ADOPTED RULES
An agency may take final action on a section 30 days after a proposal has been 
published in the Texas Register. The section becomes effective 20 days after the 
agency files the correct document with the Texas Register, unless a later date 
is specified or unless a federal statute or regulation requires implementation 
of the action on shorter notice. If an agency adopts the section without any 
changes to the proposed text, only the preamble of the notice and statement of 
legal authority will be published. If an agency adopts the section with changes 
to the proposed text, the proposal will be republished with the changes.

TITLE 1. ADMINISTRATION
PART XIII. Texas Incentive and Productivity Commission 
CHAPTER 275.Productivity Bonus Program
1 TAC sec.275.16
The Texas Incentive and Productivity Commission adopts a new section to rule 275 
concerning the Productivity Bonus Program. The section was adopted without 
changes to the proposed text as published in the April 26, 1996, issue of the 
Texas Register. This section will not be republished. 
Section 275.16 is proposed to separately describe the certification and transfer 
processes, which occur at separate times. Section 275.16 Subsections (a) and (b) 
contain modifications of provisions on savings transfers currently contained in 
Section 275.13. Subsection (c) is new language that imposes a deadline for all 
transfers to occur within 90 days of the agency's receipt of Commission approval 
to pay bonuses. 
Restructuring the section and separating the application process from the 
certification process will facilitate a greater understanding of the 
Productivity Bonus Program process.
No comments were received regarding the new proposal.
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority.
Issued in Austin, Texas, on July 9, 1996.
TRD-9609917
M. Elaine Powell
Executive Director
Texas Incentive and Productivity Commission
Effective date: July 31, 1996
Proposal publication date: April 26, 1996
For further information, please call: (512) 475-2393

TITLE 10. COMMUNITY DEVELOPMENT
PART I. Texas Department of Housing and Community Affairs 
CHAPTER 9.Texas Community Development Program
SUBCHAPTER A.Allocation of Program Funds
10 TAC sec.sec.9.1, 9.2, 9.4, 9.6, 9.9
The Texas Department of Housing and Community Affairs (TDHCA) adopts amendments 
to sec.sec.9.1, 9.2, 9.4, 9.6, and 9.9, concerning the allocation of Community 
Development Block Grant (CDBG) non-entitlement area funds under the Texas 
Community Development Program, without changes to the proposed text as published 
in the May 28, 1996, issue of the Texas Register (21 TexReg 4659). 
The amendments establish the standards and procedures by which TDHCA will 
allocate fiscal year 1996 community development, colonia, urgent need, and 
planning/capacity building funds. 
The amendments make changes to the application procedures and selection criteria 
for the existing program fund categories 
No comments were received regarding the adoption of the amendments. 
The amendments are adopted under Texas Government Code, Chapter 2306, 
sec.2306.098, which provides TDHCA with the authority to allocate Community 
Development Block Grant non-entitlement area funds to eligible counties and 
municipalities according to department rules. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority. 
Issued in Austin, Texas, on July 8, 1996.
TRD-9609798
Larry Paul Manley
Executive Director
Texas Department of Housing and Community Affairs
Effective date: July 30, 1996
Proposal publication date: May 28, 1996
For further information, please call: (512) 475-3916

