[Federal Register Volume 59, Number 14 (Friday, January 21, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-1486]
[[Page Unknown]]
[Federal Register: January 21, 1994]
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DEPARTMENT OF ENERGY
Western Area Power Administration
Loveland Area Projects--Notice of Rate Order No. WAPA-61
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of Rate Order No. WAPA-61 Loveland Area Projects Firm
Electric Service and Transmission Rate Adjustments.
-----------------------------------------------------------------------
SUMMARY: Notice is given of the confirmation and approval by the Deputy
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-61
and Rate Schedules L-F4, L-T3, and L-T4 placing increased firm power
rates for capacity and energy and increased firm and nonfirm
transmission rates from the Loveland Area Projects (LAP) into effect on
an interim basis. The interim rates, called 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 Post-1989 General Power Marketing and Allocation Criteria;
Pick-Sloan Missouri Basin Program-Western Division (Criteria) were
published in the Federal Register on January 31, 1986, (51 FR 4012).
The Criteria contractually integrated the resources of the P-SMBP-WD
and the Fryingpan-Arkansas Project (Fry-Ark), both commonly referred to
as the LAP, and called for the establishment of an initial rate for LAP
power.
The combined results of the fiscal year (FY) 1992 power repayment
study (PRS) for the Pick-Sloan Missouri Basin Program (P-SMBP) and the
FY 1992 PRS for Fry-Ark indicate that the existing rates do not yield
sufficient revenue to satisfy the cost-recovery criteria through the
study periods. The proposed P-SMBP-Eastern Division rate schedules in
Rate Order No. WAPA-60 along with the Pick-Sloan Missouri Basin
Program-Western Division (P-SMBP-WD) revenue requirement, will yield
adequate revenue to satisfy the cost-recovery criteria for the P-SMBP.
Rate Order No. WAPA-61 includes the revenue requirement for the P-SMBP-
WD that was discussed in Rate Order No. WAPA-60, and will also satisfy
the cost-recovery criteria for Fry-Ark. The LAP firm power rate was
developed by combining the revenue requirements from the FY 1992 PRSs
for both the P-SMBP-WD and Fry-Ark.
A comparison of existing and provisional rates follows:
Lap Provisional Rate Changes
--------------------------------------------------------------------------------------------------------------------------------------------------------
Provisional rates, February 1, 1994, Provisional rates, October 1, 1994,
Existing rate (FY-1993) and percent change and percent change
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rate Schedule........................... L-F3.......................... L-F4.................................. L-F4.
Composite Rate.......................... 20.06 (mills/kWh)............. 20.67 (mills/kWh) 3.0%................ 21.70 (mills/kWh) 5.0%
Firm Energy............................. 10.03 (mills/kWh)............. 10.33 (mills/kWh) 3.0%................ 10.85 (mills/kWh) 5.0%
Firm Capacity........................... $2.58 ($/kW-month)............ $2.65 ($/kW-month) 2.7%............... $2.85 ($/kW-month) 7.5%
--------------------------------------------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Percent of
Class of service Existing rate (FY 1993) Provisional rate, February 1, 1994 change
----------------------------------------------------------------------------------------------------------------
Firm Transmission........ $1.52 ($/kW-month)................. $1.88 ($/kW-month)................. 23.7
Nonfirm Transmission..... 2.1 (mills/kWh).................... 2.6 (mills/kWh).................... 23.8
----------------------------------------------------------------------------------------------------------------
DATES: Rate Schedules L-F4, L-T3, and L-T4 will be placed into effect
on an interim basis on the first day of the first full billing period
beginning on or after February 1, 1994, and will be in effect until
FERC confirms, approves, and places the rate schedules into effect on a
final basis for a 5-year period, or until the rate schedules are
superseded.
FOR FURTHER INFORMATION CONTACT:
Mr. Stephen A. Fausett, Loveland Area Office, Western Area Power
Administration, P.O. Box 3700, Loveland, CO 80539-3003, (303) 490-
7201
Ms. Deborah Linke, Director, Division of Marketing and Rates,
Western Area Power Administration, P.O. Box 3402, Golden, CO 80401-
3398, (303) 231-1545
Mr. Joel Bladow, Assistant Administrator for Washington Liaison,
Western Area Power Administration, Room 8G-061, 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 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 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 of Energy (Secretary).
The March 1993 customer brochure explaining the background for the
proposed LAP firm power and transmission rates adjustment was
distributed to all LAP customers and interested parties. In accordance
with procedures for public participation in general rate adjustments
(10 CFR part 903), the comment and consultation period was initiated on
July 8, 1993, with the publication of a Federal Register notice
announcing the proposed rate and procedures for public participation
(58 FR 36682). A public information forum was held on July 20, 1993, in
Northglenn, Colorado. The public comment forum was held on August 30,
1993, in Northglenn, Colorado. The consultation and comment period
ended on October 6, 1993. During this period, interested parties made
comments to Western concerning the proposed rates. Two comment letters
were received, and three people commented orally. All comments were
considered in the preparation of the rate order. Western has concluded
that the LAP rate adjustments are necessary to meet cost recovery
criteria.
In Rate Order No. WAPA-61, results of the Fry-Ark ratesetting PRS
are being compared to the FY 1990 PRS, which is the basis for the
existing rates.
This Rate Order also reflects the revenue requirements for the P-
SMBP-WD. The comparison shows the following differences:
1. The projected operations and maintenance (O&M) expenses
increased for both projects. The P-SMBP-WD O&M expenses for the 100-
year study period have increased by a total of $10.2 million per year,
and Fry-Ark O&M expenses for the 50-year study period have increased by
$0.6 million per year.
