on
purchased power expense:
a. Comment: A customer organization stated:
The assumed lower prices for surplus energy sales are, in fact, at
odds with recent experience for the SLCA/IP.
It is clear that experience does not support Western's pricing
assumptions, which were based on combining various pricing and cost
data in an inconsistent and somewhat arbitrary fashion. (The commentor)
recommends that Western modify its pricing assumptions by setting
prices for surplus sales at the same levels as those used for
purchases.
Response: Western agrees, in part, with comments that assumed
nonfirm surplus sales pricing in the estimation of future-year net
purchased power expenses does not reflect an extension of historic
pricing trends. This fact is supported in documentation prepared by
Western on the methodology and assumptions developed in previous rate
proceedings and consistently applied again in this proposed rate
adjustment. The imposed restrictions at Glen Canyon Dam have caused
Western to sell off-peak surplus energy. The impact of these sales is
based upon the market conditions. Western has explained that the basis
for assumptions of future surplus sales pricing is based upon
consideration of the potential market conditions. Western assumes that
there will be a need to dispose of limited onpeak surpluses in southern
markets, which will mean competing against low-cost sales from the
Navajo Generating Station. Western will also try to sell significant
surpluses in northern markets, competing against low-cost sales from
regional northern utilities. Certain general conclusions may be drawn:
(1) average nonfirm surplus energy prices, both offpeak and onpeak,
will be less than historic conditions, this also implies that period
pricing (onpeak or offpeak) will be less than recent experience, (2)
historic pricing differentials, onpeak versus offpeak, winter versus
summer season, will continue, and (3) Western's hourly modeling of
constrained operations at Glen Canyon is reasonable.
Though the method developed is believed to be a reasonable tool for
forecasting future surplus sales pricing, Western acknowledges that
some merit exists in comments that suggest a closer link to recent
historic trends is reasonable. Western will continue to refine the
methods for forecasting future market conditions, both purchases and
surplus sales, and will continue to give greater weight to recent
historic pricing trends in future pricing projections.
Western disagrees with the comment which suggests that surplus
sales and purchase pricing should be identical, without consideration
of the nature of the constraint condition at Glen Canyon. The methods
developed by Western for assessment of conditions with and without
interim release constraints at Glen Canyon currently predict (a) that
higher, but acceptable, average purchase prices will result in the near
future from deliveries under several long-term purchase agreements and
(b) lower average surplus sale prices will occur due to significant
``forced sales'' during offpeak and shoulder onpeak hours. However,
should additional operation experience suggest modification to this
base assumption, Western will consider future improvements in the
methods used.
b. Comment: Western applied the hourly modeling of net purchased
power expense to only 3 years. The other years between and beyond the 3
years modeled were estimated based on a regression analysis of the 3
years' results . . . regression analysis using three data points to
interpolate and extrapolate results may be unreliable and is certainly
less than ideal. (The commentor) recommends that the hourly model be
used to calculate annual net expense at least through the year 2002,
when the recovery of the hydrosystem and increases in firm load . . .
have stabilized.
Response: Western disagrees with the suggestion that additional
years of hourly modeling in its current form would significantly
improve the reliability of forecasted net purchase power expenses.
The methodology developed by Western to forecast the net purchase
power expense considers several significant variables such as hourly
firm load and available hourly hydrogeneration in determination of
hourly deficits or surpluses. The method then considers seasonal
variation in purchase and surplus sales pricing structures in
estimation of the net purchase power expense. Given the simplifying
assumptions made in the methods, Western recognizes a significant
correlation between deficit (or surplus) hydrogeneration and the
associated net purchase power expense.
In balancing the limited time required to complete the analysis and
the precision required for the net expense estimate, Western determined
that modeling all hours within each month for 3 years (i.e., 36 months)
would be adequate and that hourly modeling for additional years would
not significantly improve the reliability of the forecasted net
purchase power expense.
Western continues to support the general application of these
methods to express the causal relationship between deficit (or surplus)
hydrogeneration and annual net purchase power expenses. However,
Western acknowledges that some future modifications may be beneficial,
such as (1) additional refinements of the model, (2) validation of key
assumptions, and (3) application of refined methods and assumptions to
additional future periods (i.e., months, years) to increase the sample
size. Such changes will be considered in future net purchase power
expense forecasts.
c. Comment: A large customer organization says that it has been
unable to understand or replicate Western's results.
Response: Western has made a conscientious effort to provide all of
the information needed to develop the purchased power expense analysis
in a timely manner. Western's staff has provided explanations to
customers and their consultants and are available and willing to
provide additional clarification as needed.
3. Future Flow Restrictions at Glen Canyon Dam
a. Comment: A large customer organization expressed concern that
Western has overstated revenues of $3 to $8 million per year from
short-term capacity sales through 2004.