TITLE 16. ECONOMIC REGULATION
PART II. Public Utility Commission of Texas
CHAPTER 23.Substantive Rules
The Public Utility Commission of Texas adopts amendments to sec.23.3, relating 
to definitions, sec.23.13, relating to statistical reports, sec.23.21, relating 
to cost of service, sec.23.31, relating to certification criteria, new 
sec.23.34, relating to integrated resource planning, new sec.23.35, relating to 
preliminary integrated resource plan, new sec.23.36, relating to solicitation of 
resources, new sec.23.37, relating to approval of resources procured through 
solicitation, and an amendment to sec.23.44, relating to new construction, with 
changes to the proposed text as published in the January 19, 1996, issue of the 
Texas Register (21 TexReg 477). 
The commission held substantive discussions on integrated resource planning 
(IRP) issues during numerous open meetings between November 1995 and June 1996. 
The commission began this rulemaking proceeding by mailing an issues paper to 
170 interested parties on November 13, 1995. Thirty parties filed comments and 
these comments were considered in the development of the rule proposal. In a 
related activity, on December 14, 1995, the commission conducted an interagency 
workshop with the Texas Railroad Commission to discuss IRP and demand-side 
management (DSM) program impacts on fuel markets. At an open meeting on January 
10, 1996, the commission voted to publish a rule for comment in the Texas 
Register. On February 20, 1996, forty interested parties filed initial comments 
on the proposal, and replies to comments were filed on March 4, 1996. The staff 
of the commission conducted a public hearing on the proposal on March 19, 1996. 
The commission held a workshop on IRP issues on April 3, 1996. Throughout this 
period, the commission and its staff have met with interested parties in an 
attempt to resolve some of the outstanding issues. Numerous parties have filed 
letters in support of or in opposition to portions of the rule proposal. 
The rule amendments and new rules are adopted pursuant to new legislation that 
directs the Public Utility Commission to adopt regulations relating to IRP no 
later than September 1, 1996, (Public Utility Regulatory Act of 1995 (PURA) 
sec.2.051). The amendments are also the product of the commission's independent 
inquiry into IRP, beginning with the consideration of various rule proposals and 
the conduct of several workshops from 1991 through 1994. Among other PURA 
provisions, the commission's IRP activity was initiated under the commission's 
general authority to regulate public utilities, its specific authority, 
beginning in 1983, to require utilities to consider a broad range of 
alternatives in resource planning decisions (formerly PURA, sec.16(b)-(g) and 
sec.54), and its obligation to prevent anti-competitive activities by public 
utilities. In adopting IRP rules, the commission has attempted to promote 
resource diversity, create a regulatory framework that allows emerging 
competitive markets to grow, and enforce the Legislature's directives regarding 
wholesale competition (PURA, sec.2.001). The commission also has considered the 
potential for anti-competitive conduct by regulated monopolies during the 
transition period to a more competitive industry under its authority pursuant to 
PURA, sec.2.216. In particular, the commission has been concerned with the 
limited retail competition that occurs among electric utilities and the 
suppliers of natural gas and propane fuels. The commission is concerned that 
monopoly electric utilities may use revenues from one sector of their operations 
to subsidize activities in partially-competitive markets. The commission is also 
concerned that electric utilities may use customer information acquired in its 
role as monopoly electric service
provider to prepare a competitive bid. Electric utilities have special 
information about customer energy usage patterns, appliances, buildings, and 
payment histories that are not generally available to their competitors in the 
energy services industry. The energy services industry is comprised of a wide 
array of businesses, including air conditioning suppliers and repair persons, 
lighting contractors, propane dealers, builders and general contractors, 
electricians, energy management specialists, insulation salespersons, and energy 
service companies, and these persons are affected to varying degrees by electric 
utility activities. 
In the 1995 revisions to PURA, the Texas Legislature adopted a significant 
revision to its statement of legislative policy regarding the electric utility 
industry (sec.2.001). This revised policy statement concluded that wholesale 
competition among utilities and certain non-utilities is in the public interest. 
To effectuate this policy, the Legislature directed the commission to adopt 
rules regarding IRP and the competitive acquisition of resources. The success of 
this competitive bidding or formal resource solicitation process, as it is 
sometimes called, relies on the implementation of several other changes in 
regulations. The introduction of new market participants, such as exempt 
wholesale generators and power marketers, became possible with 1995 legislation 
authorizing their entry into Texas wholesale power markets. Many of these 
generators and marketers are currently bidding, or are expected to bid, in many 
of the resource solicitations conducted as part of the IRP process.
In February, 1996, the commission adopted an open-access comparable transmission 
service rule which requires utilities to provide wholesale transmission service 
to other suppliers at rates, and on terms and conditions which are comparable to 
the rates, terms, and conditions under which the utility uses its own 
transmission system. The open access regime will allow generation projects in 
one part of the state to bid into the solicitations of utilities in another part 
of the state. Wholesale competition is occurring in the generation sector, but 
the Legislature's expected benefits of lower costs and higher quality service 
will occur only if the market allows participation by a maximum number of buyers 
and sellers of generation services. Without fair and equal access to wholesale 
customers the goal of wholesale competition will be frustrated. The IRP process 
enacted by the Legislature allows interested parties, customers, and new 
suppliers to examine the utility's planning goals, its stated need for 
resources, the resource mix, and the availability of resource alternatives. The 
achievement of the lowest reasonable system cost in each service area requires 
that utilities periodically conduct solicitations of demand-side resources and 
supply-side resources, and that utilities acquire resources that lower system 
cost. The resource planning process is complex, and involves utility decisions 
on behalf of individual customers. These decisions have significant impacts on 
the welfare of customers and the public at large; therefore, the Legislature 
recognized the need for regulatory oversight of a utility's resource planning 
activities. 
The following parties filed comments in this proceeding: State Representative 
John Hirschi, Brazos Electric Power Cooperative, Inc. (BEPC), Browning-Ferris 
Industries, Inc. (BFI), Center for Energy and Economic Development (CEED), 
Central and South West Corporation (CSW), City of Austin Electric Utility, City 
of Friendswood, Consumers Union Southwest Regional Office (Consumers Union), 
Cuero Hydroelectric, Inc. (Cuero Hydro), Destec Energy, Inc. (Destec), East 
Texas Electric Cooperative, Inc. (East Texas), Economic Opportunities 
Advancement Corporation of Planning Region XI and the Low-Income Intervenors 
(LLI, represented by the Texas Legal Services Center), El Paso Electric Company 
(EPE), Enron Capital & Trade Resources (Enron), Entergy/Gulf States Utilities 
Company (GSU), Environmental Defense Fund of Texas (EDF), Golden Spread Electric 
Cooperative, Inc. (Golden Spread), Good Company Associates (Good Company), Gulf 
Coast Coalition of Cities (cities served by Houston Lighting & Power Company and 
Texas-New Mexico Power Company; Gulf Cities), Gulf Coast Power Connect, Inc. 
(Power Connect), Houston Lighting & Power Company (HL & P), Lower Colorado River 
Authority (LCRA), National Association of Energy Service Companies (NAESCO), 
Nucor Steel (Nucor), Office of Public Utility Counsel (OPC), Public Citizen's 
Texas Office (Public Citizen), Mr. Sol Shapiro, South Texas Electric 
Cooperative, Inc. (STEC), Southwestern Public Service Company (SPS), Steering 
Committees for Cities Served by Central Power and Light Company and Texas 
Utilities Electric Company (Steering Cities), Texas Electric Cooperatives, Inc. 
(TEC), Texas Fireframe Company (Texas Fireframe), Texas Gas Association (TGA), 
Texas General Land Office (GLO), Texas Industrial Energy Consumers (TIEC), 
Texas-New Mexico Power Company (TNP), Texas Propane Gas Association (TPGA), 
Texas Ratepayers' Organization to Save Energy, Inc. (Texas Rose), Texas 
Renewable Energy Industry Association (TREIA), Texas State Association of 
Electrical Workers/ International Brotherhood of Electric Workers (IBEW), Texas 
Utilities Electric Company (TU Electric), and Zond Development Corporation 
(Zond). 
The commission also received letters from persons concerned with particular 
aspects of the proposed rules. One issue that drew comment is the competition 
among electric utilities and natural gas utilities and propane dealers in the 
retail energy service market. State Representative Dan Kubiak wrote and urged 
the commission to preserve competitiveness in the energy services sector, and to 
recognize the importance of small businesses that provide energy services or 
supply and repair appliances and equipment. Letters were directed to the 
commission on these issues from Green's Blue Flame Gas Co., Inc. (Houston), 
Huffhines Gas Inc. (Dallas), Hughes Propane (Pinehurst), Nelson-Putman Propane 
Gas, Inc. (Corsicana), Roadrunner Energy, Inc. (Uvalde), Rocking B Auto & Fuel 
Supply (Bushland), Sands Propane, Inc. (Mineral Wells), Star Tex Propane, Inc. 
(Waco), WelchGas (Naples), and WelchGas Cass County Butane Co., Inc. (Atlanta).
A second issue that drew comment from individuals and from representatives of 
governmental or non-profit weatherization service providers is the rule proposal 
that would allow utilities to work directly with weatherization providers to 
address tenant and low-income DSM programs. LLI and Texas Rose offered petitions 
with approximately 5,000 signatures in support of these provisions. Letters were 
directed to the commission on this matter from Cara Pearl Allen, Brazos Valley 
Community Action Agency (Bryan), Community Action Council of South Texas (Rio 
Grande City), Jim Hogg County Judge Horacio S. Ramirez, Crosby County Judge 
Jerry Robertson, Caprock Community Action Association, Inc. (Crosbyton), 
Colonias Del Valle, Inc. (Pharr), Combined Community Action, Inc. (Smithville), 
Community Services, Inc. (Corsicana), Economic Opportunities Advancement 
Corporation of Planning Region XI (Waco), Minnie Mae Fields, Duval County Judge 
Edmundo B. Garcia, Jr., Elizabeth Victoria Henson, Hill Country Community Action 
Association, Inc. (San Saba), Willie Mae Lewis, Diane Massey, Northeast Texas 
Opportunities, Inc. (Mt. Vernon), Nueces County Community Action Agency, 
Panhandle Community Services (Amarillo), People for Progress, Inc. (Sweetwater), 
Project Bravo (El Paso), South Plains Community Action Association (Levelland), 
Texas Association of Community Action Agencies, Inc., Tri-County Community 
Action, Inc. (Center), Texoma Council of Governments (Sherman), West Texas 
Opportunities, Inc. (Lamesa), and Williamson-Burnet County Opportunities, Inc. 
(Georgetown). 
A third issue that was addressed in the letters was the need for a diverse 
resource mix, and the need for increased use of renewable resources and 
conservation programs to meet Texans' energy needs. Texas Citizen Action and the 
Sustainable Energy and Economic Development Coalition (SEED Coalition) provided 
copies of 180 letters to Governor Bush and a reference to numerous signatures in 
support of renewable resources and conservation. Several other letters presented 
a different point of view. Clifford Miercourt, president of the North American 
Coal Corporation, and Glen Eckhart, president of the Sabine Mining Company, 
reminded the commission of the importance of coal and lignite to the Texas 
economy, and urged the commission to reject segmented bidding. 
In preparing a rule for publication, the commission identified fifteen issues of 
particular importance. In its subsequent meetings and workshops the commission's 
discussion focused on these major policy issues: renewable resources and other 
small-scale resources; cost recovery for renewable resource projects; the 
removal of barriers to resources caused by the current method of setting rates 
including cost recovery and incentives mechanisms for various resources; the 
public participation process and the role of customers in utility planning 
decisions where the public is affected over a long period of time; the balance 
between regulatory flexibility, wherein utilities would be given significant 
freedom to implement a planning process, and commission oversight of particular 
activities where the interests of a vertically-integrated utility might not be 
aligned with the interests of its customers or with the public interest; the 
relationship between a utility and its affiliates that might bid in a resource 
solicitation; the role of IRP in the transition to competition; various 
procedural requirements; the scope of a solicitation for demand-side resources 
and whether a utility would be given a free hand in excluding resources from 
bidding for DSM programs if the utility decided that such alternatives were 
undesirable; unbundling, including customer choice, the role of the distribution 
utility, the ability of third parties to participate freely in energy service 
markets, and how the regulatory process might change to encourage a more robust 
energy services market; the definition of lowest reasonable system cost as set 
forth in the statute and how best to implement that provision; the 
quantification of the resource selection criteria in a solicitation; risk 
analysis and mitigation; the provision of low-income and tenant DSM programs; 
and the application of a limit on the capital costs of rate-based supply-side 
resources. 
In the preamble, the commission posed the following series of questions related 
to renewable resources: Should facilities of less than ten megawatts operating 
with renewable energy technologies be exempt from the requirements of a 
certificate of convenience and necessity? Are there small-scale, but otherwise 
economical renewable resource projects that are unlikely to bid into a utility 
resource solicitation? Should utilities be required to have a standard offer for 
purchases from small-scale resource providers? Do the costs and benefits of 
small generating facilities warrant exemption from the regulatory oversight 
required for larger combustion-based generating resources? Should the commission 
allow generation facilities of less than ten megawatts operating exclusively 
with renewable resources to make retail sales without a certificate of 
convenience and necessity? What transmission and standby services would such 
entities and their customers need? What other proposals would allow all 
resources, large and small, to be included in power markets? Are the proposed 
changes sufficient to create vibrant competition that includes providers of 
renewable resources? 
State Representative Hirschi supported the ten megawatt exemption from 
certification, and stated that the consideration of renewable resources by 
utilities is not sufficient to result in increased usage of renewable resources. 
OPC commented that competitive bidding for new resources may produce an 
insufficient amount of renewable resources, and that utilities should be 
required to conduct segmented bidding for renewable resources to meet a target. 
Gulf Cities stated that some small-scale economical renewable projects will 
participate in bidding, provided that the high cost of participation in the 
bidding process is offset, to some degree, by some preferred treatment and a 
sense that the process is fundamentally fair. Gulf Cities did not support the 
exemption from certification for retail sales by facilities of less than ten 
megawatts operating exclusively with renewable resources. Texas Rose proposed an 
abbreviated certification process. 
TU Electric did not believe that a facility fueled by a renewable source should 
be exempted from certification. TU Electric believed that a standard offer is 
inappropriate, in that it forces a utility to buy resources at a set price and 
does not encourage resource providers to submit proposals with the lowest 
possible cost. In TU Electric's view, it would be more appropriate to adjust the 
solicitation criteria and scoring mechanisms. CSW stated there should be few 
restrictions and regulations on the use of distributed resources by a regulated 
utility. CSW stated that the beneficial application of distributed resources 
could be greater than ten megawatts in some cases. Regarding retail sales made 
by generation facilities of less than ten megawatts, CSW stated that such sales 
should not be allowed and that the commission does not have the authority to 
allow retail wheeling. HL & P stated that the commission need not discriminate 
in favor of small-scale or renewable resource providers because the wholesale 
market should be allowed to function, and no new stranded investments from 
costly renewable resources should be created. HL & P stated that the commission 
may encourage renewable resources in a manner consistent with the basic IRP 
policies relating to reliability and lowest reasonable system cost. HL & P 
believed that small-scale providers will not bid in a resource solicitation, but 
that there are already small niche markets for them off-grid and on the customer 
side of the meter. SPS stated that it is not necessary to allow retail wheeling 
to encourage renewable resources. SPS is not aware of any economical renewable 
resources, large or small scale, that are not already being considered under the 
existing IRP process, and stated that the only way to encourage renewable 
resources is to provide subsidies. SPS stated that it purchases energy from 
small-scale resource providers based on commission-approved tariffs. TNP stated 
that an exemption for small renewable resource providers from certification 
requirements would create more of a market for these providers, but that this 
exemption is contrary to the purpose of IRP because it would create a market for 
one class of resource providers that is not market-based. TNP stated that these 
resource providers should participate in a resource solicitation, bidding 
against other resource types, under the same selection criteria. GSU stated that 
as we move to a more competitive environment, the economic viability of options 
must be the basis for measurement of the true competitiveness of renewable 
resources; that is, there should be no standard offers. The commission should 
allow all resource acquisitions of less than ten megawatts or with terms of less 
than three years to be waived from certification requirements. To allow this 
treatment only for renewable resources would distort the market and be unfair to 
other producers. EPE stated that no biases or preferences should be afforded to 
any specific resource. 
LCRA proposed that, in regard to small amounts of generation that are needed as 
distributed generation, the exclusion from the resource solicitation be extended 
to any distributed resource that has a capacity of ten megawatts or less, 
regardless of fuel used. LCRA argued that this approach would allow utilities 
flexibility in meeting transmission system needs without incurring the 
transactional cost and time delay of the IRP solicitation process. TEC stated 
that the commission cannot allow retail sales without a certificate. TEC noted 
that a smaller electric cooperative would be subjected to severe revenue 
instability if one ten-megawatt facility were to take one-half of its customers. 
BEPC stated that exempting renewable resources from certification is a positive 
step towards making renewable resources an alternative, but such resources must, 
in general, be a least- cost alternative, and limits on the percentage amount of 
the total generating requirement should be set forth. STEC noted that the 
Legislature has mandated rules to promote renewable resources but such rules 
must be consistent with the guidelines of the IRP process; that is, renewable 
resources must provide reliable energy service at the lowest reasonable cost. 
STEC recommended that utilities provide a "green" rate if customers desire such 
a rate. STEC questioned the commission's authority to exempt facilities from a 
certificate. East Texas supported the exemption of small renewable resources 
from the certification requirements, but noted that utilities should not be 
required to buy renewable resources if they are more expensive than nonrenewable 
resources. LLI supported the development of mechanisms to encourage an increase 
in the use of renewable resources. Consumers Union stated that the use of 
renewable resources to make retail sales should not justify cost-shifting to 
captive customers. Consumers Union recommended that the commission defer the 
question of retail sales from small renewable projects to its overall review of 
competition in the electric industry. Consumers Union recommended a segmented 
bidding procedure. EDF supported provisions exempting renewable resources of ten 
megawatts or less from the certification requirements. EDF suggested that the 
all- source solicitation process would be more meaningful if a utility 
delineated its total resource need through blocks of resources by type. EDF 
suggested that very small renewable projects be billed using the concept of net 
billing. Texas Rose stated that programs incorporating photovoltaic technologies 
should be used instead of green-pricing because they are more fair and cost-
effective. TIEC stated that until there is customer choice, no utility-owned 
resource should be excluded from the resource planning and certification. Enron 
recommended that small-scale distributed resources be exempted from the IRP 
process, particularly if such resources are installed and operated by non- 
affiliated parties, and, in addition, Enron supported retail sales by these 
suppliers and an increase of the size limit to 80 megawatts to make the 
definition consistent with the federal definition of small power producer. 
Further, renewable resources should have access to all transmission and 
ancillary services that are available to wholesale providers, and access to the 
distribution system. Finally, Enron supported the inclusion of fuel cells in the 
definition of renewable energy technologies. NAESCO cited problems with the 
resource solicitation process in New York where regulators were heavily involved 
and utilities did not award contracts to any bidders. New Jersey, in contrast, 
has had a successful standard offer program for energy efficiency, and NAESCO 
described the pre- and post- implementation audits that are related to the 
verification of savings for DSM in New Jersey. Cuero Hydro stated that small-
scale hydroelectric facilities can produce low-cost power but cannot afford to 
bid in a utility resource solicitation because the cost of preparing a proposal 
can run up to hundreds of thousands of dollars. Cuero Hydro stated that 
regulations should allow retail sales by renewable resources with a provision 
for nonrenewable standby power sources. Cuero Hydro supported a standard offer. 
Mr. Shapiro stated that the proposed actions alone are not sufficient to create 
the vibrant competition sought because the commission needs to set forth goals 
for renewable resources in its statewide IRP, with the objective of gaining 
renewable resource experience in Texas. Mr. Shapiro cited the possibility of the 
next energy crisis, and noted that renewable resources are alternatives to the 
importation of coal and/or nuclear energy to Texas. Mr. Shapiro suggested that a 
standard offer should apply to distribution utility purchases of up to three 
percent of current purchases. Texas Fireframe stated that the fireplace has been 
overlooked as a renewable resource that can reduce electric utility winter 
peaking problems. Texas Fireframe stated that criticisms of the fireplace as an 
energy waster are misplaced, and that a properly-constructed fire can provide 
the same overall efficiency (about 30 %) as the production and delivery of 
electricity. Texas Fireframe advocated the distribution, by electric utilities, 
of the most up-to-date fireplace information to consumers. Power Connect 
asserted that the exemption from certificate requirements of retail sales from 
renewable facilities should be both continued and expanded to encompass the 
economies of scale of particular renewable technologies. TREIA suggested 
specific revisions to promote renewable resources. Zond suggested additional 
returns to the shareholders of utilities that invest in renewable resources. 
Zond stated that renewable resources of ten megawatts should be exempt from 
certification requirements and that a standard offer approach is appropriate. 
GLO stated that renewable resource land leases will supplement revenues from oil 
and gas leases. GLO supported the proposed exemptions from certification 
requirements. Nucor Steel stated that renewable resources should be treated on 
an equal basis with other resources. 
In addressing whether renewable energy facilities of less than ten megawatts 
should be exempted from certification requirements, the commission considered 
the preferences of the renewable energy providers as well as the concerns of 
various parties relating to the potential for abuses. The commission takes note 
of its definition of generating unit in sec.23.31 that exempts from 
certification experimental technologies of less than ten megawatts of all types. 
The commission also notes that distributed renewable resources may be added 
outside the solicitation process by utilities. On the balance, the commission 
considers it reasonable to otherwise treat renewable resources in the same 
manner as other technologies, and thus the proposal to further the exemption is 
not adopted. 
The commission considered the transaction costs of small-scale renewable 
resource providers who are unlikely to bid into a utility resource solicitation. 
High transactions costs are a problem for all small-scale resource providers, 
not just renewable resource providers. One means of addressing small scale 
resources is to move toward a separation of the distribution operations of 
electric utilities and toward offering customers a wider choice of tariff 
options. In this manner, customers will be able to work directly with the 
providers of small-scale resources, and these customers will be able to obtain 
standby or interruptible service, for example, to make a project economical. The 
commission also considered restrictions on the bidding fees that may be charged 
in a resource solicitation, but this may best be considered on a case-by-case 
basis. In a related matter, the commission considered whether it should require 
utilities to put in place a standard offer for purchases from small-scale 
resource providers. Several parties commented that a standard offer approach for 
small-scale resources, including renewable resources and DSM, would address this 
problem. While there may be some merit to this approach in some circumstances, 
the commission noted the problems that some other states have had in 
implementing a standard offer approach, and the commission is trying to move 
away from approaches that require administrative determinations of avoided 
costs. The resource solicitation process reveals the market-based marginal costs 
of electricity, and the overlay of another process on this approach may 
complicate matters. The commission is also concerned that a standard offer 
approach which includes a standard price may run counter to the statutory 
framework of achieving the lowest reasonable system cost through a competitive 
solicitation process. Rather than require utilities to make a standard offer, 
the commission will consider alternatives to the solicitation process on their 
merits on a case-by-case basis. 
The commission addressed whether the costs and benefits of small generating 
facilities warrant exemption from the regulatory oversight required for larger 
combustion- based generating resources. Specifically, the commission assessed 
whether generation facilities of less than ten megawatts operating exclusively 
with renewable resources should be allowed to make retail sales without a 
certificate of convenience and necessity, and if so, the transmission and 
standby services that such entities and their customers would need. Section 
23.31(c)(1)(E) of the rules, relating to certificates of convenience and 
necessity, allow certain exemptions for retail sales by renewable resource 
providers of less than ten megawatts of capacity. This exemption is not much 
used, both because of the difficulty in finding a perfect match between customer 
needs and a renewable resource site, or because of other regulatory barriers. 
For example, the commission does not have regulations relating to the 
transmission of power from a non-utility generating unit to an end-user 
customer. If the barriers to entry are identified as the problem, the next step 
is to identify the barriers that could be reduced or dropped. The issue before 
the commission relates to whether allowing access to retail customers would 
appropriately eliminate the utility as a middleman, thus opening new business 
opportunities for enterprising renewable resource providers. The commission 
agrees that direct access for renewable resource providers would stimulate the 
renewable resources market and might lower transactions costs for such 
providers. However, unlimited retail access for small renewable resource 
providers represents a significant change in the regulatory paradigm. As such, 
the commission believes it is more appropriate to examine the merits of direct 
access for all generation companies and resource options comprehensively, rather 
than focusing on direct access for a particular technology. The commission 
directs the staff to address this issue in the context of the report on the 
scope of competition in the electric industry, and Project Number 15000, 
Investigation into Electric Industry Restructuring in Texas. 
The commission also asked what other proposals would allow resources of all 
types and sizes to be included in power markets, and what other changes would 
create vibrant competition that includes renewable resources. The commission has 
considered a variety of issues and proposals, not merely in this proceeding, but 
in Project Number 14045, the transmission services rulemaking proceeding, and in 
its general inquiry into the scope of competition in the electric industry. The 
commission will continue to address these matters in its rulemaking activities, 
and in the preparation of a report on the scope of competition to the 
Legislature. 
In the preamble, the commission posed the following question: Should the 
commission permit a utility to recover renewable resource costs through a fuel 
factor, or should the commission develop a separate factor? TU Electric asserted 
that the purchased power generated by a renewable resource should be treated in 
the same manner as capacity costs of all other purchased power, and noted that 
PURA, sec.2.051(r)(2) envisioned a monthly power cost recovery factor. CSW 
suggested that the costs of renewable resources up to current market costs 
should be recovered concurrently through the fuel factor. GSU stated the cost 
recovery of incremental resources can be accomplished through a fuel factor or 
through new and innovative cost recovery mechanisms. HL & P and EPE stated that 
preferential cost treatment is bad, and would be an artificial stimulation of 
the market. OPC opposed special cost recovery treatment for non-fueled resource 
costs. Similarly, Gulf Cities stated that cost related to renewable resources, 
both capital and operating, should not be considered as a component of a fuel 
recovery factor. Gulf Cities supported a separate factor in order to maintain 
the integrity of the record to provide clear identification of such costs during 
the reconciliation process. Steering Cities stated that it endorses the use of 
renewable resources but opposed piecemeal ratemaking. Automatic recognition of 
the costs of renewable resources must be offset by recognition of the cost 
reductions since the last rate case. Steering Cities pointed to the past several 
decades of regulation which reveals considerable abuse of fuel factors as 
utilities attempt to transform an opportunity into a guarantee by including base 
rate costs in their fuel expenses. Steering Cities noted that it is ironic that 
while some speak of eliminating the fuel factor as an anachronism, the 
commission is considering a rule that would manipulate the fuel factor to 
provide incentives for utilities to correct for regulatory disincentives. CEED 
opposed accelerated cost recovery for utility investment in renewable resources. 
TIEC stated that energy and capacity costs of a renewable energy should be 
recovered through base rates. Nucor Steel stated that renewable resource costs 
should be addressed in the context of a rate proceeding. If a special factor is 
permitted, Nucor Steel stated that the non-fuel costs should be classified and 
collected on the basis of demand through a mechanism like the purchased power 
cost recovery factor rather than the fuel factor. Power Connect submitted that 
cost recovery should not provide an opportunity for utilities to avoid periodic 
review of their overall cost of service and rate design. Public Citizen 
supported the commission's intent to allow the early recovery of renewable 
resources, but opposed allowing the utility to recover these resources through 
the fuel factor. Consumers Union expressed the view that the commission cannot 
legally, and should not, pass the cost of renewable resources on to ratepayers 
outside of a rate case; investment in renewable resources is a capital 
investment, which is not properly included in a fuel factor. EDF and Texas Rose 
stated that the proposed rule lacks specificity. TREIA stated that the 
commission should develop a separate factor, a "best fuel factor," which 
considers non-depletion, limited CO2 emissions, reduced particulates, 
reliability, and risk management. Zond and GLO stated that a utility should be 
able to recover these costs through a fuel factor. 
The commission rejects the proposed language related to fuel factor recovery for 
renewable resource projects because it is unduly complicated, presumes future 
rate base treatment, and deals with the issue of resource acquisition incentives 
in a piecemeal manner. The proposal would have permitted a utility to recover 
its average fuel cost for the energy generated by a renewable facility until the 
facility was given rate base treatment. Different regulatory mechanisms result 
in different allocations of cost, and the commission notes that while it is 
important to minimize the delay in recognizing the resource costs in rates, it 
is equally important that consumers are not charged more than their cost of 
service for any activity, including renewable resource projects. The commission 
prefers to examine cost recovery in a more comprehensive manner as part of 
Project Number 15000, Investigation into Electric Industry Restructuring in 
Texas. 
In the preamble, the commission posed the following questions: How might timely 
cost-recovery mechanisms facilitate the procurement of new, low-cost, 
competitive resources? Should the matter of timely cost recovery be taken up in 
the context of broader issues of regulatory reform, such as within an 
investigation of performance-based regulation? OPC and Gulf Cities suggested 
that the commission take up the entire discussion of incentives in a separate 
docket where the combined effect of various proposals can be analyzed. Gulf 
Cities expressed the view that the matter of timely cost recovery should be 
linked to performance standards and considered, at least as to detail, outside 
the IRP process. LLI believes that the commission should propose a detailed cost 
recovery rule for comment before any decisions are made. Nucor Steel supported a 
ruling by the commission that no current cost recovery or incentives are 
allowed. Steering Cities believed that piecemeal ratemaking is inconsistent with 
both traditional public interest regulation and the views of advocates of 
competitive markets who argue that competition will bring efficiency and lower 
prices. TIEC stated that the provision, as written, would increase rates, is not 
consistent with a move to competition, creates unfair subsidies between the 
participants and non-participants of the DSM programs, and does not assure that 
strict scrutiny of the costs will occur. EDF and Texas Rose supported a more 
detailed rulemaking on cost recovery. TREIA stated that power purchase 
agreements should be negotiated with little or no inflation index, so that fuel 
price increases are not passed to consumers. Enron supported performance-based 
regulation but does not believe that timely recovery of costs need wait until 
performance-based regulation is developed. TU Electric pointed out that there is 
no need to rehash the performance-based regulation topic as part of this IRP 
rulemaking, since it was fully debated at the Legislature and rejected. CSW 
believed that the evaluation and procurement of resources through the 
solicitation process should focus on efficiency, and should not be biased by 
variations in the timeliness of cost recovery methods applied to different 
resource options. CSW proposed that concurrent cost adjustments can be achieved 
either by including the costs of new resources as costs eligible for recovery 
through a utility's purchased power or fuel cost recovery factors, or by 
implementing "green tariffs" or other special pricing mechanisms designed as 
options offered to meet specific customer needs. HL & P preferred that timely 
cost recovery be allowed equally for all resources to avoid skewing markets. HL 
& P also stated that comprehensive regulatory reform is preferable to piecemeal 
recovery mechanisms. SPS submitted that cost recovery is a basic element of 
successful markets. These cost recovery mechanisms will remove a major 
disincentive to procurement of any resource. SPS proposed alternative rate-
making procedures, as a way of encouraging the transition to competitive 
markets. GSU stated that the issue of timely cost recovery should be addressed 
concurrently with other issues in this rulemaking. Utilities should be afforded 
flexibility to seek cost recovery through conventional methods or through new 
and innovative approaches or through performance based ratemaking. EPE stated 
that if utilities are required to acquire resources through IRP, they should be 
able to recover costs in a timely fashion due to the risks involved with full 
recovery of costs. BEPC stated that the procedures should allow utilities to 
pass the costs associated with new contract for resources through the purchased 
power cost recovery factor. STEC stated that the new cost recovery mechanism 
will provide an incentive for utilities to rely on third-party resources, and 
STEC would not wait until a general review of rate-setting to use the new 
current cost recovery mechanisms. 
In addressing how timely cost-recovery mechanisms could facilitate the 
procurement of new, low-cost, competitive resources, the commission agrees with 
the parties who state that the matter of timely cost recovery should be taken up 
in the context of broader issues of regulatory reform, such as within an 
investigation of performance- based regulation. The commission recognizes that 
contracts for resources resulting from a solicitation may result in a more 
appropriate allocation of risks among customers, utilities, and resource 
providers. Because of the complexity of the issues, the commission prefers that 
the matter of timely cost recovery and other regulatory incentives be taken up 
in the context of broader issues of regulatory reform. The commission directs 
the staff involved with Project Number 15000 to consider revisions to the fuel 
factor rule and to consider performance-based regulation and its variants. A 
future rulemaking may set forth the details of the process; in the meantime, the 
commission will determine whether it is appropriate to allow current cost 
recovery and other regulatory incentives on a case-by-case basis. 
In the preamble, the commission posed the following questions: Should the right 
to participate in the working group be limited to utility customers? Should non- 
customers of the utility be permitted to participate in some other manner? How 
much flexibility should a utility be afforded in obtaining public input? How is 
a formal public participation process compatible with the need for flexibility 
in a competitive market? State Representative Hirschi stated that representation 
of all customer groups is important, and recommended that utilities not be 
allowed to limit participation to the actual customers of the utility. OPC 
voiced concerns regarding the requirements of the currently proposed rule, 
including improper delegation of commission authority to the utilities for 
determining the manner in which the public has the right to participate, and to 
the tacit approval of excluding non-customers in the public participation 
process. Gulf Cities supported the proposal with minor changes. Steering Cities 
stated that customers should be able to designate non-utility customers to 
participate on behalf of customers. 
TU Electric stated that public participation should be limited to the customers 
of the utility, and non-customers may be allowed to make presentations. TU 
Electric stated that the commission should not mandate the scope or method. CSW 
stated that the right to participate in a working group should be limited to 
utility customers because of concerns over the competitive position of the 
utility. However, CSW stated that the requirement in the rule that the utility 
open a docket 120 days before filing its preliminary IRP for the exchange of 
information with interested parties complicates the public participation 
process. HL & P saw no reason why working groups of customers should be required 
of utilities; the public participation process should be the least intrusive to 
give utilities flexibility. HL & P stated that customer research is conducted 
and that intervention is afforded the public in commission hearings. SPS 
recommended limiting the membership and activity of the working group. Utility 
management has the ultimate responsibility for resource planning, thus utilities 
should be afforded considerable flexibility in obtaining public input. GSU 
stated that customer input and satisfaction is crucial now, especially as 
competition approaches, and that customer participation should not extend into 
the areas of resource selection and operational decisions of a utility. GSU 
stated that utilities should be afforded the flexibility to design and implement 
their own process. TNP stated that utilities should be afforded flexibility in 
defining the process. TNP sees public participation in marketing terms: each 
utility should define the type and level of public participation to best fit its 
market position and strategic goals. EPE stated that participation in a 
utility's public group should be limited to customers because non- customers may 
participate at the commission. EPE stated that the public participation process 
should not be a prescribed formal exercise. BEPC stated that the customers of 
the member-distribution cooperatives effectively participate in resource 
planning because of the democratically-elected board. STEC supported the use of 
the public in planning, but would limit any working group to customers, and 
stated that the rule should set forth the purpose and objective of public 
participation. East Texas stated that the rule should set a threshold of 
acceptability without prescription. 
Good Company stated that the right to participate in a working group should not 
be limited to customers because utilities may bias the information. Competitors 
and interest groups should be allowed to participate in all activities except 
voting. Cuero Hydro stated that the right to participate in the working group 
should not be limited to customers of a utility because customers need unbiased 
information, and competitors and interest groups should be afforded an 
opportunity to help educate customers. Mr. Shapiro stated that utilities should 
be allowed to establish their own processes because utilities that do public 
participation well will reduce controversy when the plan is filed. Public 
Citizen stated that the commission should promulgate more detailed rules, and 
that the public, not just customers, should be involved because many of the 
decisions made by the utility affect those who live downwind or downstream. LLI 
suggested that the final IRP rule set out guidelines for public participation, 
and emphasized the critical nature of the process, particularly to involve the 
public at the earliest stage to reduce the need for litigation. Consumers Union 
believed that PURA gives flexibility with regard to standards for public 
participation. The involvement of the public is essential to a fair and open 
process, and utility management has an inherent conflict of interest in choosing 
public participants who may challenge a utility's planning assumptions, resource 
alternatives, and recommendations. Thus, the commission should set clear 
standards that minimize utility control of the process, and in particular, 
public participation should not be limited to customers of the utility.
TPGA stated that non-customers should have the right to participate in the 
provision of information to the working group, and the commission should not 
delegate any of its authority or responsibility to protect the public interest 
to a utility-guided process. TREIA stated that representation of each utility 
system should be present in each public group as transmission costs are shared 
by all systems. GLO supported working groups that include all stakeholders, with 
meetings scheduled to allow for greatest level of participation. Texas Rose 
stated that all members of the public should be able to participate in the 
working groups, and that detailed and thorough notice requirements must be 
stated. Standards should also be set for the number, timing, and locations of 
meetings. EDF stated that the commission should broadly require participation by 
customers, and other affected individual members of the public and their 
representatives. TIEC stated that the utility should communicate with the 
customers but ultimately the utility should bear the responsibility for 
planning, thus the commission should be cautious in relying heavily on the 
results of a customer group. TGA stated that certain non- customer groups, such 
as natural gas utilities, can provide valuable input, particularly as to the 
types of data which must be collected or estimated to ensure that the DSM 
evaluation process is appropriate to eliminate fuel-switching programs. Nucor 
Steel suggested that the commission should not permit the utility to treat the 
public input group as a jury; the utility should use the input internally and 
not as external justification for actions; an unbiased party such as the 
commission must conduct the process; and the utility should permit any 
interested member of the public to participate. 
The commission believes that public participation is an essential part of the 
IRP process. The rule sets forth standards for utilities with regard to public 
participation; however, the specific design and conduct of the public input 
process are matters that are left to utilities. The commission agrees with 
utilities that state that limiting public participation to the customers of the 
utility is appropriate. However, the commission will require utilities to 
educate customers, allowing a variety of viewpoints, including those of 
competitors and other non-customers, to be presented to customers as part of the 
public participation process. After providing the required information and 
educating customers, utilities must gather information regarding the values and 
preferences of customers relating to resource planning matters. The rule states 
that the customers involved in the public input process will not become a quasi-
judicial body. Although such customers will be provided technical information as 
required and appropriate, they will not be expected to make determinations on 
technical matters. The rule sets forth the information and issues that the 
public must consider at a minimum. Utilities must ask customers about their 
values and preferences with regard to the selection criteria to be used in the 
resource solicitation; must ask customers how to apply statewide goals to the 
utility's service area; and determine the customers' values and preferences with 
regard to an ongoing annual solicitation for demand-side resources and targeted 
bidding for specific types of resources. 
In the future, consumers may have sovereignty, and each customer may be able to 
choose an energy supplier. This sovereignty will allow each customer to design 
his or her own customized resource plan. In such a system, resource planning as 
it is currently conducted may be unnecessary. However, the commission believes 
that public input is important today because that vision of retail access is not 
here today. The commission takes note of the view that competitive pressures are 
forcing electric utilities to take the views of customers into account to a 
greater extent than in the past. While anecdotal evidence supports this notion, 
it does not reduce the need for regulators to ensure that the public has input 
into resource planning matters. If the commission does not set standards for 
public participation, the commission might be left with difficult or impossible 
choices during the approval process of a preliminary of final plan, especially 
where a utility failed to involve the public and where such involvement might 
have improved resource planning. Finally, the commission believes that the 
public participation requirement is compatible with the need for utility 
flexibility in a competitive market because the utility can satisfy the 
standards set forth in the rule in a variety of ways. Resource planning 
decisions affect the public over the long term, and utilities will ultimately 
benefit from working closely with customers if they are not already doing so. 
In the preamble, the commission posed the following questions: Should utilities 
be allowed to waive certain rights, including the right to review bids from its 
affiliate, in exchange for more regulatory flexibility? Do such waivers better 
align the interests of the utility and its customers? Are there other ways that 
utilities should be afforded flexibility? What else can the commission do to 
reduce the time needed to issue the interim order and final order on the 
utility's integrated resource plan? Some third- party resource providers and 
most regulated utilities believed that flexibility is the key to their success. 
In their view, a flexible process will allow utilities to contract for resources 
outside the formal solicitation process and thereby allow exempt wholesale 
generators and power marketers to enter into the system without costly formal 
regulated procedures. Some utilities stated that the Legislature has already 
indicated that affiliates can bid, and that there is no need for further 
regulations on that issue. Others contended that uniform and disciplined 
regulations will act as a safeguard against potential abuses. These parties 
state that the abuses of the past will continue if utilities are given the 
freedom to game the system. Small providers voiced concern over the ability of 
utilities to manipulate the forecast and the resource need, and to engage in 
abusive self-dealing behavior in the solicitation of resources. These parties 
stated that even if a utility affiliate will not bid, there are a significant 
number of issues to be addressed in a preliminary plan, and that these issues 
cannot be addressed in an expedited manner as proposed in the rule. 
The commission rejects the published proposal as being too inflexible. The 
commission prefers a quick review of the preliminary plan whenever the 
circumstances warrant it. Delays impede competition, and a successful IRP 
process is one that will enhance the ability of new entrants, such as exempt 
wholesale generators and power marketers, to become viable competitors in Texas 
power markets. One circumstance that could shorten the regulatory review would 
be the absence of a utility affiliate bid, but the commission sees no need to 
set forth by rule the particular circumstances that will shorten the time for 
review. Conversely, the consideration of an affiliate contract may necessitate a 
longer review period simply because the commission is required by the statute to 
make additional findings in such a circumstance. However, there is no need to 
assume that at the outset. The commission will shorten the time to issue orders 
on preliminary plans and final plans (from 180 days each) on a case-by-case 
basis. A decision by a utility not to consider the bid of its affiliate is one 
factual matter that may shorten the review process. The statute requires that in 
approving a contract between a utility and its affiliate, the commission must 
find that the utility treated and considered its affiliate's bid in the same 
manner it treated other bids. In the preamble, the commission requested comments 
on standards governing the relationship between a utility and its affiliate in 
the context of a resource solicitation. The commission asked about a specific 
aspect of the proposal: Is it appropriate to restrict a utility affiliate from 
the use of the name or trademark of its utility? OPC supported the precautions 
in the proposed rule, but suggested two modifications: when the bid of an 
affiliate will be considered, a utility should be required to use an independent 
third-party evaluator, and the utility should charge an affiliate to use its 
name or trademark or the market value of the trademark's use should be imputed 
as revenues to the utility. Gulf Cities supported a bright line between the 
operations of a utility and its affiliates, and offered to modify them to make 
them clearer or stronger. TU Electric agreed that affiliates should not be given 
preferential treatment, and stated that there is simply no need for all of the 
additional requirements set forth in sec.23.36(g). CSW stated that the 
restrictions of PURA, the Public Utility Holding Company Act and the Energy 