2. The purchased power costs projected over the future 6-year
period for P-SMBP-WD are $113 million. These costs are partially
attributable to the extended drought which necessitated Reclamation and
the Corp of Engineers to draw down the reservoirs to an extremely low
level. This has caused Western to project future purchased power
expenses for the next few years until the reservoirs are full again.
Although FY 1993 was an above-average water year, purchased power
expenses are continuing to be projected because the flooding in the
Mid-west severely restricted water releases and therefore severely
curtailed power generation.
3. The revised Fry-Ark cost allocations reduced the overall project
investment costs by over $38.5 million.
Of the above factors, the one item with the greatest rate impact is
the drought, which is reflected in the purchased power expenses and
capitalized unpaid annual expenses. The second greatest impact comes
from O&M expenses which are increasing due to inflation as well as
responding to programmatic and administrative requirements, such as
safety programs and environmental compliance.
Rate Order No. WAPA-61, confirming, approving, and placing the
proposed LAP rate adjustments into effect on an interim basis is
issued, and the new Rate Schedules L-F4, L-T3, and L-T4 will be
submitted promptly to FERC for confirmation and approval on a final
basis.
Issued in Washington, D.C., January 6, 1994.
Bill White,
Deputy Secretary.
Order Confirming, Approving, and Placing the Loveland Area Projects
Firm Power and Transmission Service Rates Into Effect on an Interim
Basis
January 6 , 1994.
In the matter of: Western Area Power Administration Rate
Adjustments for Loveland Area Projects; Rate Order No. WAPA-61.
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 Pick-Sloan Missouri Basin Program and the Fryingpan-
Arkansas Project, were transferred to and vested in the Secretary of
Energy.
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993 (58 FR 59716), the Secretary of Energy delegated (1)
the authority to develop long-term power and transmission rates on a
nonexclusive basis to the Administrator of the 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:
$/kW-month: Monthly charge for capacity (usage--$per kilowatt-
month).
$/kW-year: The annual transmission revenue requirement divided by
the reserved annual transmission capacity.
AC: Alternating current.
BAO: Billings Area Office.
Criteria: Post-1989 General Power Marketing and Allocation Criteria;
Pick-Sloan Missouri Basin Program-Western Division, 51 FR 4012
(January 31, 1986).
CROD: Contract rate of delivery.
Customer Brochure: A document prepared for public distribution
explaining the background of the rate proposals contained in this
rate order.
DC: Direct current.
DOE: Department of Energy.
DOE Order RA 6120.2: An order dealing with power marketing
administration financial reporting.
FERC: Federal Energy Regulatory Commission.
Fry-Ark: Fryingpan-Arkansas Project.
FY: Fiscal year.
GWh: Gigawatthour.
kW: Kilowatt.
kW-month: The greater of (1) the highest 30-minute demand measured
during the month, not to exceed the contract obligation, or (2) the
contract rate of delivery.
kWh: Kilowatthour.
L-F3: Loveland Area Projects existing firm power rate. (Effective
permanently January 28, 1992.)
L-F4: Loveland Area Projects provisional firm power rate. (Effective
February 1, 1994.)
L-T1: Loveland Area Projects existing firm transmission service
rate. (Effective permanently April 29, 1991.)
L-T2: Loveland Area Projects existing nonfirm transmission service
rate. (Effective permanently April 29, 1991.)
L-T3: Loveland Area Projects provisional firm transmission service
rate. (Effective February 1, 1994.)
L-T4: Loveland Area Projects provisional nonfirm transmission
service rate. (Effective February 1, 1994.)
LAO: Loveland Area Office.
LAP: Loveland Area Projects.
MAPP: Mid-Continent Area Power Pool.
MBSG: Missouri Basin Systems Group.
mills/kWh: Mills per kilowatthour.
MW: Megawatt.
NEPA: National Environmental Policy Act of 1969.
O&M: Operation and maintenance.
PMA: Power marketing administration.
PRS: Power repayment study.
P-SMBP: Pick-Sloan Missouri Basin Program.
P-SMBP-ED: Pick-Sloan Missouri Basin Program-Eastern Division.
P-SMBP-WD: Pick-Sloan Missouri Basin Program-Western Division.
Reclamation: Bureau of Reclamation, U.S. Department of the Interior.
Treasury: Secretary of the U.S. Department of Treasury.
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
February 1, 1994, and will be in effect pending FERC's approval of
them, or substitute rates, on a final basis for a 5-year period, 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 these firm power and transmission rates.
The provisional firm power rates represent an increase of more than 1
percent in total LAP revenues; therefore, it is a major rate adjustment
as defined at 10 CFR 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. Discussion of the proposed rate adjustments was initiated on
January 29, 1993, when a letter announcing an informal customer meeting
was mailed to all firm power customers and other interested parties.
The meeting was held on February 9, 1993, in Denver, Colorado. At this
informal meeting, Western representatives explained the need for the
rate increases and answered questions from those attending.
2. On March 12, 1993, a customer brochure was mailed to all
customers and other interested parties, advising them of the delay in
publishing the Federal Register notice. The public information and
public comment forums were also delayed.
3. A Federal Register notice was published on July 8, 1993 (58 FR
36682), officially announcing the proposed firm power and transmission
rate adjustments, initiating the public consultation and comment
period, announcing the public information and public comment forums,
and presenting procedures for public participation.
4. On July 9, 1993, letters were mailed to all LAP firm power and
transmission customers and other interested parties announcing the
publication of the Federal Register notice of July 8, 1993, and the
public information and public comment forums.
5. At the formal public information forum held on July 20, 1993,
Western explained the need for the rate increases in greater detail and
answered questions.
6. At the formal public comment forum on August 30, 1993, three
persons representing customers and customer groups made oral comments.