Response: It is improbable that flows restricted for environmental
reasons will ever again provide enough firm power from the Glen Canyon
Unit to reach levels used in past power projections. Western does not
know which of many possible flow regimes will finally be imposed at the
Glen Canyon Unit. The treatment of short-term sales has been consistent
with the firm power assumptions. Therefore, it is impossible to modify
power projections for the proposed rate adjustment to recognize the
reduced power output. The only course of action Western is able to
follow is to stay with historic power projection figures, using the
methodology already used in previous processes, until the Glen Canyon
regime is finally determined.
Western will evaluate the firm power rate then in place when the
new flow regimes from the Glen Canyon Dam are decided. If it is needed,
a firm power rate adjustment will be proposed then.
b. Comment: An organization of several customers stated: While it
is understood that a degree of uncertainty surrounds the exact level of
flows at Glen Canyon, Western should conduct a sensitivity analysis
predicated on the alternative flow assumptions identified in the
Operation of Glen Canyon Dam Environmental Impact Statement. Such
sensitivity analysis (sic) would give customers a range of possible
replacement power costs.
Response: Western has done extensive analyses of the power and rate
impact of every flow regime identified for study in the GCD-EIS.
Detailed descriptions of the studies and their results are reported in
the draft GCD-EIS, and will be contained in the final GCD-EIS when it
is published.
In the meantime, Western is specifically required, by law and by
regulation, to use known or statistically probable estimates of future
activity in creating rates. The level of uncertainty still existing
with the GCD-EIS prevents the use of any of its data at this time. As
is noted above, when a decision about environmentally related flows
through Glen Canyon Dam is made, a revised PRS will be prepared, and a
new rate will be proposed, if needed.
4. O&M-Related Issues
a. Western O&M: CREDA signed an agreement with Western and
Reclamation dated September 24, 1992, which states:
Western shall utilize the Work Program Information made available
to its Customers by Western and Reclamation (including adjustments
thereof which may result from reviews, from internal corrections or the
dispute resolution process provided for in these Joint Procedures but
excluding the costs of future transmission system additions in a
Planning Year or Out Year which are conceptual in nature), to prepare
the power repayment studies upon which it relies to promulgate any
interim or final rates proposed or adopted for SLCAIP firm power or
transmission services.
Several customers and their member organizations are concerned
about the implementation of the 1992 Agreement.
(1) Comment: (One commentor) continues to be concerned with
Western's inconsistent use of budgeted information in the preparation
of the PRS . . . (the commentor) has been some-what frustrated in its
attempts in this rate adjustment process to reconcile certain
information used in the 1994 Rate Brochure PRS with the information
previously provided in the Work Program review process.
Response: The FY 1995 Work Program is merely a copy of the proposed
FY 1994 Congressional Budget Submission. It was used as the starting
point in planning expenditures for the FY 1995 congressional budget.
CREDA's September 1992 agreement with Western and Reclamation
allows power customers to have meaningful input to the new
congressional budget. However, this work program document is prepared
too early in the planning process for either customers or Western to
say that no further changes will be made. Western feels that the timing
and use of documents stated in the agreement should be revisited.
Western is willing to continue to work with the customers in improving
the budget and work plan review process in the future.
To illustrate the process, the transformation of the FY 1995 Work
Program into the final FY 1995 Budget is outlined below:
(a) (The commentor) reviewed the FY 1995 Work Program and had
opportunity to make suggested changes.
(b) The revised FY 1995 Work Program became the FY 1995 Internal
Review Budget. At this point, more changes were made. Those changes
then were reviewed by Western. Further changes, usually a lowering of
spending projections, are common in this stage of budget preparation.
(c) The FY 1995 Internal Review Budget was then sent to Washington
to be approved by DOE. There are usually reductions in spending
estimates at this stage, as well, dictated by DOE's spending
priorities. The DOE-approved budget was called the FY 1995 OMB Budget
Request and was sent to that agency for review and approval. Any
changes were then incorporated into a document called the FY 1995
Congressional Budget Submission.
(d) Finally, the FY 1995 Congressional Budget Submission went
before Congress, where any final changes desired by the legislative
branch of Government were made. Only after it was approved by Congress
after public debate was the final FY 1995 Budget determined.
The FY 1994 Congressional Budget Submission was officially sent to
Congress in January 1993. When the April 1994 rate brochure PRSs were
being prepared, the data in the FY 1994 Congressional Budget
Submission/1995 Work Program was already more than 2 years old (having
begun as the FY 1994 Work Program in early 1992). Because of this
timing, most of the information was outdated.
Western had completed turning the FY 1995 Work Program into the FY
1995 Congressional Budget Submission by that time. As is usually the
case, some of the planned expenditures had been deleted in the process.
Further, because of extra impetus to keep costs down, a Western-wide
decision was made in which O&M costs would be allowed to rise only 2-
percent per year between FYs 1994 and 1996.
In keeping with Western's policy to set rates at the lowest
possible level consistent with sound business principles, Western used
data from the lower-cost (and more current) FY 1995 Congressional
Budget Submission rather than that in the customer-reviewed FY 1995
Work Program in the Rate Brochure PRS.
When Reclamation, Western, and CREDA entered into the September
1992 agreement, the parties did not anticipate that expenditure plans
would change significantly between the Work Program review and the
congressional budget submission. Events have proved otherwise.