Policy Act of 1992 already provide numerous protections against preferential 
treatment of a utility or its affiliate's bids; therefore, the restrictions on 
the use of names or trademarks should be removed from the proposed rule. HL & P 
stated that the proposal places the utility affiliate at a competitive 
disadvantage and stated that PURA already allows regulatory scrutiny of the 
affiliate transactions through the ratemaking process. HL & P disagreed with the 
need for separate board members, disagreed with the prohibition of joint 
training, marketing, and promotion, and disagreed with the restriction on the 
use of the name or trademark of the utility. GSU stated that any restrictions on 
affiliate transactions that are required by the IRP rule should clearly apply to 
that IRP process and should not be construed to apply to other activities 
outside the scope of the company's IRP process. SPS agreed that there may be 
some cases where the utility may have an advantage from name recognition; 
however, those cases should be handled on an individual basis. EPE stated that 
it is inappropriate to place any restriction on the use of a trademark of a 
corporate parent and/or affiliate. BEPC stated that PURA provides sufficient 
safeguards and there is no need to address the issue in this rulemaking because 
it will only serve to impede competition. STEC questioned whether the commission 
has the authority to dictate prohibition on the sharing of officers and 
directors, or on the use of the trademark of the utility. 
Enron stated that market power is a fundamental concern that regulation is 
intended to address. Enron supported the standards set forth in the rule, and is 
not opposed to additional means to prevent competitive abuses. NAESCO stated 
that the utility must not share information regarding energy services, customer 
loads, etc. with its affiliate unless other service providers have access to the 
same information. NAESCO stated that changing the context of resource 
acquisition from bidding programs to a standard offer will eliminate many of the 
problems associated with affiliate bidding. Power Connect asserted that the 
commission should reject all affiliate transactions that are not absolutely 
clean. Destec supported third-party evaluation of proposals if an affiliate 
bids. Public Citizen suggested that in order to eliminate abuse of the process 
by affiliates, the commission should require full divestiture of the utility and 
its affiliates. At a minimum, the commission should prohibit the use of the 
utility's name in the process. The proposed rules should be adopted, but do not 
go far enough to prevent abuses. Golden Spread stated that broad-based limits on 
utility-affiliate arrangements does not take into account the unique structure 
of cooperatives, which has an appropriate alignment of consumer and utility 
interests: the consumer owns the cooperative, and receives recognition of 
profits in the form of patronage capital. Golden Spread urged the commission to 
reconsider the application of utility-affiliate restrictions on cooperatives. 
Consumers Union endorsed the proposal, and urged restrictions on the use of a 
utility's name or trademark. The provisions relating to the independent 
evaluator, sec.23.36(h) should be strengthened to ensure the evaluator remains 
independent. TIEC stated that the proposed affiliate-utility restrictions should 
be minimum standards and thus should not be diluted. 
The commission adopts the proposed standards governing the relationship between 
a utility and its affiliate with minor wording revisions. The commission finds 
that the implementation of these affiliate standards is necessary to insure that 
the commission can appropriately make the affiliate transaction findings 
required by PURA, sec.2.051(r)(1)(C) and (D) in the context of individual 
utility IRP proceedings. Without affiliate standards in its regulations the 
commission would face the enormous task of determining whether the public 
interest is served by a contract between a utility and its affiliate on an ad 
hoc basis. The commission finds that absent such standards a utility affiliate 
would have advantages that are not available to its competitors. Each of the 
proposed standards is intended to help set a fair and level playing field among 
the utility affiliate and its competitors. Without standards self-dealing abuses 
may arise, and after- the-fact admonitions or a rejection of a contract with an 
affiliate are not particularly constructive. Policy decisions ought to occur up 
front in order to reduce litigation, and in this instance the appropriate policy 
decision is the establishment of a standard governing the behavior of a utility 
and its affiliate. Affiliate bidding will increase (by one or two) the number of 
bidders in a solicitation, thereby increasing the scope of competitive markets; 
therefore, the participation of utility affiliates in resource solicitations 
should be encouraged. However, the participation of affiliates has significant 
potential to raise the cost of resources in Texans if third-party bidders lose 
confidence in the process due to market abuses. The adoption of these affiliate 
standards, as well as the adoption of a requirement that utilities use an 
independent bid evaluator when their affiliates bid into their own IRP 
solicitations, will mitigate the potential for such abuses. 
The commission notes that the affiliate standards adopted by the commission are 
not without parallel in the utility industry. In enacting the Federal 
Telecommunications Act of 1996, the US Congress implemented affiliate standards 
for telecommunications companies which are very similar to the standards adopted 
in this rule. The telecommunications industry has faced affiliate transaction 
issues for quite some time, and the standards adopted by Congress were designed 
to mitigate the potential for anti- competitive behavior in that industry. The 
commission believes that similar standards can accomplish the same purpose in 
the Texas electric industry. 
Although the commission has not significantly modified the affiliate transaction 
standards it proposed in the published rule amendments, it has broadened their 
applicability. To promote competitive parity among resource providers and to 
mitigate the potential for market abuses, the commission will also apply 
appropriate provisions of the affiliate standards in the rule to a utility's 
functionally unbundled organizational units which are involved in the 
competitive resource acquisition process. Specifically, these units are a 
utility's wholesale purchase power and sales unit, created under sec.23.67 and 
sec.23.70 of the commission's regulations, and its retail energy services unit. 
These units will be involved in the competitive resource acquisition process as 
the sellers and/or buyers of third-party supply-side resources for retail 
customers and as the suppliers of retail energy services, respectively. As such, 
the concerns over potential anti-competitive conduct which apply to utility 
affiliates apply equally to these functions within the integrated utility. 
The affiliate standards adopted in this rule contain guidelines governing the 
exchange of competitive information among a utility and its affiliates. Although 
they are more general in nature, these guidelines serve the same basic purpose 
as the code of conduct governing intra-utility exchanges of competitive 
information contained in sec.23.67 and sec.23.70. The need for standards 
governing intra-utility exchanges of competitive information are equally 
applicable in the context of a utility's resource acquisition process. A fully-
developed set of rules which address the separation of distribution functions 
will elaborate on these standards for the exchange of information between the 
separate organizational units of a utility, as well as other appropriate 
distribution functional unbundling requirements. 
One standard upon which the commission deliberated related to the use, by the 
affiliate, of the name or trademark of an electric utility. The guidelines 
governing the use of trademarks by affiliates contained in the Federal 
Telecommunications Act of 1996 set forth such a restriction. The commission 
concludes that an affiliate of a utility may use the utility's trademark or 
name. The commission further concludes that the affiliate transaction guidelines 
set forth here have broad applicability for both telecommunications and electric 
companies within its jurisdiction, and thus the commission directs the staff to 
initiate a broad rulemaking on affiliate transactions to further develop these 
guidelines. The opening subsection of the proposed rule, sec.23.34(a), states 
the purpose of IRP. In the preamble, the commission requested comment on that 
statement, and on the relationship of the IRP process to the other changs taking 
place in the electric industry. The rule as published stated that: "nothing in 
the integrated resource planning process shall inhibit the development of 
competitive markets for electric power or for energy services," and comments 
were invited on the role of IRP in a more competitive environment. State 
Representative Hirschi and Gulf Cities questioned the use the word "nothing" in 
the proposed purpose statement, and stated that full competition would appear to 
undermine the whole goal and purpose of the proposed IRP rule. Steering Cities 
noted that several portions of the rule are inconsistent with, and will likely 
inhibit, development of competitive markets, including incentives, automatic 
cost recovery factors, and provisions for earning a premium on power plant 
construction. TU Electric fully embraced the notion that IRP should not inhibit 
competition, but noted that the commission must streamline, not over-regulate, 
the IRP process. 
CSW suggested that the time spent preparing a mandatory preliminary plan is 
largely a waste of time. SPS stated that IRP will inhibit the development of 
competitive markets by establishing a costly, cumbersome process that will be 
utilized by special interest groups. HL & P stated that public policy has been 
set by the Legislature, and the commission must address the wholesale market. HL 
& P stated that traditional IRP concepts are out of step with changes in the 
industry. EPE stated that the dissemination of proprietary information pursuant 
to the IRP process will place utilities at a competitive disadvantage. TNP 
stated that the appropriate application of IRP principles can smooth the 
transition to competition, and that utilities that remain vertically integrated 
require more regulatory oversight than those utilities that functionally 
unbundle. TNP stated that unbundling is already occurring, and that utilities 
are already aware of the burden of proof required for approval of new resources. 
GSU stated that special care should be taken during the development of this rule 
to limit the exposure of sensitive competitive information. East Texas stated 
that the regulations need to reduce filing requirements, allow utilities to be 
flexible, and not rely on prescriptive approaches if wholesale competition is 
desired. STEC agreed that IRP should not inhibit the development of competitive 
power and energy service markets, and cited areas where the proposed rule may 
inhibit competition, including the length of time for the whole process, the 
application of externalities and subjective selection criteria, biases against 
affiliates, and access by competitors to a utility's competitive strategy. 
Enron stated that IRP is unlikely to result in the same resource allocation as 
markets driven by the needs of individuals, and IRP will not by itself achieve 
competition. Good Company stated that there is competition in the energy 
services sector, and that all energy service providers should have the 
opportunity to compete fairly. Good Company argues that the IRP rule must 
endorse one of two DSM choices: continued reliance on traditional utility DSM 
programs, or unbundled energy service opportunities to allow third-party energy 
service providers to satisfy customers needs. Good Company stated that 
unbundling would allow third parties to make modifications to end-uses to 
achieve energy efficiency, but would remove from the utilities the 
responsibility of selecting a service provider or specific technology. 
Traditional utility-provided DSM is very disruptive to the marketplace because 
utilities choose winners and losers among the bidders and because utilities 
choose winning and losing technologies when other technologies might satisfy 
customers' needs. Mr. Shapiro stated that a total laissez faire approach should 
not be allowed.
Power Connect urged that until emerging competitive markets are securely 
established, regulators must guard against potential abuses from electricity 
monopoly franchises. Destec stated that it is not certain that IRP as conceived 
in the 1970's has a place in a restructured electric industry; however, even 
under market- based resource acquisition regulators will have a valuable role as 
overseer of planning activities. Public Citizen stated that although the utility 
industry is changing rapidly, IRP has a key role to play in a transition to 
competition because Texas is far from a fair or fully-competitive industry. 
Consumers Union stated that IRP will not inhibit competitiveness in the electric 
industry; rather, as the commission stated in its December 1, 1994, letter to 
the Governor, IRP can smooth the transition to a new competitive electric 
industry. Consumers Union stated that IRP is essential even under some form of 
competition because it is a way of setting standards for the types of resources 
will be solicited; otherwise, market failures will result in losses to 
residential and low-income customers. EDF stated that the proposed language 
should be modified to recognize the explicit role of IRP in furthering the 
development of competitive markets. TREIA stated that the words "fair 
competition" should replace "competitive markets." TIEC stated that IRP should 
support and be consistent with Project Number 15000, and later modified once the 
transition is complete. TGA believes that the existing competition in end-use 
markets necessitates a broadening of the statement to include all energy 
markets. Texas Rose stated that an economically-efficient market would provide 
for the delivery of a broad range of electricity services including DSM 
resources and renewable energy resources, the participation of many buyers and 
sellers, and an accounting for future fuel price, fuel supply and environmental 
risk in the resource evaluation process. TPGA stated that the public interest 
will be better served by competitive markets for all energy services, not just 
electric power. Nucor Steel wholeheartedly supports the language. 
The commission agrees with those who stated that the IRP process is a useful 
transitional mechanism that can advance the objectives of competitive markets. 
Specifically, the competitive solicitation for supply-side resources can ensure 
fair entry into wholesale power markets and the demand-side resource 
solicitation is one means of advancing competition in energy service markets. 
The primary purpose of the IRP process is to require utilities to look at a full 
range of resource alternatives, both demand- side and supply-side, to decide on 
the attributes of resources that are needed, and to acquire resources in 
competitive markets. The commission believes that IRP will foster and complement 
the development of competitive markets. 
The commission posed several questions related to which utilities should file 
information related to resource planning. The commission asked whether it should 
require all electric utilities in Texas to file a preliminary integrated 
resource plan, or a letter stating their intent with regard to planning matters. 
The commission also asked how to develop a robust resource solicitation process 
that will remain workable under various industry restructuring scenarios. State 
Representative Hirschi stated it would be unwise to tie distribution companies' 
profits to the amount of electricity they transmit because that reduces the 
incentive for conservation. OPC took the position that only investor-owned 
utilities and generation and transmission cooperatives need file an IRP because 
distribution company restructuring is not currently contemplated by PURA and 
would require legislative changes. 
It is TU Electric's position that the commission should not create a 
solicitation process that will fit every possible future market configuration. 
SPS stated that the commission should only require utilities planning to 
construct generating resources to submit a preliminary IRP, as required by PURA, 
sec.2.051(e). SPS provided that the development of competitive resource markets 
depends not on Texas alone, but on the national markets for those services; 
therefore, the commission should not take the sole responsibility for developing 
a robust resource solicitation process. HL & P stated that future distribution 
companies will conduct a resource solicitation as a matter of good business 
practice, and that a regulatory filing will be unnecessary. HL & P stated that 
the commission should be out of the business of developing a resource 
solicitation process in a restructured electric industry. CSW stated that, while 
the preliminary IRP filings are required by statute, the commission should focus 
its attention on review of near-term resource needs and decisions being made by 
the utility. TNP stated that all utilities should file a letter stating their 
intent with regard to planning matters and that appropriate IRP rules will set 
forth minimal filing requirements with a limited hearing process to address the 
requirements of the statute. GSU stated that utilities should be able to file 
documents appropriate to the level of commission action they are seeking. 
Priority should be given to those utilities which plan to proceed to resource 
solicitation in the near term or which have a clear need for capacity, and the 
process should be flexible and focus on proven standard business practices. EPE 
stated that if the future is competition, utilities should not be required to 
file a preliminary plan or a resource planning statement. The commission should 
make the resource solicitation process as flexible as possible because the 
future industry structure is uncertain. TEC stated that the exemptions expressly 
carved out by the Legislature when crafting the IRP process do not require the 
filing of a preliminary plan by non-generating utilities, unless such utilities 
plan to construct generating facilities. BEPC stated that a non-generating 
utility should not have to file a preliminary plan. A utility that purchases 
power from a non-utility generator should have to file a letter that sets forth 
the name of its supplier and basic information on the quantity purchased. Non- 
utility generators that intend to purchase resources from new suppliers should 
be subject to the same regulations as regulated utilities. STEC stated that it 
is neither desirable nor necessary for all utilities to file a resource planning 
statement. East Texas stated that the proposed rule appears to raise the issue 
of whether or not a utility requires additional resources; however, not all 
utilities should be required to file an IRP. East Texas recommends that 
utilities with less than 200 megawatts of generation not be required to file an 
IRP. The rule should define the term generating utility. 
Enron stated that the commission should focus on an IRP process that is workable 
in today's environment, and that will not impede movement toward a more 
competitive environment. Good Company stated that the commission should require 
all utilities to file a preliminary IRP or a resource planning statement. The 
commission has proposed elimination of the energy efficiency planning rule, and 
without it, the commission would have no oversight of most utilities' DSM 
programs. Therefore, the amendment, not elimination, of sec.23.22 is 
appropriate. Non-generating utilities should be required to acquire resources in 
a competitive market. Mr. Shapiro stated that all utilities that sell at retail 
should be required to file a plan so that the commission can evaluate the 
utility plan in light of the statewide IRP. Public Citizen submitted that the 
commission should use its authority to require the distribution utilities to 
have a portfolio of resources, contracts and fuel types. The commission's 1994 
statewide electrical energy plan showed an alarming lack of diversity in fuel 
and a dramatic increase in the number of natural gas-fired plants. Further, the 
IRP rule and statutory provisions that do not require certification or approval 
of contracts under two years in length will have the severe and unintended 
consequence of creating a short-term market for power. The only way to avoid 
this consequence is to adopt a rule requiring a portfolio of both long- and 
short-term contracts and non-fueled resources. Consumers Union stated that the 
statute exempts certain utilities from the IRP process. The commission cannot 
obtain jurisdiction to require those exempted utilities to file an IRP without 
specific legislative authorization. Gulf Cities stated that all electric 
utilities providing electric service to the general public should be required to 
file a preliminary integrated resource plan. To exempt non-generating utilities 
from the IRP process would eliminate the opportunity of the utility customer or 
interested non-utility customer to participate in a formal process and would 
limit the ability of the commission to have adequate and reasonably complete 
information in the development of a statewide IRP. TREIA stated that all 
utilities should be required to file either a preliminary plan or a resource 
planning statement. The commission should require more information for the 
resource planning statement. EDF stated that the commission should require all 
electric utilities to file preliminary plans. The commission should experiment 
with application of its proposed resource solicitation process before concerning 
itself with how competitive solicitations would evolve under full retail direct 
access. GLO stated that all electric utilities should be required to file a 
preliminary plan. Complete geographic information systems databases should be 
included in the requirements detailing the utilities' existing and planned 
transmission and distribution system network. 
TIEC stated that the development of retail competition and the ability of 
customers to choose where they buy their electricity will ensure a robust 
resource solicitation process that will provide resources at the lowest 
reasonable system cost. Texas Rose stated that in the interest of developing a 
meaningful statewide IRP, the provisions of the rule should apply as widely as 
possible. TPGA believed that the commission should require all electric 
utilities to file either a preliminary plan or a resource planning statement, 
and that the proposed language does not go far enough in setting forth 
guidelines for utilities to value DSM outcomes and subject them to market 
forces. TPGA commented that the rule should require consideration of propane and 
natural gas technologies and should prohibit exclusion of these resources in any 
way by electric utilities. TPGA stated that all energy suppliers should be able 
to fairly compete to provide the lowest-cost energy, and that customers should 
have the greatest number of choices possible among energy options. TGA stated 
that all electric utilities in Texas should be required to file preliminary 
plans. The commission needs data from all utilities to prepare its statewide 
IRP, and the published proposal repeals the load and capacity resource forecast 
filing and energy efficiency plan filing requirements. The commission needs more 
information about DSM from all utilities than would be submitted in the proposed 
resource planning statement. TGA expressed concern that future distribution-only 
investor-owned utilities would be exempted from the rules as proposed. 
In its deliberation on these matters, the commission considered such issues as 
which utilities should file planning documents, the intensity of the review of 
the plans filed by investor-owned utilities, whether the definition of the need 
for resources reaches beyond a simple capacity need, and what role the 
commission should play in determining the need for resources. The commission 
considered a variety of concerns relating to cooperatives in deciding to limit 
IRP filings to those utilities specifically mentioned in the statute. Further, 
the commission will not attempt to anticipate in this proceeding whether 
distribution-only investor-owned utilities will be formed in the future or what 
an appropriate IRP process might be for those entities. The statute seems to 
equate the construction of generation facilities with resource planning 
responsibility and with a need for regulatory oversight of resource planning. In 
the future, distribution utilities may be required to acquire resources through 
a competitive solicitation process, thus associating the obligation to serve all 
customers in an area with the obligation to plan for resources to serve such 
customers. 
The commission agrees with the parties who stated that the commission should 
follow the processes set forth in the PURA. While the commission is sympathetic 
to the concerns expressed with regard to existing DSM programs, including 
electric cooperative DSM programs, the commission will not expand the scope of 
IRP filing requirements beyond the statute. Rather, the commission recognizes 
that a review of all promotional DSM activities and rate designs may be 
appropriate. Therefore, the commission directs the staff to take up the issue of 
reporting on promotional rate designs, rebates, and DSM activities in the retail 
market as part of another rulemaking. Consequently, the commission will not 
repeal the energy efficiency plan rule, sec.23.22, at this time. 
The intensity of review refers to the manner in which regulatory oversight of 
resource planning matters is implemented. As a practical matter, the 
reasonableness of the service area forecast, the target reserve margin, the 
projection of load loss, and the estimates of the impact of interruptible loads 
and conservation activities are key inputs to the determination of resource 
need. In striking a balance on this issue, the commission considered the costs 
and benefits of detailed oversight of utility planning and practices, and 
compared this to the value of increased flexibility for utilities in acquiring 
resources in competitive markets. The commission rejected the notion that 
preliminary plans that do not contain a proposed solicitation should undergo the 
full IRP process. However, the commission will enter a final order on the docket 
handling the preliminary plan filing to give the document finality. The 
commission will issue a notice regarding the filing of a preliminary plan that 
does not contain a proposed solicitation. The commission will then determine 
whether the preliminary plan is in compliance with the regulations. If 
necessary, the commission would use its enforcement authority to remedy 
deficient filings. The rules make clear that no public hearing will be required 
to judge the adequacy or merits of a preliminary plan that does not contain a 
solicitation. The scope of the commission's compliance review will be to 
determine whether the filings are "comprehensive" and whether they "provide 
sufficient detail, work papers and source materials to allow the commission to 
determine the accuracy and reasonableness of the determinations made by the 
utility." The commission will reject filings that do not meet this standard. If 
the filing is sufficiently comprehensive and meets the other tests of the rule, 
the commission's inquiry into a preliminary plan that does not contain a 
solicitation is at an end. 
The commission believes that under the statute, the need for additional capacity 
is the central factor which determines whether a utility is required to conduct 
a solicitation and complete the full IRP process. However, the commission 
directs all public utilities to consider the operating costs of each generating 
unit in their assessment of resource need. The commission concludes that it 
cannot limit the definition of the "need for resources" entirely to the need for 
new capacity additions because that would result in an over-simplification of 
how resource planning is conducted. Early retirement of costly generating units 
might lower system costs, and thereby increase the need for replacement 
resources. Utilities should therefore consider the possibility of plant 
retirements in the resource planning process. 
The IRP process can foster the transition to competition if the commission 
requires utilities to rely on competitive procurement to reduce costs. Wherever 
possible, the commission prefers marketplace bids as a yardstick for utility 
performance, rather than continued reliance on administrative review. The goal 
of the IRP process is reliable power at lowest reasonable system cost, and all 
utilities should pursue all resource options that lower system costs. The 
commission concludes that the utility must consider whether there is a need for 
additional resources. The commission has outlined filing requirements that 
include factors that a utility must consider in determining the need for 
resources, including a consideration of the operating costs of existing 
generating units and whether early retirement of an existing unit would reduce 
system cost. The commission will conduct a compliance review of any preliminary 
plan that does not contain a proposed resource solicitation. 
With respect to DSM programs, the approach taken by the commission is to allow a 
utility to conduct an ongoing annual DSM solicitation if its customers determine 
that such resources might prove beneficial to the system. A utility may need 
low-income and tenant DSM programs to improve the overall equity of its DSM 
portfolio, or it may need to acquire small amounts of DSM annually as a hedge 
against future events. As a general principle, such annual DSM solicitations 
should be subject to a cost cap based on a current, competitive market measure 
of the utility's avoided cost of acquiring resources, such as the results of the 
utility's most recent IRP solicitation. However, the commission recognizes that 
certain limited exceptions to this cost standard might be necessary to meet the 
statutory goal of providing DSM programs to all customer classes, particularly 
low- income ratepayers. 
The statute anticipated a resource solicitation for both supply-side and demand-
side resources and such activities as conservation and customer load management 
affect the energy usage patterns of customers' retail loads. In preparing a rule 
proposal for publication, the commission considered the role of promotional DSM 
programs in retail energy service markets. The commission is concerned that DSM 
practices may inhibit energy service markets, and may result in subsidies not 
intended by the societal objectives of energy efficiency and the conservation of 
resources. Because retail consumption and usage patterns (that is, load 
forecasts) are a key input into resource planning, the commission published a 
rule proposal that addressed a variety of retail usage issues. The commission 
considered whether in conducting a resource solicitation it would be appropriate 
that the utility consider a broad range of alternatives, or whether it would be 
acceptable for a utility to exclude certain potential resources. In the 
preamble, the commission posed the following questions: What level of discretion 
should utilities exercise in excluding resources from consideration within a 
request for proposals? How should the commission balance the utility's desire 
for flexibility with the requirement that a utility consider a broad array of 
resources? Should the commission require electric utilities to review and fairly 
evaluate the bids of retail market competitors (such as natural gas utilities) 
that are based on alternative-fuel technologies (such as natural gas cooling)? 
If so, and if such bids are "best" according to the specific criteria contained 
in the request for proposals, what action should the commission take if a 
utility does not negotiate contracts and procure resources from such bidders? 
Several parties commented that IRP deals only with wholesale competition, and 
that the retail electric services sector remains regulated just as it always has 
been. The electric utilities generally supported the position that only "true 
energy resources" should be allowed to bid. TU Electric stated that requiring a 
utility to consider bids from retail market competitors is the opposite of 
competition, and such a requirement would give the utility's retail market 
competitor an advantage. HL & P stated that the commission should not interfere 
with competition in the energy services sector. CSW stated that fuel switching, 
self-generation and customer relocation are not resources to meet the utility's 
needs, but rather are a reduction in the utility's need for resources. SPS 
echoed those positions and stated that the decision to switch to alternative 
fuels should rest with the customer. Consumers Union submitted that IRP should 
include resources that achieve the goal to provide reliable energy service at 
the lowest reasonable system cost, and that IRP should exclude alternatives 
which do not meet that goal. Gulf Cities took the position that if a utility 
chooses to exclude specific alternative resources from bidding, then the utility 
must specifically identify the resources excluded and support its rationale for 
restrictive eligibility requirements. Good Company stated that utilities should 
not be allowed to exclude resources because all resource alternatives need to be 
assessed to see whether they provide benefits to customers. Several parties 
expressed the view that the commission needs to adopt a methodology for 
determining whether load-building programs are in the public interest. Potential 
energy service providers urged equal consideration of all demand-side and 
supply-side opportunities for meeting customer demands. Some parties suggested 
that the following alternatives be considered as resources: distributed 
generating resources, transmission lines, real-time-pricing, various innovative 
rate designs, new services options that increase revenues, geographically- 
targeted DSM, new customer billing arrangements, fuel-switching activities that 
increase or decrease electric sales, and retail access (retail wheeling). Texas 
Rose stated that the commission should establish by rule a minimum set of 
specific DSM programs, renewable resources, and purchase power alternatives that 
all utilities will be required to evaluate in their resource plans. Texas Rose 
stated that a core resource list would include DSM programs for homes and 
apartments, low income customers, small businesses, and large industrial 
customers. Nucor Steel stated that the rule should require the utility to 
consider any reasonable resource that can cost-effectively affect the utility or 
customers' needs, including rate design options such as real-time pricing and 
interruptible rates, as well as self-generation and even retail wheeling. The 
commission concludes that the eligibility rules for bidders should be compatible 
with an all-source bidding process in which the resource solicitation is used to 
obtain market information, and selection criteria based on the utility's needs 
are used to determine the resources that the utility will rely on. Either 
granting broad discretion to the utility to exclude resources or prescribing a 
list of approved resources is inconsistent with a selection process that focuses 
on serving customer needs in a cost-effective manner. The commission concludes 
that the eligibility provisions of a solicitation should be broad and that 
resources should be selected on the basis of the benefits that they provide, 
regardless of whether those resources rely principally on electrotechnologies. 
The commission recognizes that there may be instances where it is 
administratively efficient to allow a utility to exclude specific resources from 
bidding. Since this exclusion would inhibit the market processes that the formal 
resource solicitation is attempting to enhance (fostering the consideration of a 
broad range of resources), the commission should grant such restrictions on a 
case-by-case basis after reviewing the utility's support for the proposed 
eligibility restrictions. Some electric utilities contend that only 
electrotechnologies are true resources, but the commission rejects this view as 
unreasonable. Regulations that allow utilities to exclude the bids of 
competitors at the utilities' sole discretion are subject to abuse. The 
commission agrees with the comments about not interfering with competition in 
the energy services sector (HL & P), and about leaving the decision to switch to 
alternative fuels with the customer (SPS). To reduce regulatory interference, 
the commission will begin to remove regulation by opening up markets to all 
energy service providers. Any suggestion that regulators and monopoly electric 
utilities are not presently interfering in the energy services sector is without 
basis. The goal of the commission's new regulations is not to interfere in the 
energy services sector, but to establish a regulatory framework which promotes 
competitive parity and allows competition in that sector to function 
effectively. Traditionally, the regulatory process has focused on the 
establishment of reasonable rates and services for retail customers. Energy 
services have been fundamentally shaped by regulatory processes (including the 
administrative approval of tariffs), and by the marketing and DSM activities of 
utilities. Tariffs have a strong influence on the energy services sector because 
administratively- approved tariffs offer a limited choice of service and pricing 
options to most customers. DSM programs have increased the service options 
available to customers and have focused on improving end-use energy efficiency 
and retail pricing. 
Restrictions on the DSM solicitation process will inhibit the ability of 
innovative energy service providers to lower a utility's system costs. The 
commission also finds that prescriptive or inflexible approaches that set forth 
by rule lists of technologies that must be considered are also unreasonable. The 
commission believes that it is reasonable to require each utility to 
specifically identify the resources that would be excluded from bidding. The 
utility would then need to support the rationale for restrictive eligibility 
requirements in its proposed resource solicitation, as contained in the 
preliminary plan. The commission believes it is reasonable that IRP include 
resources that achieve the goal of providing reliable energy service at the 
lowest reasonable system cost. The nature of the screening and selection of bids 
will result in the elimination of bids that would not contribute to meeting that 
goal; it is not necessary to exclude them at the outset. Elimination through 
screening will occur through the application of the specific weights assigned to 
the resource selection criteria. Bids that score poorly on heavily-weighted 
criteria will be eliminated. Bidding restrictions at the outset are incompatible 
with the all-source bidding process supported by the commission.
The commission requires utilities to rely on the resource solicitation process 
to obtain market information; requires utilities to screen bids, select 
resources, and negotiate contracts; and permits certification of contracts for 
resources with third parties in the final plan. The specific resource selection 
criteria approved in the preliminary plan will largely determine the resources 
that are selected, and such resources will necessarily contribute to the goal of 
providing reliable electric services at lowest reasonable system cost. 
In the preamble, the commission raised the issue of functionally unbundling the 
electric distribution operations of utilities. The functional unbundling of 
distribution operations is one possible means of addressing competition in the 
energy services market. Since both natural gas utilities and electric utilities 
are authorized to serve the same end- use customers in Texas, there is limited 
retail competition for certain customer energy needs. Limited retail competition 
also exists among utilities and independent providers of services that rely on 
electrotechnologies. There is the potential for utilities to favor their own DSM 
programs and to thereby inhibit the opportunities for independent service 
providers. The commission has attempted to deal with the issue of electric-gas 
end-use competition for a decade through its regulation of utility practices, 
but this has required close scrutiny of each conservation and load management 
program. In November 1987, the TGA filed a letter and resolution with the 
commission requesting that the commission examine the promotional practices of 
electric utilities that TGA believed distort the relative merits of gas and 
electric energy. TGA stated that some electric utility conservation programs did 
not encourage energy efficiency, but were thinly-disguised marketing efforts. 
TGA drew the commission's attention to the problems which arise when a monopoly 
utility uses revenues and information from one sector of its operations to 
subsidize its activities in partially-competitive markets. The commission has 
also considered promotional aspects of rate designs in rate proceedings. In 
addition, since December, 1989, and every two years since, the commission has 
asked utilities subject to sec.23.22, relating to energy efficiency plans, to 
report to the commission how existing tariffs encourage the efficient use of 
resources. With these issues in mind, the commission posed the following 
questions in the preamble of this rule: Should the commission address the 
regulatory problems associated with natural gas providers and electric utilities 
by functionally unbundling the electric distribution operations of electric 
utilities? What are the benefits of such an approach, and what problems are 
associated with implementing competitive energy service markets? Is the proposed 
preliminary plan filing requirement related to energy service and pricing 
options a sufficient means of ensuring that a utility's retail rates and 
services offer a broad menu of options to retail customers? 
The parties' responses varied widely. Several parties that supported unbundling 
stated that the creation of distribution-service-only utilities, or a 
requirement that all retail services be completely unbundled, may be beyond the 
authority of the commission or beyond the scope of this rulemaking proceeding. 
Other parties focused on DSM-specific problems and solutions that are discussed 
elsewhere. TU Electric reminded the commission that it is beyond the 
commission's authority to order unbundling of distribution operations. HL & P 
stated that retail functional unbundling challenges the premises of PURA because 
IRP is not a forum to address retail competition. HL & P stated that the 
commission has no authority to address unregulated services that may be offered 
in the future. EPE stated that complete unbundling will require reconsideration 
of issues such as exclusive franchise service territory, universal service, 
etc., and presented concern that those entities providing ancillary or control 
area services would not be fully reimbursed for incurred costs. SPS requested 
that the commission identify the regulatory problems associated with unbundling 
distribution operations of natural gas and electric utilities before trying 
radical restructuring proposals. Further, SPS noted that a competitive bidding 
process ensures that a broad menu of economic options is available to retail 
customers. 
TNP supported the notion that vertically-integrated utilities must functionally 
unbundle, and noted that market pressures are forcing the unbundling of the 
energy services sector. TNP reminded the commission that DSM is changing. In the 
past DSM was used as a resource to postpone the need for generating resources; 
however, in the market for energy services, according to TNP, customers are 
willing to purchase or invest in services that lower their total costs. TNP 
noted that utilities are unbundling the energy services aspect of the business 
in order to retain market share, especially where customers are at risk. 
Enron supported unbundling of distribution charges into three cost-based 
components: distribution service (wires, poles, transformers); metering and 
billing; and other customer services. Enron stated that the preliminary plan 
filing requirements for pricing and service options are a poor substitute for 
retail access. Gulf Cities stated that unbundling is a necessary element in the 
transition to a competitive environment, but noted that the issues associated 
with implementing competitive energy service markets may not be ripe for 
consideration at this juncture. Consumers Union urged consideration of this 
issue within Project Number 15000. TGA stated that the preliminary plan filing 
requirements are insufficient to ensure a broad range of service and pricing 
offerings to customers. TGA also cited electric utilities' fuel-switching 
activities, including declining block rates and DSM that rely on the electric 
utilities monopoly position. TGA advocated the use of cost-effectiveness 
screening tests to examine these programs. NAESCO stated that traditional energy 
efficiency programs have not been designed to promote the delivery of energy 
efficiency in competitive markets, in part because utilities have been reluctant 
to expose customers to market forces and to non-utility competitors. Good 
Company supported unbundling of the energy services of the utility, and if that 
is not possible, recommended that the commission balance a utility's market 
power with a detailed set of guidelines to increase customer choice. Good 
Company argued that the time for traditional DSM programs has passed, and that 
unbundling will increase competition in energy services. This will occur because 
the marginal costs of the utility will define the value of DSM programs. Texas 
Rose stated that the DSM market should be opened to all service providers 
including energy service companies and suppliers of natural gas and renewable 
technologies. TPGA supported the unbundling of the energy services of electric 
utilities and stated that each utility ought to identify the value of various 
DSM outcomes, then allow competition for these services. Finally, Nucor Steel 
stated that the commission cannot effectively separate the energy services 
market from the retail electricity market: you cannot deregulate one market and 
keep the other a regulated monopoly. 
One potential solution to the challenge of regulating the limited end-use 
competition that exists in today's retail markets is to more clearly separate 
competitive or potentially competitive activities from traditional monopoly 
activities. There are steps that the commission might take to deregulate the 
energy services markets, without affecting retail access for independent 
providers of generation services. The commission has attempted, through past IRP 
rulemaking efforts, to increase competition in the energy services sector, and 
to mitigate anti-competitive behavior in that sector, in particular, by making 
improvements in the solicitation process. However, the commission has been 
unable before now to adopt IRP rules or to adequately address the potentially 
inappropriate use of DSM programs and special rate designs to cross-subsidize 
and promote the use of electricity. The question now is whether functional 
separation of electric distribution operations will address this potential for 
anti-competitive behavior. The commission believes that it will. The division of 
utility electric distribution operations into natural monopoly components and a 
competitive component (energy services) will result in an unbundling of retail 
rates and services, such that captive electric customers will select from a menu 
of service options. A broad array of innovative energy services may then be 
provided in competitive markets, and all competitors, including electric utility 
subsidiaries, will provide service on an equal basis. Such a system will require 
that competitors in energy service markets be granted the same access to 
electric customer information (subject to privacy protections) that is available 
to utility subsidiaries and the functionally separated energy service units. 
Third parties could then work with electric customers to reduce total energy 
costs or to provide new services. Increased customer choice from the existing 
utility would be consistent with other economic efficiency goals, and would 
promote the provision of retail energy services to customers at the lowest 
reasonable system cost. 
The commission has therefore included a distribution functional separation 
requirement in this rule. The commission believes that such separation is 
necessary to enforce the commission's obligations under PURA, sec.2.051(m) and 
sec.2.216. Both of these sections impose an obligation on the commission to 
mitigate the potential for anti- competitive behavior in the energy services 
market. The commission believes that the functional separation requirements 
contained in this rule are the minimum necessary to adequately enforce its 
obligations under the statute. The commission recognizes that the general 
functional separation requirements adopted here will require further rulemaking. 
Therefore, the commission directs the staff to address the details relating to 
the functional separation of distribution operations by initiating a rulemaking 
on functional unbundling. This rulemaking will define the details of the 
distribution functional unbundling and establish a timetable for its 
implementation.
The commission supports the increased use of new and innovative tariffs to 
expand the customer choices that are available from the existing monopoly 
provider. As part of the preliminary plan filing, each public utility shall 
indicate what pricing and service options are available to each customer class, 
and shall indicate what eligibility restrictions are placed on its existing 
rates and riders. Some classes of customers may have options where utilities are 
offering a broad array of pricing and service options to retain such customers 
to eliminate uneconomic bypass. Where limited options are available to a 
customer class, the utility would be expected to analyze the impact of 
alternative pricing and service options on the need for additional resources. 
The commission believes it is important to provide the maximum array of service 
options to customers, so that they can tailor their electric services to their 
individual needs. To further this goal, the commission directs the staff to 
initiate a separate rulemaking to establish guidelines and/or requirements with 
regard to retail customer pricing and service options. The proposed rulemaking 
should include consideration of any minimum service obligations and quality 
standards that should be imposed on the functionally separated energy service 
providers and on independent competitors in the energy services market. 
The statute requires that the commission periodically adopt long-term resource 
planning goals in a statewide IRP, and requires that utilities subject to such 
regulations focus on achieving the lowest reasonable system cost through 
resource solicitations. In the preamble, the commission posed the following 
questions: Is it appropriate for the commission to leave further definition of 
the term "lowest reasonable system cost" to each utility's preliminary 
integrated resource plan? What is the appropriate role of the commission in 
setting long-term planning goals for Texas? How would those goals affect the 
definition of lowest reasonable system cost? Can the goals of the statute 
relating to the diversity or mix of resources be met in light of the 
commission's proposal to require all-source bidding? State Representative 
Hirschi stated that it is wholly appropriate for the commission to be involved 
in long-term planning for Texas to reduce dependence on imported fuels and to 
improve the environment. OPC submitted that it is up to the utilities to propose 
a mix of resources that satisfies the factors listed in the rule. OPC also 
suggested that the utilities be required to present in their preliminary plans a 
proposal for dividing their solicitation into three segments: renewable 
resources; other supply-side resources; and demand-side resources. Gulf Cities 
believed that the ultimate definition of "lowest reasonable system cost" will be 
unique to each utility in the filing for its preliminary integrated resource 
plan and that the definition may change over time. 
TU Electric suggested that the term "lowest reasonable system cost" has already 
been defined by the Legislature in PURA, sec.2.051(a) and requires no further 
definition. That definition will have to be applied to utility-specific facts on 
a case-by-case basis. TU Electric proposed that the commission's long-term 
resource planning goal should be to ensure that all customers reap the benefits 
of market-based, competitively- priced resources obtainable through a fair and 
impartial solicitation process. CSW believed that the definition of the term 
"lowest reasonable cost" should be left to the individual utility to determine 
in its preliminary plan based on the input of its customers, its own risk 
profile, and its strategic direction with respect to resource procurement. CSW 
further stated that, for the transition to a competitive bulk power market, the 
commission should set goals that will ensure a reasonable balance between low 
cost and reliable service, dependable service, service quality and diversity of 
resources. HL & P stated that utilities should not be required to consider non-
cost factors that camouflage the true market price of power in a competitive 
market. For example, environmental values are already reflected in the state and 
federal environmental laws. The commission should approve the utility's 
definition of "lowest reasonable system cost" in each preliminary IRP, and avoid 
predetermined rules and generic methodologies. The commission should set a long-
term goal of letting the market work. LCRA suggested that each utility should be 
given the ability to manage its resource portfolio (and to target solicitations) 
to maximize diversity of resources without having to show good cause as 
suggested in proposed sec.23.34(i)(1). SPS submitted that each utility may have 
unique circumstances; hence, the commission should retain flexibility in its 
regulation so that innovative solutions and responses to changing circumstances 
can be adopted. TNP argued that the definition should not be stated by rule. 
Utilities should have the freedom to evaluate non-cost criteria to make sure 
