[Federal Register Volume 60, Number 197 (Thursday, October 12, 1995)]
[Notices]
[Pages 53181-53184]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-25222]



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DEPARTMENT OF ENERGY
Western Area Power Administration


Record of Decision for the Energy Planning and Management Program

AGENCY: Western Area Power Administration, DOE.

ACTION: Record of decision.

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SUMMARY: The Department of Energy, Western Area Power Administration 
(Western) completed a draft and final environmental impact statement 
(EIS), DOE/EIS-0182, on its Energy Planning and Management Program 
(Program). Western is publishing this Record of Decision (ROD) to adopt 
the Program, which will require the preparation of integrated resource 
plans (IRP) by Western's long-term firm power customers, and establish 
a framework for extension of existing firm power resource commitments 
to customers.

DATES: Western will proceed to take action with the publication of this 
ROD. All parties who have previously expressed an interest in the 
Program will be notified and copies of the ROD made available to them.

FOR FURTHER INFORMATION CONTACT: Robert C. Fullerton, Western Area 
Power Administration, P.O. Box 3402, A3100, Golden, CO 80401-0098, 
(303) 275-1610.

SUPPLEMENTARY INFORMATION: Western has prepared this (ROD) pursuant to 
the National Environmental Policy Act of 1969 (NEPA), Council on 
Environmental Quality NEPA implementing regulations (40 CFR Parts 1500-
1508), and DOE NEPA implementing regulations (10 CFR Part 1021). This 
ROD is based on information contained in the ``Energy Planning and 
Management Program Environmental Impact Statement,'' DOE/EIS-0182, and 
related coordination with agencies, power customers, interested groups, 
and individuals. Western has considered all comments received on the 
proposed Program in preparing this ROD. The final Program also 
implements the provisions of section 114 of the Energy Policy Act of 
1992 (EPAct), Public Law 102-486.

Background

    Western proposed the Program in concept on April 19, 1991 (56 FR 
16093). The goal of the Program was, and is, to require planning and 
efficient energy use by Western's long-term firm power customers and to 
extend Western's firm power resource commitments as contracts expire. 
Western published its notice of intent to prepare an EIS in the Federal 
Register on May 1, 1991 (56 FR 19995).
    Combined public information/environmental scoping meetings on the 
proposed Program were held in seven states in June 1991. Based on the 
feedback received from these meetings, Western developed alternatives 
to be analyzed in the EIS. Public alternatives workshops were held in 
eight cities in Western's service area during March and April 1992.
    President Bush signed EPAct into law on October 24, 1992. Section 
114 of EPAct requires the preparation of IRPs by Western's customers, 
and amends Title II of the Hoover Power Plant Act of 1984. Western 
adjusted its proposed Program to fully incorporate the provisions of 
this law.
    The draft EIS was printed and distributed during March of 1994. 
Notices of availability for the draft EIS were published in the Federal 
Register by Western on March 31, 1994 (59 FR 15198), and by the 
Environmental Protection Agency (EPA) on April 1, 1994 (59 FR 15409). 
Eight public hearings were held throughout Western's service area 
during the 45-day public comment period. Western did not identify a 
preferred alternative in the draft EIS, but solicited input from 
interested parties and the public as to what they thought the 
appropriate alternative should be.
    Because the Program is also a rule-making action, Western conducted 
a public process under the Administrative Procedure Act (APA), 
coordinated with the ongoing NEPA process. A notice of the proposed 
Program was published in the Federal Register on August 9, 1994 (59 FR 
40543), with seven public information/comment forums held at various 
locations during September 1994.
    With input from oral and written comments from both the NEPA and 
APA processes, Western modified the EIS alternatives where appropriate, 
and revised the draft EIS. The final EIS was distributed to the public 
on June 27, 1995. The EPA notice of availability was published on July 
21, 1995 (60 FR 37640). The final EIS identified an agency preferred 
alternative, a combination of features from Alternatives 5 and 6, as 
presented in the draft EIS. The alternatives considered in the EIS are 
described in the following section.