Comparison of FY 1995 Work Plan With FY 1995 Congressional Budget Submission O&M Expenses $000
----------------------------------------------------------------------------------------------------------------
FY 1994 FY 1995 FY 1996 FY 1997 FY 1998 Totals
----------------------------------------------------------------------------------------------------------------
1995 Work Plan:
Reclamation................................. $17,898 $18,408 $17,403 $17,884 $16,739 $88,332
Western..................................... 30,894 30,379 30,743 31,481 33,905 157,402
-----------------------------------------------------------------
Total....................................... 48,792 48,787 48,146 49,365 50,644 245,734
1995 Budget:
Reclamation................................. $15,856 $15,925 $16,041 $16,262 $16,631 $80,715
Western..................................... 29,307 27,635 27,971 28,724 28,984 142,621
-----------------------------------------------------------------
Total..................................... 45,163 43,560 44,012 44,986 45,615 223,336
-----------------------------------------------------------------
Decreased Cost to Customers............. -3,629 -5,227 -4,134 -4,379 -5,029 -22,398
----------------------------------------------------------------------------------------------------------------
(2) Comment: Two comments expressed concern that: Western's
projected O&M expenses for 1994 are more than 25-percent higher than
actual O&M expenses in 1993 and more than 20-percent higher than the
1994 O&M expenses included in the 1995 Work Program documents.
Response: Western has been unable to duplicate the analysis in this
comment. Some of the figures in the commentor's table are incorrect.
This gives the impression of a problem where Western believes none
exists. Most significantly, Western's actual FY 1993 CRSP O&M expense
of $17.964 million shown in the commentor's tables is incorrect. The
proper amount, from the Results of Operations (financial statements) as
shown below, is $21.418 million. This should be the basis for the
commentor's percentage calculations.
Below is a table comparing the table submitted by the commentors,
the FY 1995 Work Program, and the amounts used in the PRS.
Western's CRSP O&M ($000)
----------------------------------------------------------------------------------------------------------------
1993 1994 1995 1996 1997 1998
----------------------------------------------------------------------------------------------------------------
Commentor's Table \1\..................................... 17,964 18,628 20,888 21,070 21,437 21,923
Annual Change (%)......................................... 0 4 12 1 2 2
FY 1995 Work Program\2\................................... 26,449 24,555 23,898 24,202 24,882 27,245
Annual Change (%)......................................... 0 -7 -3 1 3 10
Rate Brochure PRS \3\..................................... 21,418 22,530 20,888 21,070 21,437 21,993
Annual Change (%)......................................... 0 5 -7 1 2 3
----------------------------------------------------------------------------------------------------------------
\1\ From comment letter dated July 27, 1994; source of data identified as FY 1995 Work Program.
\2\ From FY 1995 Work Program (i.e., FY Congressional Budget submission), according to CRSP records.
\3\ Using the FY 1995 Congressional Budget submission.
The average annual growth rate in the rate brochure PRS from 1993
through 1996 is a negative 0.33 percent. This is considerably below the
2-percent maximum annual growth rate which is Western's goal.
5. Reclamation O&M
a. Comment: Reclamation explained the increase in Regional Office
expense in 1995 O&M expenses over the level shown in the 1995 Work
Program (which was $564,000) as the inclusion of the Dolores Project
O&M expense. The O&M expenses for the Dolores Project are shown in the
1995 Work Program as $301,000 for 1995, leaving $263,000 of the
increase in this account category unexplained.
Response: The statement that the Regional Office expense in 1995
included the Dolores Project is incorrect. The Regional Office expense
category applies only to the initial CRSP units (i.e., Aspinall,
Flaming Gorge, Glen Canyon, and Navajo), and not to the Dolores
Project. Dolores Project costs are shown in their own, separate PF-3
budget document.
Regional Office expenses shown in the initial units (CRSP) work
plan differ from those included in the PRS because Western
inadvertently used an unofficial version of Reclamation's PF-3. This
document did not differ from the official budget in total costs for the
CRSP initial units. An adjustment within the program was made, which
increased the Regional Office expense by $564,000. This was made to
balance to the FY 1995 Budget Submission funding amount.
b. Comment. The O&M figures (for the Rio Grande Project) in the PRS
appear to double count capitalized moveable equipment (CME) expenses
for the years 1995, 1997, and 1998 . . . .
Response: Western agrees with the comment and has rerun the RGP
study to eliminate this error.
c. Comment: For 1994, the difference in expenses between the Work
Program and the PRS appears to be comprised of the $35,000 for CME less
a $20,500 expense reduction, which is unex- plained.