that they are consistent with utility strategic plan objectives, customer 
desires, and competitive position. The commission can makes its final 
determination regarding "lowest reasonable system cost." Commission goals should 
be incorporated by the utility if such goals do not harm the utility's 
competitive position and if customers share the goals. GSU stated that the term 
needs further definition but it should be compatible with the definition that 
will emerge from the competitive market. EPE stated that utilities must have 
flexibility for determining what the appropriate "lowest reasonable system cost" 
means with regard to its own system. The appropriate role of the commission is 
to monitor the long-term planning goals to ensure that utilities provide 
reliable energy services at the "lowest reasonable system cost," not to set 
planning goals for utilities. STEC believed that the rule proposal appropriately 
defines "lowest reasonable system costs" in accordance with the statute, and 
resists the temptation to conduct social policy through economic regulation. The 
commission should adopt long- term planning goals consistent with the statute. 
BEPC stated that the commission should leave any further interpretation of the 
meaning of "lowest reasonable system cost" to each utility's preliminary plan. 
East Texas stated that the granting of a certificate requires cost- effective
conservation, but the commission should allow utilities to use the rate impact
measure to define cost effective. East Texas wants the term "lowest reasonable 
system cost" further defined by rule such that low rates would be the definition 
of "lowest reasonable system cost." 
Mr. Shapiro advocated the setting of long-term goals in the statewide IRP. 
Destec believed that in the emerging competitive marketplace for electric 
services, ratepayers should only pay for options that have passed a market-based 
cost comparison test. The objectives of utility resource planning and 
procurement should be the provision of low-cost, environmentally sensitive, 
reliable electric service to the customer. CEED believed it is unnecessary to 
clarify the definition of "lowest reasonable system cost." By choosing the 
phrase system cost, the Legislature made its intention plain because system 
cost, by definition, refers to internal utility costs. BFI stated that language 
should be added defining "cost of compliance" to include environmental costs 
(resulting from generation, transmission, distribution, etc.) of electricity or 
impacts that are not directly reflected in prices paid by customers. Public 
Citizen believed that the definition of lowest system cost should be determined 
by the commission in the rules. Failure to do so will result in endless 
unnecessary rounds of redundant hearings at the commission and perhaps 
litigation. Consumers Union submitted that the goal of the process should be to 
minimize the cost of meeting energy service needs in Texas, reducing prices 
charged to ratepayers and conserving resources, while recognizing the need to 
provide reliable utility service. Consumers Union suggested that the commission 
follow PURA, sec.2.051(b) and (c) which require the commission to adopt planning 
goals, giving the commission both a role and a responsibility. TPGA stated that 
the phrase should be further defined considering the benefits and costs of the 
entire energy delivery system. TGA stated that "lowest reasonable system cost" 
needs further definition in regulations. The commission needs to guard against 
instances where a utility saves one dollar at the expense of two dollars to 
natural gas utility customers. Fuel-switching and load-building programs are 
neither inherently good or bad; each should be assessed on its merits. EDF 
stated that the "lowest system cost" should be explicitly defined. TREIA stated 
that the term is driven by the consideration of commodity prices alone and 
therefore is contrary to the meaning of the word reasonable. The definition is 
contrary to the Energy Policy Act of 1992 and the definition of the least-cost 
option. Zond stated that the commission should set rules relating to 
implementation of certain minimum levels of renewable energy and not leave such 
decisions to the utilities. All producers and distributors should be required to 
have a renewable portfolio standard which they must meet. TIEC stated that the 
"lowest reasonable system cost" should be decided on a case by case basis and, 
therefore, the commission need not attempt to further define the term in the 
rule. Texas Rose stated that "lowest reasonable cost" should be defined as 
minimization of revenue requirement, a measure of economic efficiency, where 
total customer utility bill, not the per unit energy rate, becomes the basis for 
measuring lowest-cost. Nucor Steel believed that the definition of "lowest 
reasonable system cost" must be the same for each Texas utility or the standard 
will be meaningless. 
The commission will adopt a statewide planning process that will allow utility 
customers to have input in planning decisions, and will allow the commission to 
conduct several IRP cases prior to the establishment of the statewide IRP in 
1998. The commission's general guidelines for the resource solicitation process 
describe the factors that must be considered in establishing the criteria that 
are presented to the commission for the proposed solicitation. The general 
guidelines state a preference for all-source bidding, for the quantification of 
resource selection factors, and for a comprehensive, integrated approach to 
determining specific resource selection criteria. The specific resource 
selection criteria set forth in a proposed solicitation must take into account 
the "lowest reasonable system cost," customer preferences, and the statewide 
goals. By placing importance on the general guidelines for the resource 
solicitation, the commission will lend certainty to the process and may reduce 
litigation. 
The commission agrees with those parties who stated that no further definition 
of "lowest reasonable system cost" is necessary in the rules at this time. The 
commission prefers to rely on public input to apply that definition to each 
service area. The commission believes that the statute mandates the 
consideration of factors beyond direct cost in determining a utility's "lowest 
reasonable system cost." Reasonable planners have always considered factors that 
are not as easy to calculate as direct costs, such as dispatchability and other 
technical characteristics. At the same time, the commission does not believe it 
is useful to clarify the definition of "lowest reasonable system cost" by adding 
more explicit language related to the appropriate resource mix and reductions in 
consumer electric bills. Again the statute is clear that a balancing is 
necessary. The commission will apply the statutory definition on a case-by-case 
basis, recognizing the interrelationships among the "lowest reasonable system 
costs," customer preferences, and the need for resources. The commission will 
decide how it will treat a particular utility's consideration of indirect costs, 
such as those that affect risks and consumer bills, in its consideration of that 
utility's preliminary plan. 
The issue of all-source versus targeted bidding is complicated because the 
nature of the bids received and the bids that win will depend heavily on the 
resource selection criteria. In conducting an all-source solicitation it is 
important that all relevant factors be considered and balanced in determining 
the resource selection criteria. The proposed rule set forth a preference for an 
all-source bidding approach. The commission adopts this approach but allows good 
cause exceptions to all-source bidding. In certain cases, a targeted bidding 
approach may be in the public interest, and may be the most effective means of 
achieving other policy goals, particularly if the customer input received by the 
utility through the public participation process reveals a strong preference for 
the acquisition of certain types of resources. The commission prefers that all-
source bidding rely on balanced resource selection criteria so that "all-source" 
in name does not become "targeted" in practice. In the preamble, the commission 
posed the following questions: Should the commission employ market valuations of 
environmental and other non-cost factors which influence the utility's resource 
selection process? Is it appropriate to give a utility the flexibility to use 
its discretion and judgment in the final selection of resources, particularly 
with regard to those non-cost criteria that are difficult to quantify? State 
Representative Hirschi supported the market valuation of environmental costs and 
cited the costs imposed on state and local governments from illnesses, 
especially respiratory illness that is linked to power plant emissions. 
Representative Hirschi cited a bill before the 74th Legislature that would have 
prohibited consideration of externalities, but which did not pass because it was 
unsound public policy. OPC proposed that instead of employing market valuations 
of environmental and other non-cost factors which influence the utility's 
resource selection process the commission should consider environmental and 
other non-cost factors in a qualitative manner. Gulf Cities stated that the 
commission should require environmental externalities to be considered in the 
selection process. Gulf Cities is concerned that costs stay with the cost-
causers and that the owner of a generating resource not create environmental 
problems that become a liability to local government. Steering Cities believe 
that it is appropriate for the commission to require utilities to address and 
quantify direct and indirect environmental costs. 
TU Electric submits that PURA, sec.2.051(a) precludes the monetization of 
environmental externality costs; further, PURA does not authorize the commission 
to mandate consideration of non-cost factors that are not specified in that 
section. CSW stated that the commission should employ market valuations of 
environmental and other non-market cost factors which influence the utility's 
resource selection process. CSW stated that mandatory market valuations of non-
price selection criteria may contradict a utility's definition of "least-cost 
resource" or goals established through customer participation. HL & P stated 
that it is appropriate to give utilities the flexibility to make final resource 
selection decisions, particularly with regard to non-cost criteria. SPS stated 
that the commission should not attempt to place values on non-cost 
considerations in resource selection. GSU stated that utilities should be 
afforded the flexibility to use discretion and judgment in the final selection 
of resources, particularly with regard to those non-cost criteria that are 
difficult to quantify. EPE stated that artificially increasing the cost of 
resources and imposing market valuations on non-cost factors will add to 
stranded investment. According to EPE, non-cost factors should be considered by 
the utility but should not be arbitrarily quantified or given great weight in 
the resource selection criteria. STEC stated that the notion of market 
valuations for non-cost factors is an idea that was rejected by the Legislature 
because externalities are judgmental and will distort economic decisions. 
Enron supported the use of market-based measures where available, and supported 
qualitative consideration of non-cost factors. Utilities should be allowed 
flexibility, but must justify their actions in the final plan approval process. 
CEED is uncertain as to what is meant by non-cost factors, and believes the term 
should be deleted from the language of the rule. Risk constitutes an economic 
cost that the utility bears. Factors of risk are indirect costs borne by 
utilities, and the commission should require quantification of difficult-to-
quantify factors only where it is practicable to do so. The LLI stated that the 
commission should employ market valuations of environmental and other non-cost 
factors that influence resource selection. Public Citizen stated that the public 
should be involved in weighing the options, and the commission should require 
the utilities to ask the groups what they think about how to evaluate the 
various risks and costs based on a list of questions promulgated by the 
commission. Consumers Union did not endorse monetization of environmental 
externalities, but stated that environmental impact and non-cost criteria should 
be considered in an IRP. BFI stated that the commission must specifically 
require consideration and assessment of environmental externalities within the 
proposed rule or else risk violating the commerce clause of the US Constitution. 
BFI stated that to do otherwise would be to favor out-of-state fuels to the 
detriment of in-state resources. Mr. Shapiro noted that the time horizon for 
markets is short, and the time horizon for environmental issues is long; hence, 
market valuations will not address the issue adequately. Texas Rose stated that 
CO2, NOx, and SO2 should be taken into account by all utilities. BEPC stated 
that all competitors should be required to use comparable methods if the 
commission determines that these factors should be quantified in the criteria. 
BEPC stated that the utility should be able to determine what non-cost factors 
should be considered. EDF stated that the commission should establish a standard 
on resource selection criteria that all utilities must use. TREIA stated that 
non- priced items should be considered, and that allowing utilities to use their 
discretion would be unproductive. TGA stated that the establishment of 
appropriate selection criteria is critical to the success of IRP. Utilities 
should be allowed to develop criteria that reflect their needs and operating 
requirements, and such criteria should address the quantifiable and difficult-
to-quantify aspects of DSM. TGA stated that the four standard cost-benefits 
analysis tests should be applied to all DSM activities. Zond stated that 
utilities should have flexibility, within the parameters of a renewable 
portfolio standard, to meet a minimum renewable energy goal. GLO stated that the 
commission should employ market valuations of environmental and other non-cost 
factors which influence the resource selection process. GLO drew attention to a 
Sustainable Energy Development Council report that contains recommendations and 
guidelines for arriving at these valuations. TIEC stated that the commission 
should not attempt to quantify non-cost factors which influence the resource 
selection process. TPGA stated that the rule proposal leaves far too much 
discretion with the utility to determine resource selection criteria. TPGA 
supported consideration of environmental externalities in the planning process, 
although that does not necessarily require monetization or quantification. Nucor 
Steel stated that the utility, and ultimately the commission, should attempt to 
quantify, where possible, various non-cost factors. 
The commission concludes that explicit weighting of all important factors is an 
important part of establishing selection criteria in the request for proposals, 
including the quantification of costs and the qualitative ranking of all other 
important factors. This process does not require the use of externalities in the 
bidding process, but it does focus on customer preferences and the lowest 
reasonable system cost objective. Customers may wish to consider explicit data 
regarding the importance of various factors, but the commission should not 
require quantification of all such factors in dollar terms. For instance, the 
commission believes it is reasonable to quantify environmental impacts in dollar 
terms where objective market price data is available to support such 
quantification, such as the price data which can be derived from existing 
markets for tradable emission allowances. The commission notes that the 
standards for approval of utility power plant certificates differ from the 
standards for approval of contracts for resources. Consideration of the factors 
cited in the statute for power plant certification is appropriate, but a 
contract for power with an exempt wholesale generator must meet a different 
standard. The exempt wholesale generator must win the competitive bidding, and 
that will depend on the application of the selection criteria. Factors such as 
environmental integrity are not banned from consideration; rather, their 
treatment may arise from the preferences of customers. 
In the preamble, the commission posed the following questions: What techniques 
or methods should this commission require utilities to apply in assessing risk 
in the context of resource planning? In the absence of a specific risk-
assessment methodology, how can the commission ensure that a utility has 
appropriately investigated risk? To what extent should the commission pursue a 
regulatory regime in which utilities assume all future resource risk, including 
fuel cost risk, and bear or reap the costs or rewards of such risk? Several 
parties stated that the lowest reasonable system cost should include the risk of 
future fuel cost changes and the risk of environmental regulation. These parties 
conclude that there is a statutory preference for DSM because it reduces the 
need for power plants. They believed there is a preference for power plants that 
emit fewer pollutants because such facilities are less risky than power plants 
with high emissions. Gulf Cities stated that it would be an error for the 
commission to establish specific techniques or methods for assessing risk, but 
it is appropriate to require utilities to analyze a minimum number of risks 
elements. The investor-owned utilities cautioned the commission not to require 
utilities to apply a specific technique or method in assessing risk. They 
preferred a commission review of the resource solicitations and contracts for 
resources rather than a detailed pre-solicitation review during the hearing on 
the preliminary plan. 
TU Electric stated that PURA, sec.2.051(a)(2) sets forth the risk factors to be 
taken into account, and that no further rulemaking on this subject is necessary. 
HL & P stated that market-based resource planning explicitly values risk because 
different elements of risk are reflected in different contracts for resources 
and utilities should be given the latitude to assess various risk factors. 
Electric cooperatives stated that utilities bear all the risk associated with a 
choice of resources in a fully competitive market, and argued against commission 
micro-management of the process. Zond stated that the risk- hedging value 
provided by renewable resources should be part of the utility evaluation. Zond 
commented that the commission should therefore set rules to quantify the value 
of this hedge, or set a minimum percentage requirement for renewable energy. 
Texas Rose and others supported the notion that the commission promulgate a list 
of risks to analyze, including the risk of fuel price increases and fuel 
shortages, contractor failures, and future environmental regulation. The 
commission would then specify that utilities conduct risk or sensitivity 
analyses on key variables. Consumers Union asked the commission to recognize 
that the automatic pass-throughs and incentives proposed by this rule are 
completely in conflict with the theory of performance-based regulation because 
the risks and rewards are not symmetrical. TREIA stated that the commission 
should allow utilities to suffer the consequences or reap the rewards of their 
decisions to mitigate global climate change. 
The adopted rule requires analysis of significant factors of risk, but does not 
attempt to indicate the specific methods that must be used to satisfy the 
requirements. The resource planning process needs to deal with uncertainty and 
risk, and utilities should use scenario analysis to assess risk. In an IRP 
process, utilities should be directed to show how their preliminary plans would 
change under at least a minimum set of internally consistent scenarios, such as 
a high economic growth scenario, a low economic growth scenario, etc. Utilities 
should explain how they value certain important options associated with 
resources, such as the option to accelerate or delay the construction of a power 
plant, and how they use financial markets in making planning decisions. 
Utilities should indicate how their preferred portfolio of resources addresses 
factors of risk (such as options to accelerate or delay a project), 
characteristics of resources (such as intermittence and dispatchability), and 
other factors of risk (such as fuel, performance, financial, and environmental 
risk). The commission concludes that more explicit requirements regarding risk 
analysis would be unproductive. The proposed language is sufficient to make 
clear the need for risk assessment, and the fact situation of each utility will 
determine the level of analysis that is appropriate. 
Regarding the specific matter of fuel price risk, electric utilities stated that 
it would not be in the interests of consumers to try to eliminate fuel price 
risk. HL & P requested that utilities be allowed to offer lower-risk services to 
consumers for a risk premium to expand customer choice. The parties who advocate 
increased use of DSM and renewable resources stated that a requirement related 
to the portfolio of resources would be appropriate so that all utilities reduce 
fuel price risk. Enron stated that it would be useful for the commission to 
consider not only the level of risk, but the means available to mitigate risk. 
Enron cited financial risk management of fuel prices, the cost of which can be 
used in the evaluation process. Power Connect stated that competition can 
provide portfolio diversity through contracts with competitors with enough 
capital to assume risks. Several consumer and environmental groups advocated the 
use of renewable resources as a means of mitigating risk. These parties stated 
that the statute requires an appropriate mix of resources as a means of 
mitigating risk and that the commission is required to encourage renewable 
resource technologies. A market-based portfolio standard has been advocated as 
the best way to ensure that renewable resources will play a role in mitigating 
future fuel price risk and environmental regulation risk. 
The commission supports the proposed language that requires consideration of 
options, the use of hedges, and an examination of scenarios. The IRP proposal 
focuses on the selection of resources that lower costs, and the objectives 
implied by the definition of the lowest reasonable system cost include 
consideration of factors of risk and the resource mix. The utility must rely on 
scenario analysis, must consider options in the resource solicitation, and must 
negotiate contracts which appropriately allocate risk. The IRP proposal also 
contains provisions for resource acquisition outside the formal solicitation 
process, and allows utilities to gain experience with options and other 
financial markets. 
The commission will continue to examine risk factors and the rate-setting 
process in the context of Project Number 15000 and the Scope of Competition 
report. Electric utilities should educate themselves about the hedging 
mechanisms that are available in other competitive markets, and the ways to 
incorporate such tools into their overall strategies. Competitive pressures call 
for increased regulatory flexibility that will allow utilities to make use of 
certain financial tools. This flexibility needs to be balanced with regulatory 
oversight of potential anti-competitive activities. The commission will continue 
to develop a thorough understanding of the development of electric markets to 
ensure that the IRP rule does not unduly inhibit the use of new financial 
markets. 
Portfolio standards are one means of mitigating risk, particularly the risk of 
future fuel price increases. However, the application of portfolio standards 
would require that the commission have foresight regarding the future that is 
superior to the foresight of market participants, and such standards could 
result in great expense if the commission's foresight is flawed. In large part, 
market participants' expectations regarding future fuel price risk are affected 
by the regulation of fuel costs. 
Rather than adopting portfolio standards to mitigate these risks, the commission 
intends to focus on the impact of existing regulatory processes on fuel price 
risk. For instance, the application of a fixed fuel factor made sense during a 
period of fuel price instability. To the extent that the conditions of the 1970s 
and early 1980s no longer exist, a re-examination of regulatory policy may be 
appropriate. Elimination of a fixed fuel factor may allow market participants to 
act in a more socially-beneficial manner with respect to fuel price risk 
mitigation. As part of the process of allowing markets to function the 
commission may examine its rate-setting processes to ensure that all resources 
are treated in a similar manner. It appears that a high capital cost resource 
with no fuel price risk (like a renewable resource) does not receive the same 
regulatory treatment as a moderate capital cost, moderate fuel cost resource 
(such as a combustion turbine). Future fuel costs account for approximately one-
half the total cost of a combustion turbine, and such costs are not known with 
certainty. In this regard, a re- examination of the fuel factor within the 
context of Project Number 15000 will help the commission to determine whether 
risk-takers are appropriately motivated by regulations. If they are not, the 
regulations should be amended so that markets are not inhibited. The IRP rule 
proposal is appropriate because it contains general language regarding risk 
mitigation, and because it will allow utilities to rely on financial markets. 
More explicit language regarding risk analysis or portfolio standards might 
inhibit the development of markets. 
In the preamble, the commission noted that the proposed regulations require 
utilities to report on their low-income and tenant DSM activities, and provide 
utilities with an exclusion to the solicitation process. The commission also 
posed the following question: Is it appropriate for the commission to be more 
specific by rule? State Representative Hirschi stated that these programs are 
important as a resource and for equity reasons. OPC stated that the IRP Rule 
should give more explicit direction to the utilities with regard to low-income 
and tenant DSM and that a utility's preliminary plan should specify how the 
utility will take impediments to implementing low-income and tenant DSM programs 
into account in the design of DSM programs. Gulf Cities supported the proposed 
language in sec.23.35(a)(2)(C) and sec.23.37(e)(3)(C) as it relates to demand-
side management program consideration and sees no need for the commission to be 
more specific by rule. 
TU Electric suggested that in the interest of streamlining the proposed rules, 
the commission should not include any additional requirements related to low-
income and tenants programs. The requirements in PURA are adequate to protect 
the interests of low-income and tenant customers. CSW stated that a definition 
of low-income and tenant should be provided in the rule, and the level of these 
DSM programs should be set equal to the revenue collected from customers wanting 
and willing to contribute to such services. HL & P stated that these programs 
are part of being a good corporate citizen and that the commission should not be 
more explicit by rule. GSU stated that rules inhibit flexibility. Utilities must 
evaluate the economics of low-income and tenant DSM programs if such are bid in 
the solicitation process, and the economic imperative of the competitive 
wholesale marketplace should be the driving force of the IRP process. SPS stated 
that the commission should only allow cost-effective demand-side management 
programs, and the commission should modify the language of 
sec.sec.23.35(a)(2)(C), 23.35(a)(2)(E), 23.37(c)(3) and 23.37(e)(3)(C) to 
indicate the use of cost-effective demand-side programs. TNP stated that the 
rules requiring low-income and tenant DSM should apply only if the affected 
communities agree to pay the costs of the programs. EPE stated that the proposed 
language would inhibit the development of a competitive market, and that social 
programs should be supported by surcharges on transmission or distribution 
services. BEPC stated that customers should not have to subsidize a program in 
their rates if the subsidization will cause their rates to be non-competitive. 
This subsidization would represent a societal benefit which is inconsistent with 
the concept of a functioning competitive market. STEC stated that the low-income 
provisions are appropriately crafted. NAESCO discussed a variety of issues 
related to a non-bypassable charge for the delivery of energy efficiency 
services. Mr. Shapiro stated that utilities may enter into a contract with 
rental property owners, and that utilities should be allowed to capitalize these 
expenses. The LLI believes that the provisions regarding low-income ratepayers 
and renters outlined in the proposed rule are critical to ensuring that this 
major customer segment takes its rightful place in the regulatory process. 
Public Citizen submitted that the statute clearly indicates that utilities are 
to have special programs for tenants and low-income consumers. Consumers Union 
stated that PURA requires utilities to achieve equity among customer classes in 
its DSM programs, including the tenant and low-income segments of the 
residential class. Unless the IRP specifically addresses the needs of renters 
and low-income consumers, such customers will disproportionately bear the costs 
of DSM programs compared to the benefits of energy conservation. EDF supported 
this provision. TIEC stated that no additional specificity is necessary. Texas 
Rose stated that the commission should coordinate with DOE's Weatherization 
Program, and the commission should define equity for the purpose of determining 
whether a utility's plan will adequately achieve equity among customer classes 
and provide demand side programs to each customer class. Texas Rose argues that 
a minimum level of expenditure should be established to define equitable low 
income and renter demand-side programs. The commission received thirty-six 
letters of support for the provisions regarding low- income ratepayers and 
renters from twenty-four organizations currently active in low- income 
weatherization projects. One letter included an attachment with 150 signatures 
of support. Several individuals also filed letters of support. The commission 
also received a signed petition with approximately 5,000 signatures in support 
of the proposed rule. 
The commission adopts the proposal as published and rejects the suggestions that 
the rule should be more specific, or that the rule should set forth specific 
expenditures for low-income and tenant DSM programs. The commission has 
established a process that will rely on the input of customers to assist the 
commission in determining what level of funding may be appropriate for such 
programs in a service area. The funding mechanism will be set on a case-by-case 
basis, and may be affected by future decisions related to system benefits 
charges. The commission rejects the arguments that such programs are necessarily 
cross-subsidies, and that such programs must be voluntarily funded. The statute 
requires that utilities and the commission consider the equity impacts of 
resource additions, and that utilities ensure that DSM programs are provided to 
all customer classes, including low-income ratepayers. The commission believes 
that the published proposal will help enforce this statutory directive. 
In the preamble, the commission posed the following question: Is the proposed 
limit on cost recovery for a new generating unit appropriate policy? OPC stated 
that it is absolutely essential that a utility be held to its bid in a 
solicitation. Gulf Cities supported the concept of limiting cost recovery for 
new generation to the cost estimate prepared by the utility at the time it 
conducts a solicitation under sec.23.36. Steering Cities stated that the 
commission lacks the authority to inflate the cost basis on which the utility is 
entitled to earn a return. TU Electric and HL & P stated that the commission has 
no authority for such a mechanism. CSW expressed the view that if a cost cap is 
imposed, the utility should be able to fully benefit from the cost "under-runs." 
GSU states that imposing a prescriptive set of rules places utilities on a 
disadvantageous competitive footing. EPE stated that the utility must be allowed 
to recover additional costs that arise out of changing circumstances. EPE stated 
that a utility should be allowed to recover its cost estimate even when a 
generation project comes in under budget. SPS recommended that in proposed 
sec.23.31(c)(10)(C)(ii) the commission should issue a certificate for the 
utility's plant when it meets all certification criteria and the utility agrees 
to the least-cost resource cap. TNP supported consistent application of cost-
limitation guidelines to utilities and other resource providers. STEC stated 
that the PURA does not empower the commission to limit cost recovery as 
proposed. Enron stated that comparable treatment of build versus buy options 
requires a limitation on the ability of utilities to pass through cost 
increases. Good Company supported cost caps so that utilities are held to their 
bid. Mr. Shapiro supported holding utilities and third-party bidders to the same 
standards. Destec encouraged the commission to hold the utility or affiliates to 
their bid. Public Citizen supported the proposed rule limiting the cost of new 
plants and urged the commission to expand its rules to include cancellation of a 
certificate if it is no longer the lowest cost resource. Consumers Union 
submitted that limiting capital costs that may be included in base rates 
pursuant to sec.23.31 is not permitted under PURA. Consumers Union opined that 
in practical terms the cost cap will be a one-way street because utilities will 
keep the profits if savings are achieved, but if there are cost over-runs 
utilities will make constitutional and financial integrity arguments that 
ratepayers must pay for the over-runs. TPGA stated that it supports cost caps 
for utility bids. EDF stated that cost cap mechanisms should be explicit and 
without loopholes. TREIA stated that utilities should not be granted special 
privileges over their competitors. TIEC stated that the commission should impose 
cost caps for resources that are constructed by a utility pursuant to receiving 
a certificate. Texas Rose stated that cost caps and related issues of cost 
recovery and incentives should be explored in a separate rulemaking. BEPC stated 
that the commission should not limit a cooperative's cost recovery for a new 
generating unit. 
The commission is on record as favoring market-based contracts for power and 
disfavoring additional power plants in rate base. The commission rejects the 
cost cap proposal. The commission instead adopts a final rule that supports a 
rebuttable presumption that the prudently-incurred costs of a certified power 
plant would be limited in a prudence proceeding by the costs of the rejected 
bids in the utility's most recent resource solicitation, or by the costs of the 
utility's own bid into that solicitation, if the utility chose to submit a bid 
for a rate-based plant addition. In circumstances where a utility declines to 
bid a rate-based plant addition in its IRP solicitation and then seeks to obtain 
plant certification after rejecting all third-party solicitation bids, the 
commission believes it is reasonable to consider whether there is a reasonable 
likelihood that a new solicitation would result in lower-cost and higher quality 
bids that would better serve the public interest than the proposed generating 
unit. The commission adopts new standards for power plant certification in this 
new competitive environment. The ability of a utility to reject all bids and to 
then request a certificate for a power plant that was never bid into its IRP 
solicitation may discourage bidding in a solicitation, and some third party 
providers may never come to Texas to bid. New certification standards will place 
utilities on a level playing field with third-party suppliers and reduce the 
opportunities for gaming. Under these new standards the commission will consider 
the reasonableness of the solicitation process conducted by the utility and the 
opportunities to conduct a new solicitation. 
In addition to the fifteen major issues, the commission considered many issues 
in adopting the specific rule amendments. 
In adopting new definitions in sec.23.3 the commission agrees with TU Electric 
that a definition of supply-side resource is reasonable and appropriate. In 
adopting changes to sec.23.13(c) relating to statistical reports for electric 
utilities the commission agrees with the parties who urge amendment, not repeal, 
of this subsection. The commission has recently adopted rules that require 
electric utilities to report their loads and resources to the independent system 
operator of the Electric Reliability Council of Texas. It is appropriate to 
require the filing of these documents with the commission so that all parties 
may review the likely future capacity needs in Texas. The commission agrees with 
the parties who recommended deferral of consideration of current cost recovery, 
mark-ups, and incentive rules. Specifically, the proposed cost-of-service rules, 
sec.23.21(g), relating to the treatment of integrated resource plan costs shall 
not be amended at this time as they relate to such factors and incentives. Also, 
the commission will not adopt amendments to sec.23.23(e), relating to timely 
cost recovery and incentives. The commission directs the staff to continue its 
consideration of these matters in its preparation of a report on the scope of 
competition, Project Number 15000, and in Project Number 15485, Alternative 
Rate-Making Treatments for Fuel Cost Recovery. The commission may propose rules 
relating to current cost recovery, fuel factors, or performance-based ratemaking 
upon the conclusion of these projects, or may present recommendations for 
statutory reform of regulatory incentives to the Legislature, as appropriate. 
With regard to the reimbursement of the expenses of municipalities, investor- 
owned utilities argued against reimbursement for rulemaking expenses and stated 
that the language in PURA is intended to reimburse municipalities for their 
participation in IRP proceedings. BEPC stated that if a utility is required to 
reimburse a municipality, the utility should be allowed to surcharge the 
consumers within that city. STEC stated that the statute intended to limit 
recovery of expenses to individual utility IRP proceedings, but acknowledged a 
broader reading of the statute and requested that the costs incurred by a city 
be borne solely by the utility providing service to the city. EDF stated that 
reimbursement of cities' expenses for IRP is clearly the intent of the 
legislature. Texas Rose stated that the commission should permit cities to be 
reimbursed for expenses associated with their participation in this rulemaking. 
Gulf Cities supported the proposal. 
The commission adopts the rule amendment relating to utility reimbursement of 
the expenses of municipalities for participation in individual IRP cases. A 
related issue is reimbursement of utility expenses for participation in this 
rulemaking. The commission has decided to reimburse municipalities for such 
participation. (Docket Number 15166, Application of General Counsel for 
Declaratory Order Determination Related to Reimbursing Municipalities for 
Participating in IRP Rulemaking.) 
The commission proposed the repeal of sec.23.22, Energy Efficiency Plan. Several 
parties recommended the amendment, not the repeal, of the rule because of the 
importance of monitoring the DSM activities of the state's electric utilities. 
The commission concludes that it is premature to repeal sec.23.22 at this time. 
Rather, the commission directs staff to draft a rule proposal relating to the 
development of annual reporting rules for promotional DSM programs, rebates, and 
rate designs. In that rulemaking proceeding the commission will focus the Energy 
Efficiency Plan rule on the reporting requirements necessary to mitigate the 
potential for anti-competitive abuses in the energy services market. While the 
commission is not repealing sec.23.22 at this time, the commission wishes to 
avoid imposing duplicative filing requirements. Therefore, any information 
submitted to the commission by utilities as part of their individual IRP filings 
need not be duplicated in their energy efficiency plan filings. 
One matter related to energy efficiency is the efficient operation of existing 
generating units. Gulf Cities, Texas Rose, EDF, Public Citizen, Consumers Union, 
and LLI stated that the refurbishing or repowering of an existing power plant 
should require a resource solicitation or a new certificate. Utilities argued 
that such investments are often made as part of the ongoing work of electric 
utilities, and that these activities are not part of an IRP review. In related 
comments, some parties stated that the commission should calculate the avoided 
costs of each utility so that bidders would have knowledge of what would 
constitute a winning bid. This calculation could include the ongoing costs of 
maintaining existing generating units so that third-party bidders could attempt 
to displace the high-cost power plants. The definition of the terms 
"refurbishing" or "repowering" is difficult; however, the key issue relates to 
the uneconomic expenditure of funds, not the particular term used for resources. 
The IRP process requires that the commission look broadly at the kinds of 
resources that are appropriate. The commission concludes that it is appropriate 
to carefully examine the maintenance and capital costs associated with existing 
generating units. This scrutiny will allow detection of inefficient investments 
and will accelerate the application of market forces in the generation sector. 
This scrutiny will not be accomplished in the IRP filing but will be based on 
updated reporting requirements to be considered in the context of the revisiting 
of sec.23.22, the energy efficiency plan rule. The commission concludes that it 
is inappropriate to rely on prior administrative determinations of the utility's 
avoided costs in determining whether such utility activities are reasonable, 
because the market will reveal the utility's current avoided costs through a 
bidding process. Since 1992, the commission has required a competitive resource 
solicitation based upon the belief that the winning bid determines the avoided 
cost, and that administratively-determined avoided costs are no longer useful. 
The PURA contains italicized language relating to the issuance of a power plant 
notice of intent or a certificate of convenience and necessity prior to the 
approval of a utility's IRP. The proposed amendments to sec.23.31, Certification 
Criteria, clarify this transition period. 
Consistent with Legislative policy to encourage the development of wholesale 
competition, the commission is on record as favoring market-based contracts for 
power and disfavoring additional power plants in traditional rate base. Market-
based contracts for resources are acquired in competitive markets; in contrast, 
a power plant certificate is acquired after an administrative review. The 
commission's amendments to sec.23.31 are consistent with the italicized 
language. The commission is interested in exhausting all cost-effective 
alternatives to power plant certification because that will lower costs to 
consumers. The administrative review and licensing of utility power plants no 
longer appears appropriate in light of the opportunities available in wholesale 
markets under a fair solicitation process. 
The proposed amendments to sec.23.31(c)(2)(I), Certification Criteria, addressed 
the exemption of certain renewable resource facilities from certification. The 
proposal anticipated that such exemptions would be appropriate if the generating 
unit output were less that ten megawatts average annual energy. In practical 
terms, that would be equivalent to the output of a 40-megawatt wind farm. The 
parties' comments on this issue diverged widely. Those supporting the exemption 
argued that these resources require less regulation. Those opposing the 
exemption cautioned the commission from ignoring its duties under the PURA. It 
was also pointed out that the exemption might apply to non-utility parties that 
seek retail access. 
The commission is very interested in meeting its obligation regarding the 
encouragement of renewable resources. The commission is also aware of its 
obligations relating to the public interest findings for certification contained 
in sec.23.31. Therefore, the commission finds that the blanket approval of 
renewable resource projects is not acceptable. The commission finds that it is 
appropriate to allow smaller-scale renewable resources, such as distributed 
resources, to be exempt from certification. Distributed resources may be 
acquired from unaffiliated entities by investor-owned utilities outside the 
solicitation process pursuant to PURA, sec.2.051(x)(5). A distributed resource 
that exclusively relies on a renewable energy technology will be small (less 
than ten megawatts installed capacity), will be near customers with whom the 
utility is working, will defer the upgrading of distribution facilities, and 
will be environmentally benign. Thus PURA, sec.2.051(x)(5), relating to the 
acquisition of renewable distributed resource outside the solicitation process, 
supports sec.2.051(v), relating to the encouragement of renewable resource 
technologies. The commission encourages utilities to pursue such projects. 
TEC noted that proposed sec.23.34(b)(3) suffers from a number of defects. TEC 
stated that rules should clearly identify whether any portions of sec.23.34 and 
sec.23.35 apply to non-generating utilities that seek to purchase 25 % of their 
need or 70 megawatts of capacity. TEC stated that if the non-solicitation 
portions of sec.23.36 and sec.23.37 do not apply to cooperatives, it should be 
clearly stated. TEC objected to the additional restriction against purchases 
from affiliated power suppliers, stating that it is contrary to law, and 
objected to the provision to permit the commission to conduct a hearing. TEC 
stated that the paragraph does not provide standards for the conduct of the 
solicitation. TEC stated that other non-generating utilities are exempt from 
IRP, and that paragraph sec.23.34(b)(6) is inconsistent with the statute. 
Finally, TEC stated that the last sentence in paragraph (6) requiring 
cooperation with wholesale suppliers should be limited to providing information 
about forecasts of loads. 
The commission takes the comments of TEC into account in making changes to the 
referenced paragraphs. The standards of the resource solicitation process should 
apply broadly, regardless of whether an electric utility is required to file a 
preliminary plan. The commission, in determining whether to certify a 
distribution cooperative's contract for resources, shall consider the standards 
it has established for the resource solicitation process. In determining whether 
to certify a contract for resources, the commission will need to determine 
whether the resource solicitation was conducted in a fair manner and whether the 
cooperative used open, transparent bidding procedures. The solicitation 
standards set forth in these rule amendments will drive the commission's 
decision. All utilities in Texas should take note of the intent of these 
regulations. 
The commission also considered the statutory requirements relating to the 
capabilities of large and small utilities (sec.2.051(d)) as it prepared the 
preliminary plan filing requirements and other aspects of the rules. One matter 
relating to public participation not discussed elsewhere is the use of computer 
resources to assist the customers of the utility in making decisions. SPS 
strongly disagreed with the use of its computer resources by members of the 
working group as envisioned in sec.23.34(f)(2)(B). Others, notably Texas Rose 
and Gulf Cities, argued that this information is critical to the process. 
The commission rejects the proposed rule relating to the use of computer 
resources. The use of computers to assist the customers of the utility may be an 
important aspect of the public participation process, but the commission 
believes that each utility must work out the details of public participation in 
a manner that it sees fit. The commission will review the public participation 
process as part of its consideration of the preliminary plan. 
One matter upon which the commission deliberated is the type of bidding process 
that utilities must employ in a resource solicitation. Some parties advocated an 
all-source process, in which all bidders would compete against each other. 
Others pointed out that all-source bidding would result in the purchase of the 
cheapest resources, and other goals relating to the diversity of the resources 
mix and environmental protection would not be given significant weight. These 
parties preferred a targeted or segmented bidding process that would allow the 
utility to plan its resource needs and then target the resource solicitation to 
the types of resources that would meet that need. The market would be relied 
upon, but different resource types would be treated separately. Consumers Union 
submitted that the all-source bidding proposal in sec.23.34(i)(1) is in inherent 
conflict with the Legislature's goal of diversity of resources. LCRA proposed to 
alter sec.23.34(i) to allow IRP solicitation to be targeted according to the 
provisions of each individual utility's preliminary plan without the utility 
having to show good cause for not issuing an all-source bid solicitation. 
Certain parties urged the commission to reject special treatment for particular 
resources in the belief that the commission must make a simple choice between 
favorable treatment for particular resources and equal treatment for all 
resources. It appears however, that the existing regulatory scheme may result in 
biases for certain resources and against other resources. It is commonly 
asserted, for example, that cost-of-service ratemaking creates an incentive for 
the utility to select capital-intensive resources in what is referred to as the 
Averch-Johnson effect. It may also be the case that the current rate treatment 
of fuel expenses through the fixed fuel factor significantly reduces the risks 
that utilities bear in connection with a fuel-consuming resource. These two 
effects may bias utilities toward capital-intensive, fuel-consuming resources, 
such as traditional power plants, and away from resources which do not have 
these characteristics. One of the purposes of IRP is to create a regulatory 
scheme in which these institutional biases are minimized. The all-source 
solicitation requirement addresses this concern, in part, by creating an 
opportunity for customers and energy service companies to make market- based 
proposals. However, even with all-source bidding, biases inherent in traditional 
ratemaking may persist. The commission concludes that it is best to set forth an 
all-source solicitation process with a good cause exception. In that manner, the 
commission can rely on the views of customers to help the utility determine 
whether targeted bidding might be requested for certain resources. As noted 
earlier, the commission is examining reforms to traditional rate-setting in 
Project Number 15000. 
The statute directs the commission to allow utilities to acquire certain 
resources outside the formal solicitation process. The commission addressed this 
provision in sec.23.34(j) of the new rule. In adopting a final rule, the 
commission considered the need for clarification of some of the terminology 
contained in the statute. 
Several utilities identified filing requirements in sec.23.35(a) that are not 
included in the filing requirements of PURA, sec.2.051(f). These parties stated 
that for this reason these requirements should not be included in the rules. The 
commission has not exceeded its authority because sec.2.051(f)(10) gives the 
commission specific authority to require any information that the commission 
needs in reviewing the preliminary plan. 
In addressing the issue of appropriate filing requirements, the commission 
considered the needs of small-scale resource providers. Many of the resource 
providers, including renewable resources suppliers and energy service providers, 
will be unable to submit bids in utility resource solicitations, either because 
of the cost of bidding or because of size restrictions on the bid. The 
commission has rejected a requirement for set- asides for these resources. 
Instead, the commission believes that there will be opportunities for small-
scale resource providers to work directly with customers or with utilities if 
barriers are removed or reduced. Many such barriers are regulatory; the lack of 
tariff options to some customer classes reduces or eliminates the ability of 
customers to pick those energy services they desire without paying for services 
they do not desire. The commission has addressed this issue in several ways: 
first, by requiring the functional separation of the distribution operations of 
certain utilities; second, by requiring public utilities to consider a broader 
menu of energy service and pricing options for all classes of customers; and 
third, by requiring utilities to report on their activities relating to 
renewable resource technologies. By requiring the reporting of this information 
the commission and the utilities can begin to eliminate barriers to on-site 
application of these resources. 
TEC remarked that the requirement to provide information to customers regarding 
alternatives to line extensions pursuant to sec.23.44(c)(3) would impose an 
unnecessary burden on utilities. TEC asked that the commission allow utilities 
to exercise judgment regarding when the alternatives will be economical. The 
commission believes it is appropriate to insure that utilities provide renewable 
resource technology information to customers so that both customers and 
utilities can become more knowledgeable in evaluating the available alternatives 
to line extensions. This informational requirement is limited to those 
circumstances where the information provided will allow the customer to identify 
the most cost-effective choice between the application of on-site renewable 
resources, DSM or a line extension. The commission believes that proper choices 
in these circumstances can lower the cost of providing electric service, both to 
the customer and to the utility system. The commission adopts the paragraph with 
minor changes. 