7. Western received an extensive request for information from one
customer group. We responded by providing data and background
information for the ratesetting PRS.
8. On September 17, 1993, Western sent a letter to all customers
and interested parties answering questions from the July 20, 1993,
public information meeting that were not resolved at that meeting.
9. Three comment letters were received during the 91-day
consultation and comment period. The consultation and comment period
ended October 6, 1993. All formally submitted comments have been
considered in the preparation of this rate order.
Project History
Pick-Sloan Missouri River Basin Program
The initial stages of the Missouri River Basin Project were
authorized by section 9 of the Flood Control Act of 1944 (Pub. L. 534,
58 Stat. 877, 891). The Missouri River Basin Project, later renamed the
P-SMBP to honor its two principal authors, has been under construction
since 1944. The P-SMBP encompasses a comprehensive program of flood
control, navigation improvement, irrigation, municipal and industrial
(M&I) water development, and hydroelectric production for the entire
Missouri River Basin. Multipurpose projects have been developed on the
Missouri River and its tributaries in Colorado, Montana, Nebraska,
North Dakota, South Dakota, and Wyoming.
Fryingpan-Arkansas Project
The Fry-Ark is a transmountain diversion development in
southeastern Colorado authorized by the Act of Congress on August 16,
1962 (Pub. L. 87-590, 76 Stat. 389, as amended by Title XI, Pub. L. 93-
493, 88 Stat. 1486, 1497 (1974)). The Fry-Ark diverts water from the
Fryingpan River and other tributaries of the Roaring Fork River in the
Colorado River Basin on the West Slope of the Rocky Mountains to the
Arkansas River on the East Slope of the Continental Divide. The water
diverted from the West Slope, together with regulated Arkansas River
water, provides supplemental irrigation, M&I water supplies, and
produces hydroelectric power. Flood control, fish and wildlife
enhancement, and recreation are other important purposes of Fry-Ark.
Loveland Area Projects
The Post-1989 General Power Marketing and Allocation Criteria: P-
SMBP-WD (Criteria), published in the Federal Register notice on January
31, 1986 (51 FR 4012), effectively integrated the resources of the P-
SMBP-WD and the Fry-Ark. This operational and contractual integration,
known as LAP, has allowed an increase in marketable resource,
simplification of contract administration, and establishment of a
blended rate of LAP power sales.
However, the P-SMBP and Fry-Ark retain separate financial status.
For this reason, separate PRSs are prepared for each project on an
annual basis. These PRSs are used to determine the ability of the power
rate to generate sufficient revenue for repayment of project investment
and cost during each project's prescribed repayment period. The revenue
requirement from the Fry-Ark PRS is combined with the P-SMBP-WD revenue
requirement derived from the P-SMBP PRS, to develop one rate for LAP
firm power sales.
A complete discussion of the project histories is found in the
March 1993 customer brochure, which is included in the supporting
documentation.
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 the power function. Repayment criteria are based on law,
policies, and authorizing legislation. DOE Order RA 6120.2, section
12b, requires that:
In addition to the recovery of the above costs (operation and
maintenance and interest expenses) on a year-by-year basis, the
expected revenues are at least sufficient to recover (1) each dollar
of power investment at Federal hydroelectric generating plants
within 50 years after they become revenue producing, except as
otherwise provided by law; plus, (2) each annual increment of
Federal transmission investment within the average service life of
such transmission facilities or within a maximum of 50 years,
whichever is less; plus, (3) the cost of each replacement of a unit
of property of a Federal power system within its expected service
life up to a maximum of 50 years; plus, (4) each dollar of assisted
irrigation investment within the period established for the
irrigation water users to repay their share of construction costs;
plus, (5) other costs such as payments to basin funds, participating
projects, or States.
Existing and Provisional Rates
Power Rates
The existing firm power rates and the provisional firm power rates
necessary to meet the revenue requirements for the LAP are listed
below. The provisional rates will be implemented in two steps. Step 1
rates are to become effective on an interim basis on the first day of
the first full billing period beginning on or after February 1, 1994.
Step 2 rates are to become effective on the first day of the first full
billing period beginning on or after October 1, 1994.
A comparison of existing and provisional rates follows:
LAP Provisional Power Rate Changes
----------------------------------------------------------------------------------------------------------------
Provisional rates February Provisional rates October
Existing rates 1, 1994, and percent 1, 1994, and percent
(FY 1993) change change
----------------------------------------------------------------------------------------------------------------
Rate schedule.......................... L-F3 L-F4 L-F4
Composite rate (mills/kWh)............. 20.06 20.67--3.0% 21.70--5.0%
Firm energy (mills/kWh)................ 10.03 10.33--3.0% 10.85--5.0%
Firm capacity ($/kW-month)............. $2.58 $2.65--2.7% $2.85--7.5%
----------------------------------------------------------------------------------------------------------------
Transmission Rates
The existing transmission rates and provisional transmission rates
necessary to meet the revenue requirements for the LAP are listed
below. The rates are to become effective on an interim basis the first
day of the first full billing period beginning on or after February 1,
1994.
LAP Provisional Transmission Rate Changes
----------------------------------------------------------------------------------------------------------------
Percent
Class of service Existing rates (FY 1993) Provisional rates February 1, of change
1994
----------------------------------------------------------------------------------------------------------------
Firm Transmission.............. $1.52 ($/kW-month)............... $1.88 ($/kW-month)............... 23.7
Nonfirm Transmission........... 2.1 (mills/kWh).................. 2.6 (mills/kWh).................. 23.8
----------------------------------------------------------------------------------------------------------------
Certification of Rate
Western's Administrator has certified that the LAP firm power and
transmission rates placed into effect on an interim basis herein are
the lowest possible consistent with sound business principles. The
rates have been developed in accordance with administrative policies
and applicable laws.