Response: Western's numbers were correct and have been used in the
PRS. The commentor's table shows a difference of $28,885. There are
four reasons for the difference: (1) O&M expenditures planned for FY
1993 on the Elephant Butte Dam of $67,548 (portion assigned to power =
$67,548 X 20.8% = $14,050) were not spent in FY 1993, but were
obligated and actually spent in 1994; (2) expenditures planned on the
Elephant Butte Powerplant ($30,854, of which 100-percent is repayable
by power revenues) were not spent in FY 1993, but were obligated and
actually spent in FY 1994; (3) the $35,000 referred to as CME for FY
1994 is not CME, but miscellaneous tools which is charged off to O&M
and is properly includable in the total O&M for the year; and (4) item
number (2) was further complicated by the fact that both the Work
Program and the FY 1995 Budget Congressional Submission are based on an
incorrect version of the summarized report. A line item (which should
be included in the Other Expense line) which appears on the detailed
report was coded incorrectly so that it does not appear on the
summarized reports, but is included in the totals of both reports.
Thus, the totals are $40,000 higher in the Work Program than the total
of the numbers shown and $23,921 higher than the total of the numbers
shown in the FY 1995 Congressional Budget Submission. The $40,000
budgeted Other Expense item was later reduced to $23,921, which matches
the $1,141,775 figure shown in the FY 1995 Congressional Budget
Submission. Following is a table which recaps the above information
starting with the figures shown in the commentor's table:
Elephant Butte Powerplant
------------------------------------------------------------------------
1995
1995 Work congressional
Program budget
submission
------------------------------------------------------------------------
Salaries.................................... $532,000 $532,000
Office General Expense...................... 262,000 262,000
CPA......................................... 173,000 173,000
---------------------------
Other Expense\1\............................ 120,000 150,854\2\
Subtotal\3\............................. 1,087,000 1,117,854
Missing Line Item\4\ (other expenses)....... 40,000 23,921
--------------
Total\5\................................ 1,127,000 1,141,775
------------------------------------------------------------------------
\1\Other expenses should have been higher by $40,000 in both the FY 1995
Work Program and the FY 1995 Congressional Budget Submission.
\2\When summed, includes $30,850 carryover from FY 1993.
\3\Actual summation of figure shown.
\4\This amount should have been included in the ``other expense'' line
of both the FY 1995 work program and the FY 1995 Budget
Justifications.
\5\As displayed in the FY 1995 Work Program and the FY 1995
Congressional Budget Submission.
Subtotal--Elephant Butte Powerplant O&M.................... $1,141,775
Less amount shown on commentor's table..................... 1,127,000
------------
Subtotal............................................... 14,775
Add allocated carry-over amount from item (1) above........ 14,050
------------
Total difference shown on commentor's table............ 28,825
------------
The average annual increase in projected O&M expenses which
results in a $8.2 million annual revenue requirement is
troublesome. How this figure was obtained in the modeling
effort undertaken at Western is not explained in detail in
the brochure. If the projected figure is based upon an
extrapolation of historical data adjusted for inflation,
the cost figure may not reflect all of the possible areas
of cost reduction available to both Western and the Bureau
of Reclamation.
Response. Only two projections used in the Integrated
Projects and/or CRSP PRS are based on computer modeling:
the water available for power production and the ultimate
power-related revenue requirements for the participating
projects. Estimates for future O&M expenses are taken
directly from official budgets; the budgets include modest
approximations of labor cost increases. All equipment
spending in the 5-year budget window is made up of actual
projections received from workers in the field, reporting
which equipment is likely to need replacement and when.
Miscellaneous revenue and expense projections are based on
historical averages and known future commitments.
b. Comment. A customer organization said:
The Energy Policy Act of 1992 (EPACT) has served as the
catalyst for increasing competition in wholesale
generation. They would anticipate that Western begin to
streamline its operations in order that it position itself
competitively in the new electricity market.
Response. Western's management is presently looking for
ways to improve customer service while cutting costs
through Western's Strategic Planning initiative. Some of
the decisions made to date include:
(1) Delayering. This is a reduction in the number of
supervisory employees, to reduce red tape and inertia
while increasing customer service. The emphasis will be on
empowering the employees. The initiative is already under
way.4703
(2) Western will limit increases in annual operating
expenses to less than 2-percent per project per year
through FY 1996. Thereafter, increases in annual operating
expenses will not exceed the annual rate of inflation.
(3) As the marketing agent for Federal power, Western will
participate in the decision making process with other
resource agencies whose operating decisions significantly
affect Federal power rate and repayment obligations
whenever possible.
(4) Proposals for construction of new facilities will be
assessed using integrated resource planning principles and
must meet at least one of three criteria before
construction may begin:
(a) Increased revenues from new facilities must exceed
their annual cost over the cost-evaluation period.
(b) Customers must benefit sufficiently to support new
facilities in spite of a possible rate increase.
(c) The new facilities will be funded by non-Western
sources.
A customer organization has a series of questions about
construction-related cost projections.
a. Comment: Some of the commentators said: ... they have
been unable to find support in the 1995 Work Program for a
majority of the significant (>$100,000) additions and
replacements included in the 1994 rate brochure and rate
brochure PRS....
Response: For a detailed outline of the budget process,
Western refers the reader to earlier replies to questions
about O&M. To reiterate, the FY 1995 Work Program had, in
many instances, higher cost projections than the FY 1995
Congressional Budget Submission. Western has used the
lower figures in the ratesetting PRS.