General Rules
16 TAC sec.23.3
The amendment is adopted under the Public Utility Regulatory Act of 1995, 
sec.sec.1.101, 2.051, and 2.216, Texas Civil Statutes, Article 1446c-0, 
sec.sec.1.101, 2.051, 2.216. Section 1.101 provides the commission with the 
authority to make and enforce rules reasonably required in the exercise of its 
powers and jurisdiction; sec.2.051, requires the commission to adopt integrated 
resource planning regulations by September 1, 1996; and sec.2.216, prohibits 
public utilities from engaging in anti-competitive behavior.

sec.23.3.Definitions.
The following words and terms, when used in this chapter, shall have the 
following meanings, unless the context clearly indicates otherwise.
Demand-side management - Activities that affect the magnitude and/or timing of 
customer electricity usage to produce desirable changes in the utility's load 
shape. 
Demand-side resource or demand-side management resource - Activities that result 
in reductions in electric generation capacity needs or reductions in energy 
usage or both.
Distributed resource - A generation, energy storage, or targeted demand-side 
resource, generally between one kilowatt and ten megawatts, located at a 
customer's site or near a load center, and connected at the distribution voltage 
level (60,000 volts and below), that provides geographic advantages to the 
system, such as deferring the need for upgrading local distribution facilities.
Renewable energy technology - Any technology that exclusively relies on an 
energy source that is naturally regenerated over a short time scale and derived 
directly from the sun (solar-thermal, photochemical, and photoelectric), 
indirectly from the sun (wind, hydropower, and biomass), or from other natural 
movements and mechanisms of the environment (geothermal and tidal energy). A 
renewable energy technology does not rely on energy resources derived from 
fossil fuels, waste products from fossil fuels, or waste products from inorganic 
sources.
Supply-side resource - A resource, including a storage device, that provides 
electricity from fuels (e.g., nuclear, fossil) or from renewable resources 
(e.g., solar, wind, biomass). 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority.
Issued in Austin, Texas, on July 8, 1996.
TRD-9609760
Paula Mueller
Secretary of the Commission
Public Utility Commission of Texas
Effective date: July 29, 1996
Proposal publication date: January 19, 1996
For further information, please call: (512) 458-0100