Discussion
Firm Power
The Criteria were published in the Federal Register notice on
January 31, 1986 (51 FR 4012). The Criteria operationally and
contractually integrated the resources of the P-SMBP-WD and Fry-Ark.
The integrated resources are referred to as LAP. A blended rate was
established for the sale of LAP power.
The P-SMBP ratesetting PRS reflects the P-SMBP-WD revenue
requirement for the firm power sales as follows:
------------------------------------------------------------------------
P-SMBP-WD
revenue
requirement
------------------------------------------------------------------------
Proposed Increase (February 1994):
Present Revenue Requirement--13.73 mill/kWh x
2,036,000,000 kWh...................................... $27,954,280
Proposed First Step Increase 1.15 mills/kWh x
2,036,000,000 kWh...................................... 2,341,400
-------------
Total................................................. 30,295,680
=============
Proposed Increase (October 1994):
Revenue Requirement-First Increment--14.88 mills/kWh x
1,988,000,000 kWh\1\................................... 29,581,440
Proposed Second Step Increase--.92 mills/kWh x
1,988,000,000 kWh...................................... 1,828,960
-------------
Total................................................. 31,410,400
------------------------------------------------------------------------
\1\Adjusted down from the previous year to reflect actual firm energy
under contract - 1,988,000,000 kWh x 14.88 mills, which is the FY 1993
Western Division composite rate of 13.73 mills plus the increase of
1.15 mills.
The Fry-Ark ratesetting PRS, adjusted to incorporate the savings of
the approved final cost allocation, indicates a decrease in the revenue
requirement from $13,933,200 to $12,855,560 per year. This decrease was
due primarily to an adjustment of approximately $39 million to project
investment as a result of Reclamation's approved final cost allocation
for Fry-Ark. The total Fry-Ark revenue requirement is as follows:
------------------------------------------------------------------------
Fry-Ark
Revenue
requirement
------------------------------------------------------------------------
Present Revenue Requirement............................... $13,933,200
Proposed Decrease......................................... -1,077,640
-------------
Total Proposed Fry-Ark Revenue Requirement.............. 12,855,560
------------------------------------------------------------------------
The Fry-Ark revenue requirement contains two components. The
project has an average annual energy generation of 52,000,000 kWh from
flow-through water. This energy is assigned the current LAP energy
value; i.e., 10.03 mills/kWh. The remaining revenue requirement is
derived from the firm capacity component. This is a procedure used in
the study to account for the Fry-Ark portion of the energy marketed by
LAP.
A table comparing the LAP existing revenue requirement to the
proposed revenue requirement is shown below:
Summary of LAP Revenue Requirements
------------------------------------------------------------------------
Proposed Proposed
Current February 1994 October 1994
------------------------------------------------------------------------
P-SMBP-WD............ $27,954,280 $30,295,680 $31,410,400
Fry-Ark.............. 13,933,200 12,855,560 12,855,560
--------------------------------------------------
Total Lap........ 41,887,480 43,151,240 44,265,960
------------------------------------------------------------------------
To establish the LAP rate. Western developed the revenue
requirements for LAP from the FY 1992 PRSs for both the P-SMBP and Fry-
Ark (Fry-Ark was subsequently adjusted to incorporate the approved
final cost allocation), as shown above. The revenue requirements from
both projects were combined to develop the LAP revenue requirement of
$43,151,240 for the first increment effective on the first day of the
first full billing period beginning on or after February 1, 1994, and
$44,265,960 for the second increment effective on the first day of the
first full billing period beginning on or after October 1, 1994. To
meet the LAP revenue requirements, the two-step rates for firm capacity
and energy were developed and proposed in the March 1993 Customer
Brochure for LAP. This brochure explains the background for the LAP and
how the rate design concept was developed. The brochure was distributed
to all LAP customers and other interested parties. The rate increase is
necessary to satisfy the cost-recovery criteria set forth in DOE Order
RA 6120.2.
Transmission Rate
Prior to August 1, 1982, a transmission rate of 1.0 mill/kWh was
included in transmission service contracts. The first firm transmission
service rate schedule was Schedule P-S WD-T1, which became effective on
August 1, 1982. This schedule was the first P-SMBP-WD transmission rate
that included a capacity charge. The rates under this schedule were 1.1
mills/kWh or $9.60/kW-year. Schedule P-S WD-T3 superseded Schedule P-S
WD-T1 on January 1, 1985, with a rate of 1.3 mills/kWh or $11.40/kW-
year. The present rate, Rate Schedule L-T1, superseded Schedule P-S WD-
T3 on October 1, 1990. This rate is 2.1 mills/kWh or $18.24/kW-year.
Nonfirm transmission service rate schedules using only the energy rate
have been implemented simultaneously with the firm transmission rates.
The LAP rates are developed using a cost-of-service methodology.
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.
Fryingpan-Arkansas Project--Comparison of 5-Year Rate Approval Period
[Revenues and expenses ($1,000)]
------------------------------------------------------------------------
FY 1990 PRS-- Ratesetting
1994-98 PRS--1994-98 Difference
------------------------------------------------------------------------
Total Revenues............. $73,165 $70,360 ($2,805)
============================================
Revenue Distribution:
Operations and
Maintenance........... 14,391 18,189 3,798
Purchased Power and
Transmission Expenses. 14,154 14,980 826
Interest............... 40,487 34,068 (6,419)
Investment Repayment... 4,133 3,123 (1,010)
Capitalized Expenses... 0 0 0
Prior-Year Adjustment.. 0 0 0
--------------------------------------------
Total.............. 73,165 70,360 (2,805)
------------------------------------------------------------------------
Basis for Rate Development--Loveland Area Projects
Firm Power
The P-SMBP PRS calculates the composite rate in mills/kWh for
future firm power (capacity and energy) sales. In the Fry-Ark PRS, the
study calculates the capacity rate in dollars per kW-year. The PRS
adjusts the selected rate until sufficient revenues are generated to
meet the cost-recovery requirement.