In the case of CRSP construction, this change dramatically
reduced the cost projections. Table VI on pages 12 and 13
of the April 1994 Rate Brochure shows a $276 million
decrease in budgeted power-related construction costs
through FY 1998 between the FY 1995 Work Program (referred
to in the brochure as the FY 1994 Congressional Budget
Submission) and the FY 1995 Congressional Budget
Submission. Western has used the lower figure where it is
considered reliable.
b. Comment: (The commentor) has been unable to find support
for the investments included in the Collbran/Rate Brochure
PRS.
Response: It is not possible to find the correlation
between the investments in a budget document or work
program and those in a PRS without some intermediate
steps.
The annual figures in the 1995 Work Program are only
planned cash expenditures. Investments are large items,
often taking more than 1 year to complete. The total spent
on any one investment, then, is the sum of the annual
expenditures shown in the work programs, plus any
applicable IDC.
Western is required to record an investment in a PRS in the
year that it becomes operational. This permits the
establishment of the proper repayment period and begins
the annual payment of interest on investment (due until
the investment's cost is completely repaid). Future
investments appear in a PRS in the year they are planned
to be in-service, if that is within the 5-year budget
window. Future investments (excluding future replacements)
planned for completion at some time after the 5-year
window are normally excluded from a PRS, unless
legislation directs otherwise (as is the case with the
CRSP's participating projects). Annual cash outlays for an
investment that takes more than 1 year to complete have no
counterpart in a PRS. Indeed, there may be several years
of investment costs shown in work programs and budgets
which do not appear in PRSs. However, the total sum, plus
IDC, will appear in the PRS in the year when the item is
anticipated to be operational.
It is not unusual for the first future year in a budget
document to show projections higher than those shown in
the previous budget document for that same year. It is
common to have obligated amounts at the end of the year
just closed that do not get paid in that year. They are
then carried over and added to the next year. Also, CWIP
that has been completed, but that did not get moved to
plant-in-service in the financial records, is carried over
to the next year (with the assumption that it will be
moved to plant-in-service at that time). This also adds to
the total amount shown in the subsequent year.
c. Comment: (The commentor's) Table 7 below uses
information provided in response to WAPA/CREDA-76 to
illustrate the differences between the 1995 Work Program
and the PRS.4703
(The commentor) believes that some or all of the decrease
may result from elimination or reduction of dam repair
work described in Reclamation's response to (the
commentor's) comments on the 1995 Work Program review. The
increases (i.e., increases over and above the amounts
shown in the 1995 Work Program) are unexplained, however,
by changes presented in the 1995 Work Program. Therefore,
(the commentor) recommends use of the investments shown in
line 31 of table 7 in the Collbran/Rate PRS.
Response: Table 7 in the commentor's July 27 comment letter
displays Collbran investment as shown in the FY 1995 Work
Program. Western agrees with the commentor's figures for
FY 1994 through FY 1998, except that carry-over from FY
1993 must also be added to FY 1994's total number.
Western's brochure study also contained some figures from
the FY 1995 Congressional Budget Submission. There have
since been changes to that budget that have reduced some
of those costs by approximately $450,000. Western has
rerun the Collbran ratesetting PRS using these changes.
The following table illustrates how incremental investment
in budget figures is transformed into a PRS entry. Figures
from Reclamation's FY 1995 Work Program are used. The
Collbran Project was used for this example because it
contains no IDC or multipurpose investment, thereby
simplifying the
illustration.47038,L2,i1,s100,4,4,4,4,4,5,5
Per FY 1995 Work Plan:
Big Meadows Dam.......................................... 200
Cottonwood Dam #2........................................ 72
Atkinson Dam............................................. ...........
Big Creek Dam............................................ 69
Lambert Dam.............................................. ...........
------------
Total.................................................. 341
Per PRS/Financial Statement Entries
Big Meadows Dam.......................................... ...........
Cottonwood Dam #2........................................ ...........
Atkinson Dam............................................. ...........
Big Creek Dam............................................ ...........
Lambert Dam.............................................. ...........
------------
Total.................................................. 0
d. Comment: All years in the (Rio Grande) PRS except 1994 match the
values from the 1995 Work Program. In 1994, the difference is $619,806.
(The values shown in line 14 of Table 9 should be used in the PRS.)
Response: The commentor is correct. An additional $619,806 has
been added to the work program amount shown in FY 1994. Not all of the
work in the Work Program for FY 1993 was completed or posted in that
year. The amounts not completed, including those obligated but not
spent in 1993, were carried over into FY 1994. This was the case with
the $619,806 noted by the commentor. This is necessitated because of
Western and Reclamation's accounting procedures (as explained in the
previous section on the Collbran Project), which require the total
investment (including IDC) to be moved to the plant-in-service account
in the year it becomes operational, rather than recording incremental
amounts of annual spending.