Alternatives

    The EIS evaluated a total of 13 alternatives, including a no-action 
alternative. All but the no-action alternative comprised different 
approaches to implementing the proposed Program. The two parts of the 
proposed Program are the IRP provision and the Power Marketing 
Initiative (PMI). The IRP provision requires customers to prepare IRPs, 
and establishes administrative procedures and requirements. Small 
customers could be exempt from the IRP requirement, but would still 
have to accomplish some resource planning on a simpler scale as needed.
    Options for the PMI include PMI Extensions, PMI Limited Extensions, 
and PMI Non-extensions. These options, which are explained more fully 
in the EIS, include varying amounts of existing resources (from 90 to 
100 percent of the present commitments) that would be extended to 
Western's power customers, varying the lengths of contracts (from 10 to 
35 years), determining the existence and size of a resource pool 
ranging from 0 to 10 percent, establishing options for how pooled 
resources would be generally allocated, and setting penalties for 
noncompliance.
    The alternatives in the EIS consisted of various reasonable 
combinations of the above components. The summary of the EIS contains a 
table, Table S.3, which concisely describes the principal attributes of 
each alternative. That table is reprinted here. The no-action 
alternative assumes the continuation of Western's Guidelines and 
Acceptance Criteria for the Conservation and Renewable Energy Program. 
The alternatives are not described in further detail here, as they are 
combinations of the components discussed above, and the EIS analysis 
did not reveal any important differences in impacts among the 
alternatives, except with the no-action alternative.
    All alternatives had positive impacts when compared to no action, 
as each alternative would encourage energy efficiency on the part of 
Western's customers. The predicted effect of the Program within 
Western's service territory is reduced energy usage of approximately 2 
to 6 percent in the year 2015, depending on the alternative. Western's 
customers are forecast to use 5 to 15 percent less energy in 2015, 
depending on the alternative. Within Western's service territory, the 
savings varies from area to area, depending primarily on the amount of 
conservation activity already accomplished and the number and type of 
existing energy-efficient buildings. 

[[Page 53182]]

    The energy saved reduces the need for generation which, in turn, 
reduces pollution as compared with the no action alternative. Although 
small when compared with regional generation needs, the reduction of 
emissions in absolute terms is important. A typical 500-megawatt coal 
plant produces about 2,600 tons of sulphur oxides, 5,200 tons of oxides 
of nitrogen, 500 tons of total suspended particulates, and 3.2 million 
tons of carbon dioxide annually. The Program alternatives are estimated 
to reduce annual emissions by the equivalent of one to two such coal 
plants in 2015.
    With the exception of the no-action alternative, the effects among 
alternatives are very similar, positive, and in many cases within the 
level of uncertainty of the analyses. The summary tables of impacts 
included in the EIS (Tables S.5 and S.6) show that each alternative 
except the no-action alternative is environmentally preferable in some 
impact category. Because of the small differences in impacts, their 
positive nature, and the uncertainty inherent in the future 
projections, none of the alternatives was clearly superior to the 
others in terms of overall environmental impact. Therefore, although 
none of the action alternatives can be regarded as environmentally 
preferable overall, each of them is environmentally preferable when 
compared to the no-action alternative.

Scoping Issues Not Addressed

    A number of issues were raised during the scoping process that were 
determined to be outside the scope of the EIS. These issues included 
transmission access, incentive rates and rate design, and river and dam 
operations. Western already has an open transmission access policy. 
Rates and rate design are accomplished under a separate public rate-
setting process as set forth in 10 CFR 903, and are not a part of a 
power marketing plan. River and dam operations are not determined by 
Western, but by the operating agencies, usually the Bureau of 
Reclamation (Reclamation) or the Corps of Engineers.

Modifications to the Preferred Alternative

    Two minor modifications to the preferred alternative were found to 
be necessary to make the final EIS consistent with the final Program 
regulations, which will be published in the Federal Register shortly 
after publication of this ROD. The modifications are procedural or 
administrative in nature, and do not affect the analyses in the EIS.
    The first modification involves the timing of extension contract 
offers to customers of the Pick-Sloan Missouri Basin Program-Eastern 
Division and the Loveland Area Projects. The EIS indicates that 
extension contracts would be offered upon publication of the ROD in the 
Federal Register, subject to subsequent approval of the submitted IRP/
small customer plan. Under the final rule contracts signed pursuant to 
the PMI would not be subject to termination if an IRP/small customer 
plan is disapproved. In recognition of the fact that extension 
contracts will make the penalty provisions of section 114 of EPAct 
applicable to customers immediately, the final rule will allow 
extension contracts to be unconditionally offered for execution no 
sooner than the effective date of the final regulations.
    The second modification involves the applicability of penalty 
provisions for nonsubmittal of annual progress reports in a timely 
manner, as described in the EIS. In the final regulations, the penalty 
provision will not be applied to nonsubmittal or untimely submittal of 
annual reports. There are two reasons for this change: EPAct does not 
provide for application of a penalty in this circumstance, and a 
penalty would be harsh and out of proportion to the importance of 
annual report submittal.
    In the final regulations, two decisions will be made that are 
within ranges set forth in the preferred alternative. The term of 
contract is established at 20 years, within the range of 18-20 years 
analyzed for the preferred alternative. For the Pick-Sloan Missouri 
Basin Program-Eastern Division and the Loveland Area Projects, the 
final rule establishes an initial resource pool of 4 percent, with two 
additional increments of up to 1 percent each, 5 and 10 years into the 
extension term.