Transmission Service
The present rates were developed using a cost-of-service
methodology. Western's first step in this process is to determine the
projected use of the transmission system during the rate approval
period. Western reserves transmission for its own generating
capability, at plant, based on the Criteria and its transmission
commitments based on its transmission planning process.
The second step in designing the transmission rate is to determine
the estimated annual cost of operating, maintaining, and amortizing the
transmission system. Western considers two components in developing
this annual cost. The first is the annual O&M of the transmission
system. The second element is an investment annuity. The annuity is
used to determine the annual cost of amortizing the transmission system
over a 50-year repayment period.
The final step is to divide the costs by the commitments.
Comments
During the 91-day comment period, Western received four sets of
written questions or comments pertaining to this rate adjustment. In
addition, three persons commented during the August 30, 1993, public
comment forum. All comments were reviewed and considered in the
preparation of this rate order.
Written comments were received from the following sources:
Loveland Area Customer Association (COLORADO, WYOMING, KANSAS,
NEBRASKA)
Tri-State Generation and Transmission Association, Inc. (COLORADO,
WYOMING, NEBRASKA)
Kansas Electric Power Cooperative, Inc. (KANSAS)
Representatives of the following organizations made oral comments:
Loveland Area Customer Association (COLORADO, WYOMING, KANSAS,
NEBRASKA)
Tri-State Generation and Transmission Association (COLORADO, WYOMING,
NEBRASKA)
Kansas Electric Power Cooperative (KANSAS)
Comments received at the public meetings and in correspondence
dealt with controlling costs, interest rates and computations, division
of revenue requirements between P-SMBP Eastern and Western Divisions,
revision of Fry-Ark revenue requirements to reflect final cost
allocations, reallocation of energy returned from customers under the
Post-1989 allocations, future construction, financial integration of
Fry-Ark and Pick-Sloan, and a single transmission rate for both Eastern
and Western Divisions of the P-SMBP. Comments received that were
applicable to P-SMBP only were answered in the Record of Decision for
Rate Order No. WAPA-60. The comments and responses applicable to LAP,
paraphrased for brevity, are discussed below. Direct quotes from
comment letters are used for clarification where necessary.
Issue: Western received several comments concerned with escalating
O&M expenses and control of expenses in the future.
Response: Western recognizes the increases in O&M expenses and has
implemented cost-containment measures throughout the agency to review
expenses and budgets. Western presently maintains an open dialogue with
a customer group in P-SMBP-ED to inform them of progress being made and
to gain customer input for Western's planning process. Some Western
Division customers have participated in this interaction but the
majority do not. Western will extend the invitation to the Western
Division customer group to participate in the Eastern Division
interaction or provide a similar opportunity specifically for the
Western Division.
One commenter observed that O&M costs have increased at a rate that
is far greater than the Consumer Price Index (CPI). O&M expenses are
increasing due to inflation which is reflected in the CPI as well as
responding to programmatic and administrative requirements, such as
safety and environmental compliance. These expenses have been reviewed
both internally by Western and with power customer representatives.
Western continues to share the power customers' concerns with
Reclamation, and Western has received assurances that Reclamation will
participate in the cost-containment programs associated with O&M
functions. Western remains committed to cost-containment while striving
for efficiency and providing customer service. Western plans to
continue its O&M expense review process with power customers and
involve customer representatives in its cost-containment discussions.
Issue: One commenter suggested that Western should estimate the
long-term future interest rate in the PRS instead of using the current-
year rate.
Response: Western uses the rate required by DOE Order RA 6120.2,
sections 10.i. and 11.b., for all future investments. Section 10.i.
states that forecasts for PRSs will utilize the rate established by the
Secretary of the Treasury for the latest available year, and that this
rate shall be used for all future years. Section 11.b. defines the
criteria used by the Department of the Treasury to obtain the rate.
The present rate is computed on the basis of interest-bearing
Treasury securities which, at the time the computation is made, have
terms of 15 years or more to maturity. On this basis, short-term
fluctuations in market prices are removed and projections have built-in
stability based upon a ``rolling average'' each year. In effect,
volatile changes in the rate are mitigated through the blending
process.
While it is true that the rate may decrease in the FY 1994 PRS,
estimating a new rate would be no more accurate than the current method
for projecting investment rates 3 or 4 years into the future. In fact,
if such estimates were used in the late 1970's, they would have
resulted in higher revenue requirements. There is no assurance that
this would not happen again in the future.
Issue: Western received a comment that no interest credit is
provided annually in the PRS for the net cash balance accrued during
the year for interest expense that is not due and payable until
yearend. The commenter suggested that Western should revise its method
of computing interest offsets.
Response: The method used to compute interest in the PRS conforms
to DOE Order RA 6120.2, section 10.j., dated September 20, 1979, which
requires that interest shall be the sum of 1 year's interest on the
unpaid balance of each investment plus \1/2\ year's interest on new
investment added and in-service during the year, and interest on
deferred annual expenses (i.e., capitalized deficits). This amount may
be offset by a credit against interest expense if the credit concept is
utilized by the power marketing agency.
The methodology for computing the interest offset varies between
PMAs; DOE Order RA 6120.2 does not prescribe a specific procedure to be
used in making the interest calculation. The methodology employed by
Western incorporates an interest credit for \1/2\ year on all principal
payments made to investments during the current FY, and computes this
credit at the rates of the investments being repaid. No interest credit
is taken for interest collected and retained throughout the year.