Western has used the figures recommended by the commentor. The
figures are the basis for the projected investment through the cost
evaluation period (FY 1994-98). However, these amounts do not appear in
the PRS in those years. As previously explained (see the example of the
Collbran Project above), these amounts (plus IDC, where applicable) are
shown in the PRS in the year the particular investment is scheduled to
go into service.
e. Comment: Commentor stated that:
The intent of the work program review was to provide a less formal
process through which customers could receive information and provide
input regarding Western's and Reclamation's programs, allowing for this
same information to then be used in determining the adequacy of rates.
In departing in the rate process from data developed in the FY 1995
Work Program, the principal benefit of the process is effectively
undone. Moreover, the departures were not trivial. For Western's O&M
expenses, the 1994 figure used in the Rate Brochure PRS exceeds that
contained in the FY 1995 Work Program by almost $4 million, or 20
percent.
In new construction projects, the commentor identified over $45
million in additional investment included in the PRS that was not
identified or had been excluded in the work program review.
Response: Western has given a detailed explanation of the changes
in the 1994 O&M figures between the FY 1995 Work Program and the 1993
ratesetting PRS earlier in this Rate Order. Construction cost
modifications are also listed in detail.
Western disagrees with the thrust of the commentor's statement. As
Western follows its policy to develop the lowest rate to consumers
consistent with sound business principles, all power customers,
including the commentor's members benefit.
For example, the FY 1995 Work Program includes over $527 million in
construction costs for the SLCAO alone. Deducting what would normally
be excluded from the PRS because it is not planned for completion by FY
1998 leaves $284 million. This figure ($284 million) is still more than
double what Western finally included in the Rate Brochure PRS as new
investment $131 million. The difference between these two figures (the
$284 million in the FY 1995 Work Program and the $131 million in the
Rate Brochure PRS) equals approximately 0.75 mills/kWh in the composite
rate. In other words, following the commentor's instructions would have
resulted in a \3/4\ mills/kWh higher firm power rate than Western is
proposing. Finally, Western will continue to work with its customers to
identify and correct problems with the work program review process.
8. Environmentally Related Expenses
a. Comment: The sum of environmental costs in the 1994 Rate
Brochure is more than $0.5 million greater in 1993 and 1994 than
contained in the FY 1995 Work Program. Western's response to CREDA's
information request (WAPA/CREDA 67) indicated that the additional costs
in 1994 were explained by about $6.0 million in ``unliquidated
obligation'' in 1993. While actual costs were indeed lower than planned
in 1993, the reduction does not explain the still greater increase
indicated in the 1994 rate brochures. Environmental study costs should
be limited to the amounts (with some allowance for carryover from prior
years) developed in the work program process.
Response: To compare environmental costs spent and budgeted for FYs
1993 and 1994 in the 1995 budget and work plan, the unliquidated
obligations must be taken into consideration, as shown below:
Environmental Expenses ($000)
------------------------------------------------------------------------
New
FY 1993 FY 1994 Total Total
------------------------------------------------------------------------
1994 Rate Brochure Appendix..... $11,885 $20,935 $32,820 $32,820
Adjustment...................... 0 490 490 33,310
FY 93 Unliquidated Obligations.. -2,391 0 -2,391 30,919
FY 94 Unliquidated Obligations.. 6,005 -6,005 0 30,919
---------------------------------------
Total Obligations........... 15,499 15,420 30,919 30,919
FY 1995 Work Program............ 16,788 15,463 32,251 32,251
FY 93 Unliquidated Obligations.. -2,391 0 -2,391 29,860
---------------------------------------
Total Obligations........... 14,397 15,463 29,860 29,860
---------------------------------------
Difference................ 1,102 -43 1,059 1,059
------------------------------------------------------------------------
b. Comment: A customer organization says:
It is clear that environmental expenses associated with Glen Canyon
Dam have gotten out of hand, are not under control, and are not being
subjected to any sort of cost-control analysis or audit. They urge
Western to do what it can to urge the Bureau of Reclamation to limit
environmental study expenditures to those that are calculated to
produce necessary, credible information.
Response: As a part of Western's Strategic Planning initiative:
Western will, as the marketing agent for Federal power, participate in
the decision making process whenever possible with other resource
agencies whose operating decisions significantly affect Federal power
rate and repayment obligations. Western will do so to sustain the
marketability of the Federal hydroelectric resource.
9. Miscellaneous Comments
Long-term Capacity Sales:
(1) Comment: (The commentor) notes that there is a discrepancy
between the projection of capacity sales shown in Western's ``1993
Power Projections'' and the values in the PRS. Upon inspection of the
two set of values, it appears that the values used in the PRS may have
been misentered 1 year below the proper year. This causes the amount of
capacity sales to be slightly understated in several years.
Response: Western agrees. Western has checked these data and has
found a disconnect between the kW of capacity sales estimate found in
the work papers and that in the PRS. It appears that the data from FYs
1993 through 2003 in the work papers were put into the PRS in FYs 1994
through 2004. The error has been corrected.