Responses to Late Comments on the Program

    Several comment letters were received postmarked after May 16, 
1994, the close of the comment period on the EIS, and too late to be 
incorporated in the final EIS. The following section summarizes those 
comments and addresses them.
    1. Comment: Program implementation in Texas should mean less need 
for energy, which would lead to less water demand for power generation 
at the Falcon and Amistad projects. Texas law permits but does not 
mandate integrated resource planning, and the Texas Public Utility 
Commission has many IRP elements in place. Comprehensive IRP rules are 
under consideration in Texas. Several utilities are experimenting with 
IRP processes. Texas requires biennial filings of long-term forecasts 
and capacity resource plans from all generating utilities, including 
municipal utilities. Several utilities in Texas have achieved 
significant demand-side management program impacts since 1981, and the 
PUC has had a biennial energy efficiency reporting rule since August of 
1984. The Texas PUC has not completed an IRP review process for any 
utility. Two footnotes in Chapter 3 of the draft EIS refer incorrectly 
to a point of contact at the Texas PUC. Table 3.9 in the draft EIS does 
not give sufficient recognition to the status of IRP in Texas. The 
draft EIS does not adequately emphasize the Texas PUC's requirement for 
demand and supply-side solicitation as part of its power plant 
licensing regulations (Texas Office of State-Federal Relations).
    Response: Since Western's resources are favorably priced in 
comparison to other sources of power, energy efficiency improvements 
resulting from IRP implementation would result in conservation of 
thermal resources or purchased electricity other than hydropower. No 
impact on hydropower generation will take place.
    The information on the status of IRP in Texas was largely derived 
from national surveys that are regarded as authoritative in the utility 
industry. Obviously, the best source of information on the status of 
Texas PUC practices and regulations is the PUC itself. Western accepts 
the information provided by this commenter as authoritative.
    2. Comment: The direct environmental impacts of thermal generation 
cannot be known until the location and projected emission levels are 
known. In the absence of this information, we can only express our 
concern about the potential impacts of locating plants in ozone 
nonattainment areas in the state of Texas (Texas Natural Resource 
Conservation Commission).
    Response: Western agrees that the location of new generation is an 
important factor that influences air quality. Western's Program will 
increase efficient energy use and, compared with no action, will reduce 
the need for new generation. Any entity proposing new thermal 
generation for construction must apply for necessary permits from 
appropriate authorities such as the State of Texas.
    3. Comment: It is more practical and environmentally sound to make 
contract extension and allocation decisions on a project-by-project 
basis, as Western has 