Records and Reports
16 TAC sec.23.13
The amendment is adopted under the Public Utility Regulatory Act of 1995, 
sec.sec.1.101, 2.051, and 2.216, Texas Civil Statutes, Article 1446c-0, 
sec.sec.1.101, 2.051, 2.216. Section 1.101 provides the commission with the 
authority to make and enforce rules reasonably required in the exercise of its 
powers and jurisdiction; sec.2.051, requires the commission to adopt integrated 
resource planning regulations by September 1, 1996; and sec.2.216, prohibits 
public utilities from engaging in anti- competitive behavior.

sec.23.13.Statistical Reports.
(a)-(b) (No change.) 
(c) Electric utilities. Each electric utility that submits an annual report of 
loads and resources to the Electric Reliability Council of Texas independent 
system operator pursuant to sec.23.70(e) of this title (relating to Terms and 
Conditions of Open-access Comparable Transmission Service) or other reliability 
council shall file a copy with the commission and maintain a copy of supporting 
documentation for five years. If no such annual report is prepared, the utility 
shall maintain a record of the load and resource documents prepared in the 
normal course of its activities for five years. 
(d) Telephone utilities. Each dominant certificated utility shall submit 
annually an access line report as part of its annual earnings report. 
(e) Other statistical reports. Other reports shall be filed as requested by the 
commission. Other reports may include, but are not limited to, customer class 
credit risk analyses, appliance saturation and energy use studies, and special 
cost of service-related studies. 
(f) Infrastructure Reports: Each incumbent local exchange company (LEC) that 
elects incentive regulation under the subtitles "H" or "I" of the Public Utility 
Regulatory Act (PURA 95 or "the Act") shall file an infrastructure report with 
the commission each year on the anniversary date of its election. One copy of 
the report must be filed as a hard copy, and one copy must be filed in an 
electronic format. The report must include sufficient information to ensure 
compliance with the requirements of sec.sec.3.358, 3.359, and 3.403 of the Act. 
At a minimum, the report must include the following information:
(1) End-to-end digital connectivity. 
(A) Percent and total number of access lines that have end-to-end digital 
connectivity available. Also, total number of lines that were upgraded to end-
to-end digital connectivity during the previous year and cumulative for the 
period since election. This information shall be provided for each wire center 
or central office, identified by name and Common Language Location 
Identification (CLLI) Code, and by class of customers (such as residential and 
business). 
(B) The associated investment and expense for the previous year and cumulative 
for the period since election. 
(C) The total number of equipped and active voice channels, number of channels 
on fiber optics, and number of channels on copper facilities. This information 
shall be provided for each wire center or central office, identified by name and 
CLLI Code. 
(2) New digital switch deployment. 
(A) Percent and total number of local exchange access lines served by digital 
switching facilities. Also, total number of lines that were served by new 
digital switching equipment during the previous year and cumulative for the 
period since election. This information shall be provided for each wire center 
or central office, identified by name and CLLI Code. 
(B) Percent and total number of central offices equipped with digital switching 
facilities. Also, total number of central offices that were equipped with new 
digital switching equipment during the previous year and cumulative for the 
period since election. This information shall be provided for each wire center 
or central office, identified by name and CLLI Code.
(C) The associated investment and expense for the previous year and cumulative 
for the period since election. 
(D) The type, make, and quantity of switching equipment installed during the 
previous year. This information shall be provided for each wire center or 
central office, identified by name and CLLI Code. Also include actual 
installation and service dates of the switch along with a brief description of 
its functionalities and capabilities. 
(3) Inter-office broadband facilities (capable of transmitting at least 45 
megabits per second of digital information). 
(A) Percent and total number of inter-office facilities that use broadband 
facilities. Also, total number of inter-office facilities that were upgraded for 
broadband capability during the previous year and cumulative for the period 
since election. 
(B) Include schematic diagrams that indicate quantity (such as fiber sheath 
miles, and number of strands, number of DS-3 channels or optical channels, etc.) 
and relative location for each such facility, for the previous year. Also 
include installation and service dates for such facilities. 
(C) The associated investment and expense data for such facilities, for the 
previous year and cumulative for the period since election. 
(4) Common Channel Signaling System (SS-7) deployment.
(A) Percent and total number of central offices equipped with SS-7 capability. 
Also, total number of central offices that were equipped with SS-7 capability 
during the previous year and cumulative for the period since election. This 
information shall be provided for each wire center or central office, identified 
by name and CLLI Code. Also include actual installation and service dates of SS-
7 capability along with a brief description of its functionalities. 
(B) The associated investment and expense data for such facilities, for the 
previous year and cumulative for the period since election. 
(5) Fiber optic facilities to tandem central offices.
(A) Percent and number of serving central offices that have optical fiber 
facilities to their connecting tandem offices. Also, total number of serving 
central offices that were upgraded with fiber optic facilities to their 
respective tandem switching office during the previous year and cumulative for 
the period since election. 
(B) Include schematic diagrams that indicate quantity (such as fiber sheath 
miles, and number of strands, or number of DS-3 channels or optical channels 
etc.) and relative location of each such facility, for the previous year. Also 
include installation and service dates for those facilities. 
(C) The associated investment and expense data, for the previous year and 
cumulative for the period since election. 
(6) Infrastructure commitment to certain entities.
(A) Identify each entity, by name and type, that requests services provided 
under PURA sec.3.359 or sec.3.403, as applicable. Include the address and 
telephone number for each entity served. 
(B) For each entity identified in subparagraph (A) of this paragraph, list the 
date of each request and the actual installation and service dates. Also list 
the type of service(s) requested and actually provided, including quantity and 
location. Provide information that describes the functionalities and application 
of each type of service provided. 
(C) For each service provided to an entity under PURA sec.3.359 or sec.3.403, 
except for point-to-point intraLATA 1.544 megabits per second service offered at 
a flat monthly tariff rate under PURA sec.3.359(b)(1)(D), a customer specific 
contract shall be filed with the commission within 30 days of the execution of 
the contract. Information under this subparagraph need not be included in the 
annual report required by this subsection, although the annual report should 
refer the reader to this filing for specific data.
(7) A listing of exchanges with no digital presence as of September 1, 1995. 
Also, state which exchanges have been upgraded with digital service and the date 
put in service. The information required by this paragraph shall be provided in 
an electing company's initial report under this subsection, and is not required 
to be provided in subsequent reports.
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority.
Issued in Austin, Texas, on July 8, 1996.
TRD-9609761
Paula Mueller
Secretary of the Commission
Public Utility Commission of Texas
Effective date: July 29, 1996
Proposal publication date: January 19, 1996
For further information, please call: (512) 458-0100

Rates
16 TAC sec.23.21
The amendment is adopted under the Public Utility Regulatory Act of 1995, 
sec.sec.1.101, 2.051, and 2.216, Texas Civil Statutes, Article 1446c-0, 
sec.sec.1.101, 2.051, 2.216. Section 1.101 provides the commission with the 
authority to make and enforce rules reasonably required in the exercise of its 
powers and jurisdiction; sec.2.051, requires the commission to adopt integrated 
resource planning regulations by September 1, 1996; and sec.2.216, prohibits 
public utilities from engaging in anti- competitive behavior. 

sec.23.21.Cost of Service.
(a)-(f) (No change.) 
(g) Treatment of integrated resource plan costs. 
(1) Reimbursement of expenses of a municipality. If a public utility is required 
by the commission to reimburse a municipality for expenses the municipality 
incurred for its participation in a proceeding conducted under sec.sec.23.34-
23.37 of this title (relating to Integrated Resource Planning, Preliminary 
Integrated Resource Plan, Solicitation of Resources, and Approval of Resources 
Procured Through Solicitation), the commission shall, as part of its 
determination in sec.23.35 and sec.23.37 of this title, authorize a surcharge to 
be included in the public utility's rates over an appropriate period to recover 
the municipality's expenses for participating in the integrated resource plan 
proceeding. 
(2) Expenses of a utility related to integrated resource planning. The 
reasonable expenses of the public utility for public participation, planning, 
preparation, and participation in a proceeding conducted under sec.sec.23.34-
23.37 of this title may be recovered only after commission review has been 
conducted in accordance with the provisions of either sec.2.211 or sec.2.212 of 
the Act. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority.
Issued in Austin, Texas, on July 8, 1996.
TRD-9609762
Paula Mueller
Secretary of the Commission
Public Utility Commission of Texas
Effective date: July 29, 1996
Proposal publication date: January 19, 1996
For further information, please call: (512) 458-0100

Certification
16 TAC sec.23.31
The amendment is adopted under the Public Utility Regulatory Act of 1995, 
sec.sec.1.101, 2.051, and 2.216, Texas Civil Statutes, Article 1446c-0, 
sec.sec.1.101, 2.051, 2.216. Section 1.101 provides the commission with the 
authority to make and enforce rules reasonably required in the exercise of its 
powers and jurisdiction; sec.2.051, requires the commission to adopt integrated 
resource planning regulations by September 1, 1996; and sec.2.216, prohibits 
public utilities from engaging in anti-competitive behavior.

sec.23.31.Certification Criteria.
(a)-(b) (No change.) 
(c) Certificates of convenience and necessity for new service areas and 
facilities. Except for certificates granted under subsection (b) of this 
section, the commission may grant an application and issue a certificate only if 
it finds that the certificate is necessary for the service, accommodation, 
convenience, or safety of the public. In addition, to grant an application of an 
electric utility for a new generating unit, the commission must find that the 
proposed generating unit is the best and most economical choice of technology 
for the service area, that cost-effective conservation and cost-effective 
alternative energy sources cannot reasonably meet the need, and that, after 
conducting a resource solicitation, evaluating the bids, and conducting 
negotiations, the proposed generating unit is superior to such third- party 
offers. Certificates of convenience and necessity for new generating facilities 
pursuant to this section require a notice of intent unless the utility has filed 
a preliminary plan under sec.23.35 of this title (relating to Preliminary 
Integrated Resource Plan). This subsection does not apply to a certificate of 
convenience and necessity requested as part of the integrated resource planning 
process under of sec.23.37(f) of this title (relating to Approval of Resources 
Procured Through Solicitation). 
(1) The commission may issue a certificate as applied for, or refuse to issue 
it, or issue it for the construction of a portion of the contemplated system or 
facility or extension thereof, or for the partial exercise only of the right or 
privilege. The commission may amend or revoke any certificate issued under this 
section if it finds that the public convenience and necessity requires such 
amendment or revocation. A certificate, or certificate amendment, is required 
for the following: 
(A)-(E) (No change.) 
(2) A certificate is not required for the following:
(A)-(H) (No change.) 
(3)-(8) (No change.) 
(9) Paragraphs (5) - (8) of this subsection do not apply if the utility has 
filed a preliminary integrated resource plan under sec.23.35 of this title that 
contains a proposed resource solicitation. 
(10) To provide for the orderly transition to an integrated resource planning 
process and to avoid delays in the construction of generating facilities 
necessary to provide electric service, an integrated resource plan shall not be 
required prior to the issuance of a certificate of convenience and necessity for 
the construction of generating facilities if: 
(A) the commission has approved the utility's notice of intent prior to the 
effective date of this section; 
(B) the utility has conducted a solicitation for resources to meet the need 
identified in the utility's notice of intent in accordance with commission rules 
then in effect; and 
(C) the utility has submitted to the commission the results of the solicitation 
and an application for certification of facilities to meet the need identified 
in the utility's notice of intent. 
(11) If a utility conducts a solicitation, rejects all bids, and applies for a 
certificate for a new generating facility, the reported costs of the resource 
alternatives offered in the resource solicitation shall be considered by the 
commission at the time of certification and in any prudence proceeding to 
investigate the reasonable costs of the generating facility. There shall be a 
rebuttable presumption that such offers constitute a market-based assessment of 
the value of the certified generating facility in the context of any 
determination of the reasonable costs to be recovered by the utility. 
(d)-(i) (No change.) 
(j) Notice-of-intent applications for generating plants. A utility must file a 
notice- of-intent (NOI) application upon deciding that it should construct a new 
generating plant. 
(1) (No change.) 
(2) Commission review. The commission shall approve the NOI if it concludes that 
the proposed plant is feasible and reasonable and that the utility will conduct 
a fair and reasonable resource solicitation.
(3) Standards. In determining whether the proposed plant is feasible and 
reasonable and whether the utility will conduct a fair and reasonable resource 
solicitation, the commission shall apply the standards of sec.sec.23.34-23.36 of 
this title. 
(4)-(5) (No change.) 
(6) Applicability. This subsection shall no longer apply if a utility has filed 
a preliminary integrated resource plan under sec.23.35 of this title. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority.
Issued in Austin, Texas, on July 8, 1996.
TRD-9609763
Paula Mueller
Secretary of the Commission
Public Utility Commission of Texas
Effective date: July 29, 1996
Proposal publication date: January 19, 1996
For further information, please call: (512) 458-0100