(2) Comment: Western calculates the PRS for Integrated Projects
such that replacements are repaid up to the rate-setting year. In part,
this is due to the assignment of a lower repayment priority (to
irrigation) in the PRS. Assigning the lower priority (to irrigation)
causes a less than optimal rate calculation, since the rate could be
lowered by allowing for some replacements to remain unpaid beginning 9-
10 years prior to the ratesetting year.
Response: Western recognizes that some replacements have been paid
earlier in the PRS than required. Western conducted a test to determine
if forcing payments to irrigation obligations would postpone early
payment of replacements, thus lowering the rate. Forcing payments
reduces the composite rate 0.13 mills/kWh. This change has been made in
the ratesetting PRS.
10. Untimely Responses to Data Requests
a. Comment: Three commentors stated that their consultant did not
receive all the information needed to reconcile certain key portions of
the proposed rate and did not have adequate time to verify all the data
underlying the rate adjustment.
Response: The consultant submitted five official data requests.
Responses were as follows:
------------------------------------------------------------------------
Items of
Data request received by western's data Information mailed by
SLCAO requested western's SLCAO
------------------------------------------------------------------------
May 13, 1994....................... 18 May 20, 1994.
June 3, 1994....................... 9 June 23, 1994.
June 24, 1994...................... 9 June 30, 1994.
July 1, 1994....................... 38 July 19, 1994.
July 8, 1994....................... 8 July 14, 1994.
Total............................ 82
------------------------------------------------------------------------
Customers originally had 97 days to submit comments and request
information; 56 of those days were after the public information forum.
The largest and most detailed request for data was received by Western
on July 1, 1994, which was 19 days before the original close of the
comment period. The final response to this request was faxed to the
consulting firm, on July 19, 1994, 1 day before the original end of the
comment period. Western then extended the date it would accept comments
to July 27, 1994, to provide commentors extra time to prepare a reply.
Western believes that ample time has been allowed for public comment
and that information was furnished to requestors in a timely manner.
However, Western also recognizes that there could be confusion and
misunderstanding regarding the information needed by the commentators
and that some of the information received may not be what was needed.
Western will continue to work with customers and interested parties to
find a more efficient and acceptable process to respond to data
requests and meet the commentors' needs.
b. Comment: A customer organization said:
Given the backdrop of structural changes in the industry and
increasing environmental concerns over hydro power generation, it would
seem that Western should develop a pricing policy based upon a firm
understanding of price sensitivity. The lack of any such analysis is a
major omission.
Response: One of Western's primary concerns is the impact the
prices for its products have on possible sales. Based on knowledge of
the electrical power market, Western's proposed combined rates for firm
power are below other sources of firm electrical power available to
Integrated Projects customers. For this reason, Western has not
undertaken a specific study to analyze price effects on the electrical
power purchased by Western's Integrated Projects customers.
There may be reductions of Integrated Projects energy usage in the
short-term by Western's customers as a result of the proposed increase
in the energy rate. Some of Western's Integrated Projects customers
with their own electrical power generating resources may be faced with
variable costs that allow them to produce energy more cheaply than
purchasing from Western at the proposed new rate. Information on the
cost of generation is considered sensitive and is not available to
Western. However, published sources of information which relate to coal
prices and other components of the variable costs of power generation
indicate that the proposed energy rate is less than Western's estimate
of their cost of generating thermal energy. Western has received no
comments to indicate otherwise.
c. Comment: To help customers respond more completely to Western's
proposals, a customer organization suggests that, in the future, when
Western entertains the thought of extending the time for commenting as
done here, tie the extension to a period of time following completion
of responses to requests for information.
Response: Western believes that the existing customer review
process and the public rate process sufficiently provide for both
flexibility for input and measurability of the progress toward the
completion of a rate.
d. Comment: Several customers concur with changing the expression
of the firm power rate from a `combined rate' to a `composite rate'.
Response: Western agrees with the customer comment and believes
that the composite rate will make the price of Integrated Projects
power more easily comparable with that from other sources.
e. Issue: A customer states that they believe it is very unfair to
continue to increase the burden on the ratepayers to fund
(environmental) studies which will result in further increases in costs
and/or reductions in the amount of power available.
Response: As noted earlier, Western is working with Reclamation to
more closely monitor these costs.
11. Issue Papers Resolution: Several issues which Western believes
would have caused considerable protracted comment were discussed in
detail during the pre-rate-adjustment process of informal meetings
between various stakeholders and the exchange of issue papers. The
stakeholders liked the process. The issues which were resolved in this
process are summarized below:
a. Identifying historic expenses related to the CRSP's Glen Canyon
Unit that became nonreimbursable with the passage of the Grand Canyon
Protection Act of 1992 (GCPA).
b. Agreement about which future Glen Canyon Dam environmental costs
have the potential to become nonreimbursable.
c. General understanding of the functioning of the budget
neutrality stipulations in the GCPA, stating that environmentally
related expenses will be nonreimbursable for FY 1993 through FY 1997
only to the extent that offsetting revenues are received by the
Treasury from other GCPA provisions.
d. The timing of the reallocation of the construction costs of the
Glen Canyon Unit.
e. Identification of those costs of the Central Utah
(participating) Project which are properly excluded from influencing
the Integrated Projects firm power rate.
f. Implementation of a procedure to assure that the Basin Fund has
sufficient cash on hand to pay all operating costs for the CRSP.