[[Page 53183]]
done in the past. A project-by-project approach will make it easier for 
Western to coordinate its efforts with those of the Bureau of 
Reclamation. The power contract extension alternatives proposed by 
Western may create unrealistic expectations among Western's customers, 
which may be difficult to satisfy in the event of future changes in the 
operations of Reclamation dams. Decisions should not be made now on the 
marketing of power during time periods more than ten years into the 
future. Western's draft EIS may lock in resources to an inappropriate 
degree. Western needs to analyze the environmental effects of (1) 
rewarding customers that conserve energy with a larger power 
allocation, (2) providing power to entities that intend to meet future 
power needs with fossil fuel-fired generation, and (3) providing more 
Western power for fish and wildlife purposes. The impacts of increasing 
the costs of Western's power also need to be evaluated (Bureau of 
Reclamation).
    Response: The final Program provides a general framework for 
marketing Western's long-term firm hydroelectric resources. Many 
project-specific determinations are necessary before any final 
decisions can be made on marketing power. Such important issues as the 
resource available for marketing in the future, the size of a resource 
pool, any adjustments to the size of this pool, and allocation criteria 
for new customers must be decided on a project-specific basis, with 
public input and appropriate environmental documentation. Project-
specific decisions will need to be made on whether to apply the Power 
Marketing Initiative to Western's projects in the future, such as the 
Colorado River Storage Project and the Central Valley Project. All of 
these decisions will be made in the future, and on a project-specific 
basis. Western is not making decisions today about all of the specifics 
of power marketing in the future.
    The Program will not create unrealistic expectations among 
Western's power customers. Project-specific extension percentages will 
be applied to the marketable resource determined to be available at the 
time future resource extensions begin. This approach will allow Western 
to accommodate changes in operations by the generating agencies before 
the extension term begins. The Program also allows Western to adjust 
its marketable resources on 5 years' notice after the extension term 
starts. This feature allows the flexibility to respond to changing 
operations or hydrology. Western's customers have been made aware of 
these Program features.
    Suggestions on how Western might allocate its power to new 
customers will be addressed during project-specific allocation 
processes in the future. For the two projects initially covered by the 
Power Marketing Initiative, resource pool size was determined based 
upon meeting a fair share of the needs of new customers within a 
project-specific marketing area. For other projects, the fair share 
needs of new customers will be determined at a time closer to the 
expiration date of existing contracts.
    Rates are not analyzed as part of the Program EIS, as they are 
outside the scope of the Program. Rate issues should be addressed 
within Western's long-established public ratemaking process.
    At a congressional hearing on June 16, 1994, the Commissioner of 
Reclamation expressed support for the Program proposal as documented in 
the testimony of Deputy Secretary of Energy White. At the hearing, 
Commissioner Beard stated that Deputy Secretary White's testimony 
``reflects a very thorough attempt to look at the problem and to come 
forward with * * * a very unique and innovative set of solutions.''
    Beard continued: ``I think the changes that [Deputy] Secretary 
White is recommending and that Western is going to be pursuing will 
help us * * * be able to deal with future problems * * * quicker and 
faster.'' WAPA Allocation of Hydroelectric Power: Oversight Hearing 
before the Subcommittee on Oversight and Investigations of the 
Committee on Natural Resources, House of Representatives, 103rd 
Congress, Second Session at 141-42 (June 16, 1994).

Decision

    Western has selected the preferred alternative as described in the 
final EIS, with the modifications described earlier in this document, 
as its proposed action. This alternative best meets Western's Program 
requirements and the needs of Western's customers, while being 
responsive to the comments received on the proposed Program. The 
proposed action falls between Alternatives 5 and 6, described in the 
EIS, in terms of its component provisions. The specific impacts of the 
proposed action will fall somewhere between those identified for 
Alternatives 5 and 6, which are very similar to each other. Essential 
elements of the proposed action include requiring IRPs for Western's 
long-term firm power customers, with a small customer provision for 
those customers with total energy sales or usage of 25 gigawatt-hours 
or less. The extension period for Federal power resources will be 20 
years.
    Project-specific extensions over the entire contract term will be 
not less than 94 percent of the resource determined to be available at 
the time new contracts are signed for the Pick-Sloan Missouri Basin 
Program--Eastern Division and the Loveland Area Projects; the 
percentage will be determined later for other projects. A resource pool 
of up to 6 percent will be established for these two projects, 
consisting of an initial pool of 4 percent, with additional withdrawal 
opportunities of up to 1 percent 5 and 10 years into the contract term. 
The pool may be used for allocations to new customers, customer 
development of new technologies for conservation or renewable 
resources, and contingencies. Decisions on pools for other projects 
will be made at a later date.
    Allocations may be adjusted on 5 years' notice for changes in 
operations and hydrology. This does not mean that any changes in 
operations will have to be deferred for 5 years; changes can be 
implemented immediately. Any shortfall in generation will be replaced 
with purchases or other resources until allocation adjustments are 
made. Purchased resources will be evaluated in an internal IRP process 
recently adopted through a separate public process. Project use 
withdrawals will be made in accordance with the principles set forth in 
existing marketing plans and contracts. The Program will carry the 
progressive penalty provisions prescribed in EPAct.
    The IRP provision will be effective for all of Western's customers 
following publication of the final rule under the APA process. The PMI 
will be in effect for the Pick-Sloan Missouri Basin Program--Eastern 
Division and the Loveland Area Projects initially. Its application to 
the Salt Lake City Integrated Projects marketing plan will be 
determined following completion of the separate NEPA process currently 
under way on marketing before 2004. PMI application to the Central 
Valley Project will be evaluated during the project-specific NEPA 
process for the marketing of power after the year 2004. Application of 
the PMI to projects in the Phoenix Area will be considered closer to 
the time the existing power contracts expire.
    No Mitigation Action Plan will be prepared for the Program, as the 
proposal involves no construction, and no mitigation was identified as 
necessary to implement the Program.