This methodology is based on the premise that interest expenses are
equivalent to annual operating expenses such as O&M and are due and
payable throughout the year, not on the last day of the FY. As such,
payments to the Department of the Treasury are made to repay interest
as it is incurred. This approach is recommended by the U.S. General
Accounting Office (GAO) in attachment 3 to a letter dated September 8,
1983, from DOE to the Administrators of the five PMAs.
In attachment 3, GAO reviewed the interest rate practices of four
PMAs (Bonneville Power Administration, Southwestern Power
Administration, Western Area Power Administration, and Southeastern
Power Administration) and provided a draft recommendation that DOE
revise DOE Order RA 6120.2 to incorporate Western's methodology for
computing interest credits. GAO summarized that Western was utilizing
reasonable business principles in the application of the interest
credit.
Western believes that the methodology employed by the P-SMBP and
Fry-Ark PRSs is consistent with sound business and offers a fair and
reasonable credit against interest expenses.
Issue: It was suggested by one customer group that Western should
divide Pick-Sloan revenue requirements on the basis of capacity and
energy rather than energy alone, and that this be done on the basis of
total revenue requirements rather than the incremental basis presently
used.
Response: The different bases for the two marketing plans do not
readily permit an across-the-board comparison of the capacity available
from P-SMBP-WD and P-SMBP-ED. The LAO and BAO determined that the most
appropriate method to distribute costs was on the basis of contributed
energy from each division. This has permitted an ``apples-to-apples''
comparison of each division's resources while continuing to pool
resources and expenses.
The marketing plans of the P-SMBP-ED and the LAP were prepared
independently and take different approaches to the way that capacity is
marketed. In LAP, capacity is marketed on a fixed basis, with ``take-
or-pay'' amounts for monthly capacity. This capacity is marketed with
energy at less than the average customer load factor. P-SMBP-ED
marketed capacity on a proportional basis; that is, capacity is
marketed as a percentage of each customer's total monthly demand. This
method is commonly referred to as the ``X/Y'' method. Also, capacity
for the Eastern Division is marketed with ``load factor'' energy, with
any remaining resources being marketed as peaking capacity without
energy.
Western recognizes that there are numerous ways to market power,
divide expenses, compute available resources, and forecast future
impacts. The method chosen to share costs and revenues between the
Eastern and Western Divisions of P-SMBP is consistent with the
marketing criteria and represents a fair and equitable solution to the
customers of both areas. This decision was made with careful
consideration given to the relative contribution of resources,
investments, and expenses of each division to the total project.
Western does not propose to revise the allocation of firm power revenue
requirements for Eastern and Western Divisions in this rate adjustment.
Western will continue to observe its revenue-distribution methodology
to determine if future circumstances necessitate a change, and will
continue to work with the customers to address these concerns.
Issue: Two commenters requested that Western work with Reclamation
to adjust the power-related investment for the Fry-Ark in the PRS used
in the rate process.
Response: Regarding the level of investment for future projections,
Western believes that it is now appropriate to incorporate the approved
investment level in the PRS. While the figure in the final allocation
may not be exact (due to minor revisions in interest or adjustments to
the time that different investments were booked), Western believes that
the estimate is reliable as a basis for the future investment level.
Western has revised its PRS for Fry-Ark so that new revenue
requirements were determined and a new rate established for LAP. These
changes are incorporated in the first increment of the rate increase,
scheduled for February 1, 1994.
Western is continuing to work with Reclamation to bring the cost
allocation issue to a close. The final allocation was approved by
Reclamation's Assistant Commissioner for Resource Management on August
25, 1993, and Western will be working with Reclamation to reconcile
interest adjustments and obtain a schedule of investments for the
historical period. Until these items are completed, Western will not be
able to adjust financial statements or revise past interest expenses
and investments. Western has assured its customers that it will work
expeditiously with Reclamation to revise historical information.
Issue: Customers commented that the Western proposal to decrease
the amount of power used in the electric service rate calculation to
firm sales for LAP was inappropriate and that the power should be
reallocated, and that there were inconsistencies in the projected level
of power purchases.
Response: The resources identified in the Criteria were estimated
to be 717 MW of capacity and 2,088 GWh of energy. These resource
estimates identified as marketable energy with capacity are currently
used to calculate the LAP firm electric service rate. Because the
marketable resource estimates are greater than the amount of resource
under contract, LAP has incurred a $1.4 million annual shortfall in
revenue. To recover this amount, Western has proposed using the
resources under contract to calculate the rate rather than the
marketable resources. Western considers this reasonable and within its
rate design and power marketing authority.
The reallocation or other use of the difference between the
resources under contract and the marketable resources is an allocation
issue which has been discussed with the customers on numerous occasions
since the publication of the allocations. A summary of the most recent
Federal Register notice, which was published during the Public
Information Forum, was sent to the customers on September 17, 1993.
Western projected in the January 23, 1987, Federal Register notice
that it would be able to market 2,088 GWh of energy annually for firm
electric service. This was based on projected generation studies (based
on historical hydrology) less losses and project and special use loads;
actual historic generation was not used. This amounted to 2,335 GWh at
plant, less losses and project and special use. The difference referred
to is between 2,088 GWh, the estimated marketable energy, and the 2,040
GWh under contract which includes special use. That difference is 48
GWh. Most of this 48 GWh difference can be attributed to actual project
use amounts being higher than estimated amounts.
Western has continued to use the projected generation studies and
has published in the Federal Register a revised marketable energy level
of 2,124 GWh. That is, 2,355 GWh at plant (including Spirit Mountain),
less losses and project use. The apparent increase in the marketable
energy is 36 GWh. This is due to an additional resource (19.6 GWh from
Spirit Mountain), a change in losses (from 5 percent to 6 percent over
the system of Public Service Company of Colorado and from 7 percent to
6 percent over the LAP system), and the separation of project and
special use loads (special use is now treated as customer load).