16 TAC sec.sec.23.34-23.37
The new sections are adopted under the Public Utility Regulatory Act of 1995, 
sec.sec.1.101, 2.051, and 2.216, Texas Civil Statutes, Article 1446c-0, 
sec.sec.1.101, 2.051, 2.216. Section 1.101 provides the commission with the 
authority to make and enforce rules reasonably required in the exercise of its 
powers and jurisdiction; sec.2.051, requires the commission to adopt integrated 
resource planning regulations by September 1, 1996; and sec.2.216, prohibits 
public utilities from engaging in anti- competitive behavior.

sec.23.34.Integrated Resource Planning.
(a) Purpose. The commission's regulation of utility resource planning and 
procurement is intended to ensure that utilities provide reliable energy service 
at the lowest reasonable system cost. The integrated resource planning process 
can advance the transition to a more competitive marketplace by aligning the 
utility's interest more closely with its customers. Utilities shall determine 
customer preferences with regard to planning options, consider all of the 
attributes of a broad range of resources that affect the supply or demand for 
electricity, procure resources based upon a fair and reasonable evaluation of 
the costs and attributes of resources that may be obtained in a market, and 
negotiate contracts that appropriately allocate risk. The development of a 
competitive wholesale electric market that allows for increased participation by 
both utilities and certain non- utilities is in the public interest. Nothing in 
the integrated resource planning process shall inhibit the development of 
competitive markets for electric power or for energy services. 
(b) Application. The requirements of this section and sec.sec.23.35-23.37 of 
this title (relating to Preliminary Integrated Resource Plan, Solicitation of 
Resources, and Approval of Resources Procured Through Solicitation) apply as 
specified in this subsection. 
(1) Generating public utilities are subject to the requirements of this section 
and sec.sec.23.35-23.37 of this title. 
(2) Nongenerating public utilities planning to construct generating resources 
are subject to the requirements of this section and sec.sec.23.35-23.37 of this 
title. 
(3) A nongenerating public utility that seeks to purchase more than 25% of its 
peak demand or more than 70 megawatts during any three-year period is subject to 
the requirements of subsection (h), subsection (i)(1)-(2), and subsection (j) of 
this section; sec.23.36 of this title; and sec.23.37(a)(2), (b), (c)(1), (2)(B), 
(5)-(7), (d), (e)(1)-(2), (3)(A), (B)(ii)-(iii), (E)-(G) of this title, unless 
the purchase is from its current power supplier as allowed by subsection (j)(1) 
of this section. If requested by such a utility, the commission may conduct a 
public hearing to consider the reasonableness of any contract for resources, if 
it determines that such a hearing is necessary. The commission shall issue an 
order approving, modifying, or rejecting the contract for resources resulting 
from the solicitation within 90 days of the date that the application is filed 
with the commission. 
(4) Every three years, a municipally-owned utility shall submit to the 
commission a report containing all of the information required in a preliminary 
integrated resource plan under sec.23.35 of this title, but shall not otherwise 
be subject to the requirements of this section. 
(5) A river authority subject to sec.2.0012 of the Act is subject to the 
requirements of this section and sec.sec.23.35-23.37 of this title with respect 
to the area served by the river authority on January 1, 1975. 
(6) A public utility that is not otherwise subject to the requirements of this 
section or sec.sec.23.35-23.37 of this title shall provide information to and 
cooperate with its utility wholesale power suppliers to develop and implement a 
resource plan to the extent that such activities do not otherwise affect either 
utility's competitive strategy.
(c) Structure of integrated resource planning. The integrated resource planning 
process consists of the following steps and activities:
(1) Public participation and preparation of preliminary integrated resource 
plan. In accordance with this section, the public utility shall solicit the 
views of the public on resource planning matters and prepare a preliminary 
integrated resource plan. 
(2) Request for approval of preliminary integrated resource plan. In accordance 
with sec.23.35 of this title, the public utility shall file its preliminary 
integrated resource plan. If the preliminary plan contains a proposed resource 
solicitation, the commission shall issue an order on the preliminary plan, 
including the proposed solicitation, within 180 days. In each case, the 
commission shall establish a schedule that will permit it to enter an order in 
180 days or less. If the preliminary plan of an investor- owned utility does not 
contain a proposed resource solicitation, the commission shall issue a notice of 
the filing of the plan. 
(3) Solicitation. In accordance with sec.23.36 of this title, the public utility 
shall conduct a resource solicitation. The utility shall evaluate the bids and 
select the best resources consistent with the approved preliminary plan, if any. 
(4) Approval of resources procured through solicitation. If the public utility 
has selected resources pursuant to a solicitation in accordance with sec.23.36 
of this title, it may request commission certification of the contracts under 
sec.23.37 of this title. In accordance with sec.23.37 of this title, the utility 
shall file its final plan. The commission shall issue a final order on the final 
plan within 180 days. In each case, the commission shall establish a schedule 
that will permit it to enter an order in 180 days or less. If a utility is 
filing pursuant to subsection (b)(3) of this section, the commission shall issue 
a final order within 90 days. If the utility plans to acquire additional 
generating facilities that require an amendment of its certificate of 
convenience and necessity, the utility shall apply for such an amendment, in 
accordance with subsection (f) of sec.23.37 of this title. 
(d) Staggered schedule. In October 1996 and no less frequently than every two 
years thereafter, the commission shall adopt a staggered schedule for the filing 
of preliminary integrated resource plans by electric utilities. The schedule 
will set forth the name of each electric utility affected by this section and 
sec.sec.23.35-23.37 of this title, and the date on which each utility shall file 
its preliminary plan. 
(e) Filing requirements. In October 1996 and no less frequently than every two 
years thereafter, the commission shall adopt forms for preliminary and final 
integrated resource plans. The forms shall reflect the differences in 
capabilities of small and large utilities, and of utilities with different 
structures and patterns of ownership. Electric utilities that provide service 
that is subject to rate regulation by a federal agency or an agency of another 
state shall file any information required in this section or sec.sec.23.35-23.37 
of this title separately identifying information for Texas-only operations and 
for total system operations. Upon a showing of good cause, a utility that is 
subject to resource planning requirements of a federal agency or an agency of 
another state may file all or part of its integrated resource plan in a format 
required by the federal agency, the regulatory agency of another state, or a 
regional planning agency. 
(f) Public participation. Public participation in resource planning matters is 
an essential part of integrated resource planning. The public utility shall 
consider the views of the public in preparing integrated resource plans, and 
shall reflect such views in any preliminary plan, regardless of whether such 
plan includes a proposed solicitation. 
(1) Purpose. The purpose of public participation is to educate the public on 
resource planning issues and the utility's planning activities, and to obtain 
the non-technical guidance of the public on planning matters, including the 
values and preferences of customers. It is not the purpose of public 
participation to establish a quasi-judicial group with authority over resource 
planning matters. 
(2) Process. Public utilities may decide how to conduct public participation in 
their service areas subject to the requirements of this subsection and may limit 
direct participation to its customers. The utility shall ensure fair 
representation of residential, commercial, and industrial customers, 
municipalities, and the geographic areas in its service territory in the public 
participation process. The utility shall include in its preliminary plan a 
description of how it has achieved fair representation in selecting the 
participants. The utility may request the involvement of the commission or its 
staff in the public participation process. 
(3) Record. The utility is responsible for maintaining a comprehensive record of 
its public participation activities for a period of five years. 
(4) Standards. Public participation requires two-way communication, and the 
utility shall facilitate the presentation of information from a broad range of 
perspectives to the participants, including the views of competitors and other 
non-customers. At a minimum, the utility shall obtain sufficient information 
from the participants regarding the values and preferences of its customers to 
allow the utility to incorporate those views in the preliminary plan. 
Specifically, the utility shall consider the views of the participants in 
determining: 
(A) the resource selection criteria and specific weights to be applied in the 
proposed resource solicitation, if any; 
(B) the ongoing strategies of the utility to achieve the lowest reasonable 
system cost for its service area; 
(C) whether targeted bidding may be justified in order to obtain an appropriate 
and reliable mix of resources; 
(D) an appropriate resource mix for the utility; and 
(E) limits, including upper bounds of costs and capacity, relating to an annual 
demand-side resource solicitation, if any. 
(5) Information. 
(A) The utility shall make available for review at no cost to the public at 
large at convenient locations in its service area, a copy of the most recent 
resource plan and a copy of the orders of the commission concerning the plan. 
The utility shall make available to any individual making a request a copy of 
the executive summary of its most recent resource plan.
(B) Prior to distributing informational materials to the participants under this 
subsection, the utility shall make the materials planned for distribution 
available to the commission staff and to the public at large, including 
competitors and other non-customers who may address the participants, and the 
utility shall accept comments on the content of the materials. 
(C) The utility shall provide information to the participants regarding the 
operating cost, environmental or community impacts, planned capital additions 
(e.g., repowering or refurbishment), potential for productivity and efficiency 
improvements, and expected remaining life of existing generating units 
(including life extension or early retirement options), and an estimate of the 
reasonable range of direct and indirect costs, including the bill impacts and 
risks, of these and alternative supply-side resources. The utility shall provide 
information to the participants regarding existing resources, existing customer 
services, demand-side management programs, and energy service and pricing 
options, and a reasonable range of costs for providing new demand-side 
resources, programs, and services. The utility shall provide information to the 
participants regarding the resource mix and the role of demand-side resource 
solicitations in meeting both capacity and customer service needs. In addition, 
the utility shall provide information related to its existing resources which 
enables the participants to compare such resources to currently available 
options and to select an appropriate resources mix. 
(6) Notice. At least every three years, each utility shall provide reasonable 
notice regarding the opportunities for customers and non-customers to become 
involved in the public participation process. Such notice shall describe the 
process, shall indicate how to obtain a schedule of events, and shall include: 
(A) notice by mail to the secretary of the commission, the Office of Public 
Utility Counsel, and the governing bodies of municipalities in the utility's 
service area; 
(B) direct notice to persons who submitted to the commission a request that the 
utility notify them of resource planning matters; and
(C) notice by publication in the service area. 
(7) Good cause exception. The commission may grant a good cause exception to any 
of the public participation requirements of this subsection for utility public 
participation efforts that were completed or were in progress by the effective 
date of this section. In evaluating requests for good cause exceptions under 
this paragraph, the commission shall consider whether the utility's public 
participation process was consistent with the purpose of public participation as 
prescribed in paragraph (1) of this subsection. 
(g) Lists of interested persons. The secretary of the commission shall maintain 
lists of interested persons as specified in this subsection. The secretary shall 
provide a copy of such lists upon request to any interested party. In 
implementing this subsection, the secretary may refer interested persons to 
comparable lists maintained by utilities. This subsection expires on September 
1, 2002. The secretary shall maintain lists of persons who have requested to be 
notified of: 
(1) resource planning matters, including opportunities for public participation 
and the filing of preliminary and final integrated resource plans. Persons 
requesting inclusion on such lists must state in writing their name and address 
and the name of the utility in which they have an interest;
(2) the issuance of any request for proposals for resources in Texas; and 
(3) the issuance of any request for qualifications for independent bid 
evaluators. 
(h) Lowest reasonable system cost. In determining the lowest reasonable system 
cost of an electric utility's plan, the commission shall consider in addition to 
direct costs the following: 
(1) the effect on the rates and bills of various types of customers;
(2) minimization of the risks of future fuel costs and regulations; 
(3) the appropriateness and reliability of the mix of resources; an appropriate 
and reliable mix of resources may include a portfolio of cost-effective sources 
of power including but not limited to resources that are fueled and non-fueled, 
such as renewable resources and conservation measures and a mixture of long-term 
and short-term contracts; and 
(4) the costs of compliance with the environmental protection requirements of 
all applicable state and federal laws, rules, and orders.
(i) General guidelines for evaluating and selecting resources. The commission 
finds that the development of a competitive wholesale electric market that 
allows for increased participation by both utilities and certain non-utilities 
is in the public interest. Existing markets are not fully open nor fully 
competitive; therefore, the commission finds that a formal solicitation process 
with regulatory oversight is appropriate. 
(1) All-source bidding. In formally soliciting bids, the utility shall use an 
all- source, integrated, demand-side and supply-side resource solicitation 
process. The all-source solicitation may include separate, parallel requests for 
proposals which are fully coordinated to meet the resource need, and which are 
integrated at the final stages of resource selection. The utility may conduct 
targeted solicitations upon a showing of good cause, and upon approval of the 
commission. The utility may conduct an ongoing annual demand-side resource 
solicitation, or other similar process, if the participants in its triennial 
public participation process support such an approach and have set limits, 
including upper bounds of costs and capacity, for such a solicitation or 
process, and if the commission approves the solicitation or process. 
(2) Quantification. In developing its specific resource selection criteria, the 
utility shall quantify, to the maximum reasonable extent, the factors it 
considers in evaluating resources. If available, the utility shall employ 
objective market valuations of environmental and other non-cost factors which 
influence its resource selection process, such as market valuations of tradable 
emissions allowances. Where appropriate, the utility may set forth a framework 
for the ranking and weighting of various factors that can not easily be 
quantified. 
(3) Resource selection criteria and weights. In developing its specific resource 
evaluation criteria and weights, the utility shall consider the lowest 
reasonable system cost, the characteristics of the resource need, the values and 
preferences of its customers, and the goals set forth in the most recently 
adopted statewide integrated resource plan. 
(j) Resources acquired outside the solicitation process. Consistent with the 
utility's most recent approved integrated resource planning goals, if any, the 
utility, including a nongenerating utility, may add new or incremental resources 
outside the solicitation process. The addition of new or incremental resources 
by a utility under this subsection does not require an amendment to the 
utility's integrated resource plan. The utility shall acquire such resources 
under contract, and the utility shall put in place accounting procedures that 
allow the tracking of the costs of such resources. An electric cooperative may 
acquire such resources directly or in coordination with another electric 
cooperative. Except as provided for in the previous sentence, a public utility 
may not acquire a resource under this subsection from an affiliate of the 
utility, except that the resources cited under paragraphs (6) and (7) of this 
subsection may be provided by the utility. The acquisition of a resource outside 
the solicitation process under paragraphs (1)-(3) and (5)-(6) of this subsection 
does not relieve the utility of its responsibility to demonstrate in an 
appropriate forum that such resources are preferable to the alternatives that 
would have been available through a resource solicitation. Resources may be 
acquired outside the solicitation process only in the following circumstances: 
(1) contract renegotiation for existing capacity; 
(2) demand-side management resources or resources powered by renewable energy 
technologies; 
(3) capacity purchases with a term of two years or less;
(4) capacity purchases necessary to satisfy unanticipated emergency conditions; 
(5) the exercise of an option in a purchased power contract;
(6) distributed resources powered by renewable resource technologies located at 
or near the point of consumption if such resources are less costly than local 
facility extensions or upgrades; or 
(7) demand-side management programs for low-income customers that the utility 
develops through coordination with state or federally authorized weatherization 
providers. 
(k) Statewide integrated resource plan. 
(1) Process. In November 1998 and every two years thereafter, the commission 
shall adopt a statewide integrated resource plan. The statewide plan shall 
include the commission's long-term resource planning goals. When it adopts the 
statewide plan, the commission shall send the plan and a report on the plan to 
the governor and shall notify each electric utility that a statewide plan has 
been adopted. The commission shall make the statewide plan and the report on the 
plan available to the public. 
(2) Contents of the report. The report on the statewide plan shall include the 
commission's long-term resource planning goals for the State of Texas and: 
(A) historical data for electric consumption statewide and by utility; 
(B) historical data for electric generation by utility and by type of capacity, 
including alternative energy sources; 
(C) an inventory of generation capacity statewide and by utility;
(D) quantitative data on demand-side management programs to the extent the 
commission determines necessary; 
(E) each generating utility's forecast without adjustment;
(F) a projection of the need for electric services; 
(G) a description of the approved individual integrated resource plans of public 
utilities; 
(H) an assessment of transmission planning being performed by utilities within 
this state; and 
(I) other information as determined by the commission. 
(3) Recommendations regarding transmission system needs. In carrying out its 
duties related to the integrated resource planning process and in setting rates 
for utilities that are not required to file an integrated resource plan, the 
commission may review the state's transmission system to determine and make 
recommendations to public utilities on the need to build new power lines, 
upgrade power lines, or make other improvements and additions. 
(l) Confidential information. Any information submitted by a utility pursuant to 
this section and sec.sec.23.35-23.37 of this title may be submitted by the 
utility under seal. Each page submitted under seal shall have the words 
"Confidential Information" typed or stamped on its face. The utility shall 
clearly identify each portion of the application alleged to be Confidential 
Information; identify the exemption to the Open Records Act, Government Code, 
Title 5, Chapter 552, et seq. applicable to the alleged Confidential 
Information; and provide a detailed explanation of why the alleged Confidential 
Information should be exempt from public disclosure under the Open Records Act. 
The utility may require the execution of an appropriate confidentiality 
agreement prior to providing access to such confidential information to any 
interested party. The form of any such confidentiality agreement shall be agreed 
to by the Legal Division of the Office of Regulatory Affairs prior to filing and 
included with the informational filing. 
(m) Distribution functional unbundling. To mitigate any potential anti-
competitive behavior in the retail energy services market and to enforce the 
commission's obligations under subsection (m) of sec.2.051 and sec.2.216 of the 
Act, generating public utilities providing electric service to retail customers 
shall conform to the functional unbundling requirements and implementation 
schedule established in a separate rulemaking on distribution functional 
unbundling. 

sec.23.35.Preliminary Integrated Resource Plan. 
(a) Filing requirements. 
(1) All utilities. Preliminary integrated resource plans for a ten-year period 
shall be submitted every three years and shall be accompanied by an executive 
summary and the identity, address, telephone number and facsimile number of a 
contact person to deal with matters relating to the filing. All filings made 
under this section shall be comprehensive and provide sufficient detail, work 
papers, and source materials to allow the commission to determine the accuracy 
and reasonableness of the determinations made by the utility. The utility shall 
explain any differences between the filing and the most recent resource plan 
filing with the Electric Reliability Council of Texas or other reliability 
council. A preliminary plan submitted by a public utility or a municipal utility 
under this section must include current and ten-year projections of: 
(A) statistical data, including the utility's forecast or projections of: 
(i) summer and winter peak demand and electricity usage, 
(ii) adjustments to peak demand and electricity usage related to the acquisition 
of demand-side resources, interruptible load, and other factors that affect peak 
demand and electricity usage, 
(iii) existing system capacity, current and target reserve margins, and resource 
additions and retirements, and 
(iv) a description of existing and planned resources, and 
(B) the utility's projection of major transmission line additions.
(2) Public utilities. In addition to the information requested in paragraph (1) 
of this subsection, public utilities shall submit:
(A) a description of energy service options and pricing options available to 
each class of customers including options relating to: 
(i) the reliability of service (variations in firmness or interruptibility);
(ii) the quality of service (voltage fluctuation or other quality attributes); 
(iii) the stability of prices (such as rate or electric bill guarantees and 
budget plans); 
(iv) the choice of power service (such as green pricing or particular 
technologies); 
(v) the time of usage (such as seasonality, time-of-use, and real- time 
pricing); 
(vi) alternative billing or metering arrangements (such as conjunctive billing); 
(vii) backup, standby, or maintenance power service; and 
(viii) other factors of service and pricing structures that affect customer 
choice and resource planning; 
(B) an estimate of the energy savings and demand reduction the utility can 
achieve during the ten-year period through the acquisition of demand-side 
resources, and the range of possible costs for those resources;
(C) a description of how the utility will achieve equity among customer classes 
and provide demand-side management programs to each customer class including 
tenants and low-income ratepayers; 
(D) a description of how the utility promotes the development of renewable 
energy technology projects and distributed resources; 
(E) an estimate of additional supply-side resources needed to meet future 
demand, an estimate of the amount and operational characteristics of the 
additional capacity needed, the types of viable supply-side resources for 
meeting that need, the range of probable costs of those resources, and 
supporting technical data; 
(F) a record of public participation including a description of the process and 
a demonstration that the views and preferences of the utility's customers were 
considered in preparing the preliminary plan; 
(G) an evaluation of different internally-consistent planning scenarios and a 
discussion of the incidence and treatment of various factors of risk, including, 
but not limited to, performance, environmental, financial, and fuel-related 
risks; 
(H) proposed solicitations for new or replacement demand-side or supply-side 
resources including: 
(i) a description of the resource solicitation process and projected dates for 
the important events (issuance of the request for proposals, bid due date, 
negotiation period); 
(ii) the proposed request for proposals and draft model contract for resources; 
(iii) proposed bidder eligibility restrictions, if any, and proposed minimum 
threshold criteria related to bids, and the justification of any such 
restrictions; 
(iv) a description of the resource selection criteria and weights the utility 
will use to evaluate and select or reject resources and a listing of the 
criteria which were considered and rejected; 
(v) an explanation and quantification of how the utility assigns value to 
important options, such as options to accelerate or delay a project; to 
characteristics of resources, such as intermittence and dispatchability; to 
factors of risk, such as fuel cost risk mitigation, and to other significant 
options, characteristics, and factors that the utility employs in the selection 
of resources; 
(vi) an explanation of how, in developing specific resource selection criteria 
and weights, the utility has taken into account the definition of the lowest 
reasonable system cost, the values and preferences of customers, the 
characteristics of the resource need, and any statewide goals; 
(vii) documentation in support of a good cause exception for a targeted 
solicitation, if any; and 
(viii) documentation in support of an annual demand-side resource solicitation, 
if any; 
(I) a description of how the utility intends to allocate the costs of different 
types of demand-side and supply-side resources that could be procured; 
(J) any proposed incentive factors, the justification for such factors, and the 
proposed regulatory mechanism for the recovery of incentives; and 
(K) information regarding the cost and operation of each resource acquired 
outside the solicitation process during the past three years and a projection, 
to the extent known, of the resources that will be acquired outside the 
solicitation process during the next three years. 
(b) Notice. The utility shall file copies of its application under this section 
with the filing clerk of the commission and the Office of Public Utility 
Counsel. The utility shall also provide notice of the filing by publication in 
its service area and to any persons who have requested, in writing, to be 
notified of resource planning matters. The notice shall be completed not later 
than 15 days after the filing of the application. Interested persons may 
intervene in the proceeding not later than 45 days after the date on which the 
utility files its resource plan. 
(c) No hearing required. A commission hearing is not required for a preliminary 
plan filed by a river authority or generating electric cooperative that does not 
intend to build a new generating plant, or for a preliminary plan filed by a 
municipally-owned public utility, or for a preliminary plan filed by a investor-
owned utility if the plan does not contain a proposed resource solicitation. A 
commission hearing is not required for a preliminary plan that contains a 
proposed annual demand-side management solicitation and no other proposed 
solicitation. 
(d) Commission review of a preliminary integrated resource plan that does not 
include a solicitation. The commission shall issue a final order on the 
preliminary plan of an investor-owned utility if the preliminary plan does not 
contain a proposed solicitation. In such a case the commission shall issue a 
notice concerning the filing of a preliminary plan and determine whether the 
plan is in compliance with applicable rules. The commission shall expeditiously 
issue a final order on the preliminary plan. In addition, a preliminary plan 
that does not contain a proposed solicitation may be reviewed for deficiencies 
pursuant to sec.sec.1.321, 1.3215, 1.322 and 1.325 of the Act and the 
enforcement rules of the commission. 
(e) Deficiencies in filing. After a public utility files a preliminary plan, the 
commission shall determine whether such plan complies with the filing 
requirements of this section. Parties may file motions alleging material 
deficiencies in the utility's application for approval of the resource plan not 
later than 21 days after the filing of the application. The utility may file 
responses to such motions not later than five working days after the receipt of 
such motions. The commission shall rule on such motions not later than 40 days 
after the date that the application was filed. If the commission concludes that 
the filing is materially deficient, it shall require the utility to supplement 
its filing or to file a new preliminary integrated resource plan within a 
specified time. The deadline for issuing an order in a utility's application for 
approval of a resource plan, and other deadlines related to the processing of 
the application, shall be calculated from the date that the utility files a plan 
that is not materially deficient. 
(f) Commission review of a preliminary integrated resource plan that includes a 
solicitation. The commission may review a preliminary plan that contains a 
proposed solicitation on its own motion or on the motion of the utility or of an 
affected person. In conducting such a review, the commission shall convene a 
public hearing on the adequacy and merits of the preliminary plan. 
(1) Procedure. At the hearing, any interested person may intervene, present 
evidence, and cross-examine witnesses regarding the contents and adequacy of the 
preliminary plan. Discovery is limited to issues relating to the development of 
the preliminary plan, fact issues included in the preliminary plan, and other 
issues the commission is required to decide relating to the preliminary plan. 
The time for providing responses to requests for information may be shortened on 
motion of any party, on a showing of good cause. The commission shall issue an 
order on the preliminary plan not later than 180 days after the date the utility 
files its preliminary plan. The 180-day period may be extended for a period not 
to exceed 30 days for extenuating circumstances encountered in the development 
and processing of an initial plan, if the extenuating circumstances are fully 
explained and agreed to by the commissioners. The commission may adopt a 
schedule for considering a preliminary plan in less than 180 days if the 
circumstances warrant it. 
(2) Commission determinations. After the hearing, the commission shall make the 
following determinations with regard to a public utility's preliminary 
integrated resource plan filing: 
(A) whether the utility's plan is based on substantially accurate data, 
reasonable planning assumptions, and a reasonable method of forecasting;
(B) whether the utility's plan adequately addresses transmission needs; 
(C) whether the menu of energy service options and pricing options available to 
each class of customers is sufficiently broad to satisfy the needs of such 
customers; 
(D) whether the utility's preliminary plan identifies and takes into account any 
present and projected reductions in the demand for energy that may result from 
cost-effective measures to improve conservation and energy efficiency in the 
customer classes that the utility serves; 
(E) whether the utility's proposals to achieve equity among customer classes and 
provide demand-side programs to each customer class, including tenants and low-
income ratepayers, are adequate; 
(F) whether the utility's proposals to develop renewable energy technology 
projects and distributed resources are adequate; 
(G) if additional supply-side resources are needed to meet future demand, 
whether the utility's preliminary plan adequately demonstrates the amount and 
operational characteristics of the additional capacity needed, the types of 
viable supply-side resources for meeting that need, and the range of probable 
costs of those resources; 
(H) whether the utility's preliminary plan demonstrates that there were 
reasonable opportunities for customers to participate in the development of the 
preliminary plan, whether the utility facilitated the presentation of 
information from a broad range of perspectives, whether the utility provided 
adequate information as required by sec.23.34(f)(5)(C) of this title (relating 
to Integrated Resource Plan), and whether the views and preferences of customers 
were appropriately considered in preparing the preliminary plan; 
(I) whether the utility's plan identifies appropriate scenarios and takes into 
account the incidence and allocation of various factors of risk; 
(J) whether the specific selection criteria and weights the utility will use to 
evaluate and select or reject resources are reasonable and consistent with the 
definition of the lowest reasonable system cost, the views of its customers, the 
nature of resource need, and any statewide goals, and whether the proposed 
bidder eligibility and threshold criteria restrictions, if any, related to bids 
are justified and reasonable, and whether the solicitation procedures will 
encourage bids for a broad range of options to meet the needs of the utility's 
customers; 
(K) whether the cost allocation method proposed by the utility for different 
resource types is reasonable; 
(L) whether incentive factors are appropriate, and, if so, the levels of such 
incentive factors, and how such incentive factors will affect the resource 
selection process; and 
(M) whether the utility reasonably acquired resources outside the solicitation 
process. 
(3) Commission action. In order to approve a proposed preliminary plan that 
includes a solicitation, the commission must, at a minimum, make an affirmative 
finding regarding all matters set forth in paragraph (2) of this subsection, 
except paragraph (2)(B)-(C) and (F) of this subsection. The commission shall 
take into consideration its findings on paragraph (2)(B)-(C) and (F) of this 
subsection in deciding whether to approve the proposed preliminary plan. In its 
order, the commission shall approve the preliminary plan, modify the preliminary 
plan, or, if necessary, remand the preliminary plan for additional proceedings. 
An order approving a preliminary plan that contains a proposed solicitation is 
interim in nature. 