Environmental Evaluation
In compliance with the National Environmental Policy Act of 1969,
42 U.S.C. 4321 et seq.; Council on Environmental Quality Regulations
(40 CFR Parts 1500-1508); and DOE NEPA Regulations (10 CFR Part 1021),
Western has determined that this action is categorically excluded from
the preparation of an environmental assessment or an environmental
impact statement.
Executive Order 12866
DOE has determined that this is not a significant regulatory action
because it does not meet the criteria of Executive Order 12866, 58 FR
51735. Western has an exemption from centralized regulatory review
under Executive Order 12866; accordingly, no clearance of this notice
by OMB is required.
Availability of Information
Information regarding this rate adjustment, including PRSs,
comments, letters, memoranda, and other supporting material made or
kept by Western for the purpose of developing the power rates, is
available for public review in the following locations.
Salt Lake City Area Office, Western Area Power Administration, Office
of the Assistant Area Manager for Power Marketing, 257 East 200 South,
Suite 475, Salt Lake City, UT 84111
Western Area Power Administration, Division of Marketing and Rates,
1627 Cole Boulevard, Golden, CO 80401
Western Area Power Administration, Office of the Assistant
Administrator for Washington Liaison, Room 8G-027, Forrestal Building,
1000 Independence Avenue SW., Washington, DC 20585
Submission to Federal Energy Regulatory Commission
The rate herein confirmed, approved, and placed into effect on an
interim basis, together with supporting documents, will be submitted to
FERC for confirmation and approval on a final basis.
Order
In view of the foregoing and pursuant to the authority delegated to
me by the Secretary of Energy, I confirm and approve on an interim
basis, effective December 1, 1994, Rate Schedule SLIP-F5. The rate
schedule shall remain in effect on an interim basis, pending FERC
confirmation and approval of it or a substitute rate on a final basis,
through November 30, 1999.
Issued in Washington, D.C., October 24, 1994.
William H. White,
Deputy Secretary.
Salt Lake City Area Integrated Projects; Arizona, Colorado, Nevada, New
Mexico, Utah, Wyoming; Schedule of Rates for Firm Power Service
Effective
Beginning December 1, 1994, through November 30, 1999, or until
superseded by another rate schedule, whichever occurs earlier.
Available
In the area served by the Salt Lake City Area Integrated Projects.
Applicable
To the wholesale power customers for firm power service supplied
through one meter at one point of delivery, or as otherwise established
by contract.
Character
Alternating current, 60 hertz, three-phase, delivered and metered
at the voltages and points established by contract.
Monthly Rate
Demand Charge: $3.83 per kilowatt of billing demand.
Energy Charge: 8.90 mills per kilowatthour of use.
Billing Demand
The billing demand will be the greater of:
1. The highest 30-minute integrated demand measured during the
month up to, but not more than, the delivery obligation under the power
sales contract, or
2. The contract rate of delivery.
Adjustment for Transformer Losses
If delivery is made at transmission voltage but metered on the low-
voltage side of the substation, the meter readings will be increased to
compensate for transformer losses as provided for in the contract.
Adjustment for Power Factor
The customer will be required to maintain a power factor at all
points of measurement between 95-percent lagging and 95-percent
leading.
Adjustment for Purchased Resources
Purpose of Adjustment
To ensure that Western Area Power Administration (Western) has
sufficient revenues to support resource purchases made necessary
because of restricted generation from Glen Canyon Dam as the result of
restrictions on water releases from the dam.
Applicability
To those contractors who are not receiving service under an Interim
Purchase Amendment to the firm power sales contract.
Adjustment
If Western finds it necessary to purchase resources to replace
generation lost at Glen Canyon Dam because of the above-listed
restrictions, Western will, beginning on the first month that such
purchases are made, include in the contractor's monthly power bill an
estimate of that contractor's proportionate share of net capacity
purchase costs. The cost of purchasing these resources will be offset
by the revenue that Western receives for the sale of energy, if any,
associated with the purchased resources.
In its October bill each year, Western will reconcile the previous
fiscal year's actual purchased power expenses and the monthly estimated
costs paid by the contractor. If the contractor has paid more than its
proportionate share of actual purchased power expenses, the excess
amount will be shown as a credit to the contractor's October power
bill. If the contractor has paid less than its proportionate share of
actual power purchase expenses, Western will add such amount to the
contractor's October power bill.
Notification
If Western finds it necessary to implement this adjustment, it will
give a one-time notification to the contractor and the Federal Energy
Regulatory Commission at least 10 days before initially adding
purchased power cost to the contractor's monthly bill.
[FR Doc. 94-27306 Filed 11-2-94; 8:45 am]
BILLING CODE 6450-01-P
This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.