This appears to be an 84 GWh increase in energy available for
reallocation (2,124 GWh less that amount of energy under contract, or
2,040 GWh). This was identified as available energy of 39,769 MWh in
the winter and 43,681 MWh in the summer in Western's September 17,
1993, letter.
Since the January 23, 1987, Federal Register notice, actual
operations have produced significantly less power than the projected
generation studies identified. Preliminary analysis of historic
generation reports have shown that the actual average generation less
losses and project use for the years 1960-89 has only produced an
average 2,020 GWh of marketable energy. This was derived from 2,241 GWh
at plant, less losses and project use. Therefore, LAP has an actual
generation deficit of 20 GWh, as compared to the amount of energy
currently under contract.
Since the implementation of the Criteria, Western has been able to
accommodate this deficit and the deficits caused by the recent drought
by purchasing power, bill crediting, net billing, shaping and storage,
interchange, and by drawing down the reservoirs. Also, some of
Western's firm electric service customers have not called upon their
full monthly capacity entitlements, which would cause a dramatic
increase in purchased energy to support this capacity.
Western will continue to honor its Post-1989 marketing commitment
under contract based upon the projected generation studies. The
Criteria also allows Western to revise the amounts of power committed
by contract based on the marketable resource in 1999. Western intends
to use actual average generation to identify the marketable resource
for the Post-1999 period. Western must notify customers of necessary
revisions to electric service contracts by 1996.
The actual average generation indicator, coupled with operational
flexibility and continued short-term drought-related costs, reinforces
Western's initial decision not to reallocate any projected increase in
energy identified in the projected generation studies. This action is
well within Western's discretionary authority. Western intends that
future rate design will use the resources under contract for firm
electric service rate calculations.
Issue: In a comment letter received from a customer association,
and in a package presented during the comment forum held on August 30,
1993, the customers questioned Western's criteria for participating in
rehabilitation/new construction projects. Specifically, they requested
that Western should limit its participation to those projects which can
be economically justified based on expected benefits. Also, the
customers requested that projected revenues or reduced purchased power
costs resulting from the construction be included in the PRS.
Response: Proposals for new facilities must first pass one of three
criteria before we will consider construction: increased revenues from
the new facility must exceed the annual cost, or customers must benefit
sufficiently to support the project in spite of a possible rate
increase, or the project will be funded from non-Federal sources. We
will continue our construction program as necessary to ensure we
provide reliable service.
Issue: One party commented that since Western has contractually and
operationally integrated the resources from Fry-Ark and P-SMBP-WD, we
should integrate the two projects financially as well. The same party
commented that it is unclear whether Fry-Ark properly shares in the
financial benefits it contributes to LAO operations.
Response: The two projects were created by separate congressional
legislation and therefore require separate financial accounting. The
only way Western would be able to completely integrate the two projects
would be if Congress passed new legislation mandating that the two
projects be combined.
Western has also kept the projects financially separate because of
the nature of the projects themselves. Eastern Division facilities are
governed by the flow on the main-stem of the Missouri River and receive
no benefit from the operation of Fry-Ark, and Western Division
facilities rely on Fry-Ark pumped-storage capacity to ``firm up''
regular sales. This is particularly important for the Western Division
during drought conditions because its reservoirs are small and have
minimal carryover storage. In addition, Western is a member of the
Rocky Mountain Generation Cooperative (RMGC). The Western Division uses
the pumped-storage features of Fry-Ark as a shaping and storage device
for RMGC sales on a reimbursable basis. This hydro-thermal integration
benefits all members of RMGC, and subsequently Western's customers, and
makes the most efficient use of the generating facilities.
As for the financial credits received by Fry-Ark as a part of the
LAP system, Western has gone to great lengths to ensure that Fry-Ark
receives an equitable share of LAP revenues. Revenues that are clearly
identifiable to either Fry-Ark (e.g., third-party sales of capacity
over the system of the Public Service Company of Colorado) or P-SMBP-WD
(e.g., transmission of supplemental power to customers over Western's
system in Nebraska and Wyoming) are directly credited to those
projects. Revenues not identifiable to either of the projects are
divided on the basis of the proportional revenue requirements of each
project, as specified in the Post-1989 Power Marketing Plan.
The division of general revenues is not a simple process because
the products of the Western Division and Fry-Ark are so different. To
divide general sales revenues on the basis of energy would not be fair
to Fry-Ark because it produces proportionately much less than the
Western Division. To divide revenues on the basis of capacity would not
be appropriate either because most of Fry-Ark's capacity has no energy
associated with it. Western believes that the present approach of
dividing LAP revenues between the projects is reasonable because of the
way they are operated together in the system. The operational and
contractual integration of the two projects was conducted according to
the required public process and performed in an open and cooperative
manner with Western's customers. No plans are being made to change the
apportionment of revenues between the two projects.
Issue: The customers suggested that since all the investment in P-
SMBP is integrated financially, a transmission rate based only on the
P-SMBP-WD costs is inconsistent with the allocation of investment,
related O&M expenses, and associated revenue credits between divisions.
Response: It would be inappropriate to completely integrate the
projected expenses, revenues, and commitments for the Eastern and
Western Divisions of the P-SMBP into a single transmission rate. Even
though the related revenues and expenses assigned to P-SMBP are
combined into a single P-SMBP PRS, they are two separate and very
different systems electrically, physically, and politically. The United
States and a portion of Canada are divided into separate transmission
zones to control inadvertent flow. Due to difficulties in maintaining
AC interconnections between the East and West, a series of AC-DC-AC
converter stations have been constructed to electrically separate one
system from the other. The dividing line for the Pick-Sloan Eastern and
Western Divisions coincides with this electrical division line. Each
system is also controlled separately from dispatch offices located in
Watertown, South Dakota (Eastern Division), and Loveland, Colorado
(Western Division).