[[Page 53184]]

    Issued at Golden, Colorado, September 21, 1995.
J.M. Shafer,
Administrator.  .......................................................

                                                                                 Table S.3.--Summary of Energy Planning and Management Program Alternatives Including the Preferred Alternative                                                                                 
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                       No  action                                                                                                                 Program alternatives                                                                                                          
                  --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
     Program                                                                                          PMI extension                                                                       PMI limited  extension                   PMI non-extension               Preferred    
    components              1         ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                2                   3                   4                   5                   6                   7                   8                  9                  10                 11                 12                 13       
--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
EMP..............  C&E, G&AC.........  IRP...............  IRP...............  IRP...............  IRP with Small      IRP with Small      IRP with Small      IRP...............  IRP..............  IRP with Small     IRP..............  IRP with Small     IRP with Small   
                                                                                                    Customer            Customer            Customer                                                   Customer                              Customer           Customer        
                                                                                                    Provision.          Provision.          Provision.                                                 Provision.                            Provision.         Provision.      
Extension Period.  Variesa...........  15 yrsb...........  25 yrsb...........  35 yrsb...........  15 yrsb...........  25 yrsb...........  35 yrsb...........  25 yrsb...........  10 yrsc..........  10 yrsc..........  Variesa..........  Variesa..........  18-20 years.     
Percentage         Variesa...........  98%...............  95%...............  90%...............  98%...............  95%...............  90%...............  98%...............  100%e............  100%e............  Variesa..........  Variesa..........  Variesf          
 Allocation.                                                                                                                                                                                                                                                                    
Resource Pool....  Noned.............  2%................  5%................  10%...............  2%................  5%................  10%...............  2%................  Nonee............  Nonee............  Noned............  Noned............  Variesg          
Adjustment         Noned.............  Limited...........  1 adjust..........  2 adjust..........  Limited...........  1 adjust..........  2 adjust..........  5 yr notice.......  Nonee............  None.............  Noned............  Noned............  5 year notice.   
 Provisions.                                                                                                                                                                                                                                                                    
Penalty Provision  10% Withdrawal....                                                                                                                                                                                                                                           
(11) 10% to 30%                                                                                                                                                                                                                                                                 
 surcharge, see                                                                                                                                                                                                                                                                 
 Figure 2.1 and                                                                                                                                                                                                                                                                 
 Table 2.4.                                                                                                                                                                                                                                                                     
 Optional 10%                                                                                                                                                                                                                                                                   
 power reduction.                                                                                                                                                                                                                                                               
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aTo be determined by project-specific marketing plan.                                                                                                                                                                                                                           
bContract extension begins at time of current expiration. Contracts are excluded upon receipt of IRP by Western.                                                                                                                                                                
cContract extensions are executed at the time of IRP approval; extension will provide resource certainty to a customer for 10 years from the date of IRP approval. After 10 years, power marketing will be determined by project-specific marketing plans.                      
dUnless provided by project-specific marketing plan.                                                                                                                                                                                                                            
eWestern assumes that the percent allocation after the limited extension period will be determined by project-specific marketing plans. For purposes of analysis, this draft EIS assumes a 90% allocation after the expiration of the 10-year extension period.                 
fProject-specific extensions of not less than 94% for the Pick-Sloan Missouri Basin Program-Eastern Division and the Loveland Area Projects; percentage to be determined for other projects.                                                                                    
gTotal resource pool of up to 6% for the Pick-Sloan Missouri Basin Program-Eastern Division and Loveland Area Projects, which includes both an initial pool followed by additional withdrawal opportunities 5 and 10 years into the contract; other projects to be determined.  

[FR Doc. 95-25222 Filed 10-11-95; 8:45 am]
BILLING CODE 6450-01-P