Politically, the two areas are governed by two different Councils
of the North American Electric Reliability Council. The Eastern
Division is a part of the Mid-Continent Area Power Pool while the
Western Division is governed by the Western Systems Coordinating
Council.
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 the Office of Management and Budget is required.
Availability of Information
Information regarding this rate adjustment, including PRSs,
comments, letters, memorandums, and other supporting material made or
kept by Western for the purpose of developing the power rates, is
available for public review in the Loveland Area Office, Western Area
Power Administration, Office of the Assistant Area Manager for Power
Marketing, 5555 East Crossroads Boulevard, Loveland, CO 80538-8986;
Western Area Power Administration, Division of Marketing and Rates,
1627 Cole Boulevard, Golden, Colorado 80401; and Western Area Power
Administration, Office of the Assistant Administrator for Washington
Liaison, room 8G-061, Forrestal Building, 1000 Independence Avenue SW.,
Washington, DC 20585.
Submission to Federal Energy Regulatory Commission
The rates herein confirmed, approved, and placed into effect on an
interim basis, together with supporting documents, will be promptly
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 February 1, 1994, Rate Schedules L-F3, L-T3, and L-T4
for the Loveland Area Projects. These rate schedules shall remain in
effect on an interim basis, pending Federal Energy Regulatory
Commission confirmation and approval of them or substitute rates on a
final basis, through January 31, 1999.
Issued in Washington, DC, January 6, 1994.
Bill White,
Deputy Secretary.
United States Department of Energy--Western Area Power Administration
[Rate Schedule L-F4 (Supersedes Schedule L-F3)]
Loveland Area Projects Colorado, Kansas, Nebraska, Wyoming;
Schedule of Rates for Firm Power Service
Effective: First Step: Beginning on the first day of the first
full billing period on or after February 1, 1994, through September
30, 1994. Second Step: Beginning on the first day of the first full
billing period on or after October 1, 1994, through January 31,
1999.
Available: Within the marketing area served by the Loveland Area
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
First Step
Demand Charge: $2.65 per kilowatt (kW) of billing demand.
Energy Charge: 10.33 mills per kilowatthour (kWh) 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 in excess of, the delivery obligation under the power
sales contract, or (2) the contract rate of delivery.
Second Step
Demand Charge: $2.85 per kW of billing demand.
Energy Charge: 10.85 mills per kWh 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 in excess of, the delivery obligation under the power
sales contract, or (2) the contract rate of delivery.
Adjustments
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.
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.
United States Department of Energy--Western Area Power Administration
[Rate Schedule L-T3 (Supersedes Schedule L-T1)]
Loveland Area Projects Colorado, Kansas, Nebraska, Wyoming;
Schedule of Rate for Firm Transmission Service
Effective: The first day of the first full billing period
beginning on or after February 1, 1994, through January 31, 1999.
Available: Within the marketing area served by the Loveland Area
Projects (LAP).
Applicable: To firm transmission service customers where power
and energy are supplied to the LAP system at points of
interconnection with other systems and transmitted and delivered,
less losses, to points of delivery on the LAP system specified in
the service contract.
Character and Conditions of Service: Transmission service for
three-phase alternating current at 60 hertz, delivered and metered
at the voltages and points of delivery specified in the service
contract.
Rate
Transmission Service Charge: $22.52 per kilowatt (kW) per year
for each kilowatt delivered at the point of delivery, as specified
in the service contract, payable monthly at the rate of $1.88 per
kW. For those customers with existing contracts utilizing an energy
rate, the rate will be 2.6 mills per kilowatthour.
Adjustments
For Reactive Power
None. There shall be no entitlement to transfer of reactive
kilovoltamperes at delivery points, except when such transfers may
be mutually agreed upon by contractor and contracting officer or
their authorized representatives.
For Losses
Power and energy losses incurred in connection with the
transmission and delivery of power and energy under this rate
schedule shall be supplied by the customer in accordance with the
service contract.
United States Department of Energy--Western Area Power Administration
[Rate Schedule L-T4 (Supersedes Schedule L-T2)]
Loveland Area Projects Colorado, Kansas, Nebraska, Wyoming;
Schedule of Rate for Nonfirm Transmission Service
Effective: The first day of the first full billing period
beginning on or after February 1, 1994, through January 31, 1999.
Available: Within the marketing area served by the Loveland Area
Office.
Applicable: To nonfirm transmission service customers where
power and energy are supplied to the Loveland Area Projects (LAP)
system at points of interconnection with other systems and
transmitted and delivered subject to the availability of
transmission capacity, less losses, to points of delivery on the LAP
system specified in the service contract.
Character and Conditions of Service: Transmission service on an
intermittent basis for three-phase alternating current at 60 hertz,
delivered and metered at the voltages and points of delivery
specified in the service contract.
Rate
Transmission Service Charge: 2.6 mills per kilowatthour (kWh)
delivered at the point of delivery for each kWh scheduled, payable
monthly.
Adjustments
For Reactive Power
None. There shall be no entitlement to transfer of reactive
kilovoltamperes at delivery points, except when such transfers may
be mutually agreed upon by contractor and contracting officer or
their authorized representatives.
For Losses
Power and energy losses incurred in connection with the
transmission and delivery of power and energy under this rate
schedule shall be supplied by the customer in accordance with the
service contract.
[FR Doc. 94-1486 Filed 1-19-94; 4:15 pm]
BILLING CODE 6450-01-P