sec.23.36.Solicitation of Resources. 
(a) Purpose. The purpose of the utility's resource solicitation process is to 
obtain commitments from third parties for new and replacement resources, 
facilitate the evaluation of resources subject to the specific criteria set 
forth in the request for proposals, and serve as a starting point for further 
contract negotiations. A solicitation may be required as part of the integrated 
resource planning process, may be initiated by a utility, or may be ordered by 
the commission in the context of another proceeding.
(b) Solicitation required. The utility shall conduct solicitations for demand-
side and supply-side resources, as prescribed in an approved preliminary plan, 
if any. A utility not required to prepare a preliminary plan, but required to 
conduct a solicitation, shall conduct its solicitation in a manner consistent 
with the provisions of this section. 
(c) Notice. The utility shall provide reasonable notice of the request for 
proposals. Such notice shall include: 
(1) notice by mail to the secretary of the commission and the Office of Public 
Utility Counsel; and 
(2) notice by mail to persons who requested to be notified of the request for 
proposals by submitting their name and address to the commission. 
(d) Eligibility to bid. The solicitation procedures shall encourage broad 
participation by persons who are capable of providing demand-side or supply-side 
resources, including customers of the utility and small-scale resource 
providers. In addition to soliciting resources from unaffiliated third parties, 
the utility may prepare and submit a bid for a new utility demand-side 
management program as prescribed by subsection (f) of this section and may 
receive bids from one or more of its affiliates as prescribed by subsection (g) 
of this section. 
(e) Solicitation procedures. Each bidder, including the utility and its 
affiliates, shall submit two copies of its bid to the secretary of the 
commission. The secretary shall ensure that the utility has access to all bids 
at the same time, and shall keep a copy of each bid submitted by the utility or 
the utility's affiliate. A bid submitted under this subsection or retained under 
this subsection is confidential and is not subject to disclosure under Chapter 
552, Government Code. 
(f) Utility bids for demand-side management resources. The request for proposals 
shall indicate whether the utility reserves the right to use its own proposed 
demand-side management program to meet a need identified in the preliminary 
plan. If the utility retains this right, it must prepare a bid reflecting that 
resource. A bid prepared by the utility under this subsection must comply with 
the selection criteria specified in the preliminary plan, or if there is no 
preliminary plan, the bids must comply with the criteria specified in the 
request for proposals. A bid prepared by the utility under this subsection must 
include a proposal for verification and evaluation conducted by an independent 
consultant. The utility may not give preferential treatment or consideration to 
any bid. If the utility plans to prepare a bid under this subsection, the 
utility must describe, in its preliminary plan, a reasonable process for the 
sharing of customer information with third-party bidders to satisfy the 
standards of subsection (g) of this section, taking into account the need for 
the confidentiality of customer-specific billing and usage information.
(g) Utility affiliate bids. Any bid prepared by an affiliate of the utility must 
comply with the selection criteria specified in the preliminary plan and with 
commission regulations regarding affiliate transactions. The utility may not 
give preferential treatment or consideration to a bid prepared by an affiliate 
of the utility. 
(1) Each utility must establish written procedures to ensure that all 
transactions between the utility and its affiliates are conducted on an arm's 
length basis (a code of conduct). Such utilities must maintain a written record 
of the time, date, and substance of all conversations, data, and written 
materials directly or indirectly exchanged between its personnel and the 
personnel of its affiliates that pertain to competitive market information and 
the resource acquisition process. 
(2) The utility and its affiliates must maintain separate books; must not incur 
debt in a manner that would permit the creditor of the affiliate to have 
recourse to the assets of the utility; must value any assets transferred between 
the utility and its affiliate in accordance with state and federal regulations 
to prevent cross subsidies; and must not share officers, directors, or employees 
or own property in common. The utility must not perform on behalf of its 
affiliates the hiring or training of personnel, the purchase, installation or 
maintenance of equipment (except under contract), or research and development. 
The utility must not share any information related to customers' identity, 
energy service needs, loads, end-use devices, industrial processes, costs, 
prices or any other information related to strategic planning or retail markets, 
except as shared equally with all other competitive resource bidders. The 
utility must not carry out any joint promotion, marketing, sales, or advertising 
campaigns with its affiliates, except as are available to all other competitive 
resource bidders. 
(3) If a utility signs a contract for resources with its affiliate, the utility 
must carry out transactions with independence, pursuant to the contract, and 
maintain sufficient records to permit an audit of transactions between the 
utility and the affiliate, and the utility and its affiliate must each have an 
annual compliance review conducted by an independent entity.
(h) Independent evaluator. The utility shall use an independent evaluator if 
there is a likelihood that an affiliate bid may be included among the bids to be 
evaluated or if the utility plans to bid. If an independent evaluator is 
required, the utility shall maintain a record of communications with the 
independent evaluator. The utility may use an independent party to assist in the 
evaluation of bids as appropriate under other circumstances. The independent 
evaluator shall in writing identify the bids that are most advantageous and 
warrant negotiation and contract execution, in accordance with the criteria set 
forth in the request for proposals. The utility retains responsibility for final 
selection of resources subject to the review and approval of the commission. 
(i) Evaluation of bids. The utility or independent evaluator, as appropriate, 
shall evaluate each bid submitted in accordance with the criteria specified in 
the preliminary plan, or if there is no preliminary plan, the evaluation of bids 
shall be in accordance with the criteria specified in the request for proposals. 
(j) Negotiation. The utility shall negotiate the necessary contracts. A utility 
may negotiate a pricing structure that is suitable for the resource, considering 
such factors as the reliability of the resource, the need for security of 
performance, the availability of other means of ensuring security of 
performance, the nature of the resource, the level of risk, and other 
appropriate factors. The utility shall negotiate contract terms that 
appropriately allocate the risks of future fuel costs and other resource costs 
between the resource provider and the utility. 
(k) Rejection of third party bids. The utility is not required to accept a bid 
and may reject any or all bids in accordance with the selection criteria 
specified in the preliminary plan. If the results of the solicitations and 
contract negotiations do not meet the supply-side needs identified in the 
preliminary plan, the utility may apply for a certificate of convenience and 
necessity for a utility-owned resource addition notwithstanding the fact a 
solicitation was conducted and the addition was not included in the approved 
preliminary plan. Such a resource shall be subject to commission review pursuant 
to sec.23.37(f) of this title (relating to Approval of Resources Procured 
Through Solicitation). 
(l) Time limit for filing complaint. A complaint by a bidder concerning the 
utility's decision on the acquisition of resources in a solicitation may not be 
filed later than 90 days after the person receives a notice of the outcome of 
the solicitation. If such a complaint is filed, it shall be consolidated with 
any application for the approval of contracts, under sec.23.37 of this title. 

sec.23.37.Approval of Resources Procured Through Solicitation.
(a) Application. An electric utility seeking commission approval or 
certification of contracts for resources shall request such approval pursuant to 
the provisions of this section. Except as provided in paragraph (2) of this 
subsection, the commission will consider a request for approval or certification 
of a contract for resources only if the commission has approved the utility's 
preliminary resource plan and the utility has conducted a competitive resource 
solicitation prior to filing of the application for approval or certification of 
a contract. 
(1) A public utility that has conducted a competitive resource solicitation 
pursuant to sec.23.36 of this title (relating to Solicitation of Resources) 
shall submit its proposed final integrated resource plan for commission review. 
(2) A utility applying for contract approval pursuant to subsection (b)(3) of 
sec.23.34 of this title (relating to Integrated Resource Plan) shall submit its 
proposed contract for resources for commission review. The commission shall 
certify the contract on finding that the contract is reasonable. Nothing in this 
paragraph is intended to alter or amend existing wholesale power supply 
contracts. 
(b) Procedure. The commission shall, on request by an affected person and within 
90 days after the date a utility files its final integrated resource plan under 
this section, convene a public hearing on the reasonableness and cost-
effectiveness of the proposed final plan. Interested persons may intervene in 
the proceeding not later than 45 days after the date on which the utility files 
its resource plan. The time for providing responses to requests for information 
may be shortened on motion of any party and for a showing of good cause. The 
commission shall make its determination within 90 days after the date the 
proposed contract for resources is submitted by a utility pursuant to 
sec.23.34(b)(3) of this title. Otherwise, the commission shall make its 
determination and issue a final order within 180 days after the date the utility 
files the proposed final plan. The commission may adopt a schedule for 
considering a final plan in less than 180 days if the circumstances warrant it. 
(c) Filing requirements. After conducting solicitations and negotiating 
contracts, a public utility shall submit to the commission a proposed final 
integrated resource plan. The application shall include all testimony supporting 
the final plan. The proposed final plan must include: 
(1) the contracts for resources and the following information concerning 
resources that the utility proposes to acquire: 
(A) the reliability of the proposed resource, the financial condition of the 
provider, and the safety of that resource contract; 
(B) whether the contract would unreasonably impair the continued reliability of 
electric systems affected by the purchase after giving consideration to 
consistently applied regional or national reliability standards, guidelines, or 
criteria; and 
(C) whether the purchase can reasonably be expected to produce benefits to 
customers of the purchasing utility; 
(2) information about the integrated resource planning and solicitation 
processes including: 
(A) a copy of the order on the preliminary integrated resource plan and any 
documents required by an order of the commission or the Administrative Law 
Judge; 
(B) the results of the solicitation including: 
(i) the number, type, and size (in megawatts and megawatt- hours) of bids 
received; 
(ii) a description of the evaluation process and any related methods, manuals, 
formulas, or processes; 
(iii) a description of the negotiation process; and 
(iv) a demonstration that the solicitation, evaluation, and selection were 
conducted in accordance with the specific criteria included in the preliminary 
plan; 
(3) a description of the plan to achieve equity among customer classes and 
provide demand-side programs to each customer class including tenants and low-
income ratepayers; 
(4) an action plan covering a period of three years and the methods by which the 
utility intends to monitor resources after selection and acquisition; 
(5) if the utility accepts a bid submitted under sec.23.36(f) of this title, the 
terms and conditions under which the utility will provide resources to meet a 
need identified in the preliminary plan, the details of the verification and 
evaluation plan for the demand-side resource, and any information necessary to 
satisfy all the standards sec.23.36(f) and (g) of this title; 
(6) if the utility signed a contract for resources with its affiliate, any 
information necessary to satisfy all the standards of sec.23.36(g) of this 
title; 
(7) proposed timely cost recovery factors, if any, and the data necessary to 
reconcile existing timely cost recovery factors, if any; and 
(8) an application for a certificate of convenience and necessity, if necessary. 
(d) Notice. The utility shall file copies of its application under this section 
upon the filing clerk of the commission, the Office of Public Utility Counsel, 
and any intervenors in the proceeding. The utility shall also provide notice of 
the filing by publication in its service area, to any intervenor in its 
preliminary integrated resource plan proceeding, to any bidder in its 
solicitation, and to any person who has requested, in writing, to be notified of 
resource planning matters. The notice shall be completed not later than fifteen 
days after the filing of the application.
(e) Hearing on the final integrated resource plan. 
(1) Scope. At the hearing, any interested person may intervene, present 
evidence, and cross-examine witnesses regarding the reasonableness and cost-
effectiveness of the proposed final plan. Parties will not be allowed to 
litigate or conduct discovery on issues that were litigated or could have been 
litigated in connection with the filing of the utility's preliminary plan. 
(2) Discovery. To the extent permitted by federal law, the commission may issue 
a written order for access to the books, accounts, memoranda, contracts, or 
records of any exempt wholesale generator or power marketer selling energy at 
wholesale to a utility, if the examination is required for the effective 
discharge of the commission's regulatory responsibilities under the Act, except 
that if the commission issues such an order, the books, accounts, memoranda, 
contracts, and records obtained by the commission are confidential and not 
subject to disclosure under Chapter 552, Government Code. 
(3) Commission determinations. After the hearing, the commission shall determine 
whether: 
(A) to certify the contracts. In making this determination the commission shall 
consider: 
(i) the reliability of the proposed resource, the financial condition of the 
provider, and the safety of the resource; 
(ii) whether the contract would unreasonably impair the continued reliability of 
electric systems affected by the purchase after giving consideration to 
consistently applied regional or national reliability standards, guidelines, or 
criteria; and 
(iii) whether the purchase can reasonably be expected to produce benefits to 
customers of the purchasing utility. Commission certification of a resource 
contract does not affect the resource provider's obligation to comply with all 
applicable environmental and siting regulations; 
(B) the utility's proposed final plan was developed in accordance with the 
preliminary plan and commission rules. In making this determination the 
commission shall consider whether: 
(i) the utility has met the requirements of applicable commission orders, if 
any; 
(ii) the resource solicitations, evaluations, selections, and rejections were 
conducted in accordance with the specific criteria included in the preliminary 
plan; and 
(iii) the utility's proposed final plan is cost-effective and provides reliable 
energy service at lowest reasonable system cost as defined in sec.23.34(h) of 
this title; 
(C) the final plan is equitable among customer classes and provides demand-side 
programs to each customer class, including tenants and low-income ratepayers; 
(D) the utility has an adequate plan to acquire and monitor the resources; 
(E) the commission should certify any utility bid submitted under sec.23.36(f) 
of this title that resulted from the solicitations;
(F) the utility treated and considered its affiliate's bid in the same manner it 
treated and considered other bids intended to meet the same resource needs and 
complied with the requirements of sec.23.36(g) of this title. Further, if the 
public utility requests certification of a contract with the utility's 
affiliate, the commission shall determine, in connection with such purchase, 
whether: 
(i) the transaction will benefit consumers; 
(ii) the transaction violates any state law, including least-cost planning; 
(iii) the transaction provides the utility's affiliate any unfair competitive 
advantage by virtue of its affiliation or association with the utility; 
(iv) the transaction is in the public interest; and 
(v) the commission has sufficient regulatory authority, resources, and access to 
the books and records of the utility and its affiliate to make these 
determinations; 
(G) the commission should grant any request for a timely cost recovery factor, 
and if so, the mechanism and level of such factor, including the reconciliation 
of any existing factor; and 
(H) the commission should grant a requested certificate of convenience and 
necessity for a utility-owned resource addition. 
(4) Final order. In order to approve the final plan and contracts for resources 
the commission must make an affirmative finding regarding all matters set forth 
in paragraph (3) of this subsection, except paragraph (3)(E) and (G) of this 
subsection. The commission shall take into consideration its findings on 
paragraph (3)(E) and (G) of this subsection in deciding whether to approve the 
final plan. In its order, the commission shall approve the final plan, modify 
the final plan, or, if necessary, remand the final plan for additional 
proceedings. 
(f) Certificate of convenience and necessity for generating facilities. In 
determining whether to grant a requested certificate of convenience and 
necessity for new generating facilities under the integrated resource planning 
process, the commission shall consider the effect of the granting of a 
certificate on the recipient of the certificate and on any public utility of the 
same kind already serving the proximate area. The commission shall also consider 
other factors such as community values, recreational and park areas, historical 
and aesthetic values, environmental integrity, and the probable improvement of 
service or lowering of cost to consumers in that area if the certificate is 
granted. The commission shall grant the certificate as part of the approval of 
the final plan if it finds that: 
(1) the proposed addition is necessary under the final plan. In making its 
determination, the commission shall consider the following factors related to 
the public interest: 
(A) whether the solicitation was conducted in a manner consistent with the 
preliminary plan and the resource selection criteria; 
(B) whether any of the bids rejected in the solicitation would result in a more 
appropriate sharing of future risks among the parties to the contract and the 
utility's customers as compared to the proposed generating unit; and 
(C) whether the utility submitted a bid for a rate-base addition in the 
solicitation and whether the cost and technical characteristics of the 
generating unit for which the certificate is requested were known to bidders at 
the time the solicitation was issued, and if not, whether there is a reasonable 
likelihood that a new solicitation would result in lower-cost and higher quality 
bids that would better serve the public interest than the proposed generating 
unit; 
(2) the proposed addition is the best and most economical choice of technology 
for that service area. If a utility conducts a solicitation, rejects all bids, 
and applies for a certificate for a new generating facility, the reported costs 
of the resource alternatives offered in the resource solicitation shall be 
considered by the commission at the time of certification and in any prudence 
proceeding to investigate the reasonable costs of the generating facility. There 
shall be a rebuttable presumption that the rejected bids constitute a market-
based assessment of the value of new generating units in the context of any 
determination of the appropriate costs to include in the rate base of the 
utility; and 
(3) cost-effective conservation and other cost-effective alternative energy 
sources cannot reasonably meet the need. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority.
Issued in Austin, Texas, on July 8, 1996.
TRD-9609764
Paula Mueller
Secretary of the Commission
Public Utility Commission of Texas
Effective date: July 29, 1996
Proposal publication date: January 19, 1996
For further information, please call: (512) 458-0100

Customer Service and Protection
16 TAC sec.23.44
The amendment is adopted under the Public Utility Regulatory Act of 1995, 
sec.sec.1.101, 2.051, and 2.216, Texas Civil Statutes, Article 1446c-0, 
sec.sec.1.101, 2.051, 2.216. Section 1.101 provides the commission with the 
authority to make and enforce rules reasonably required in the exercise of its 
powers and jurisdiction; sec.2.051, requires the commission to adopt integrated 
resource planning regulations by September 1, 1996; and sec.2.216, prohibits 
public utilities from engaging in anti- competitive behavior. 

sec.23.44.New Construction.
(a)-(b) (No change.) 
(c) Line extension and construction charges. Every utility shall file its 
extension policy as required in sec.23.24(b)(1) of this title (relating to Form 
and Filings of Tariffs). The policy shall be consistent, nondiscriminatory, and 
subject to the approval of the commission. No contribution in aid of 
construction may be required of any customer except as provided for in the 
extension policy. 
(1)-(2) (No change.) 
(3) If, in order to provide service to a prospective or existing customer, a 
utility must provide a line extension to or on the customer's premises, and if 
the utility will require that customer to pay a Contribution in Aid to 
Construction (CIAC), a prepayment, or sign a contract with a term of one year or 
longer, the utility shall provide the customer with information about on-site 
renewable energy technology alternatives. The information shall comply with 
guidelines or other requirements set out by the commission, and shall be 
provided to the customer at the time the estimate of the CIAC or prepayment is 
presented to the customer, or in the event there is no CIAC or prepayment, 
before a contract is signed. The information is intended to assist the customer 
in becoming more knowledgeable in evaluating the options available. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's
legal authority.
Issued in Austin, Texas, on July 8, 1996.
TRD-9609765
Paula Mueller
Secretary of the Commission
Public Utility Commission of Texas
Effective date: July 29, 1996
Proposal publication date: January 19, 1996
For further information, please call: (512) 458-0100

TITLE 22. EXAMINING BOARDS
PART XXV. Structural Pest Control Board
CHAPTER 591.General Provisions
22 TAC sec.591.21
The Texas Structural Pest Control Board adopts an amendment to sec.591.21, 
without changes to the proposed text as published in the February 27, 1996, 
issue of the Texas Register (21 TexReg 1484). 
The justification for the rule is the amendment provides clearer understanding 
of the role and requirements of non-certified licensees. 
The rule functions in that the amendment adds a definition of apprentice.
No comments were received regarding adoption of the amendment. 
The amendment is adopted under Texas Civil Statutes, Article 135b-6, which 
provide the Texas Structural Pest Control Board with the authority to license 
and regulate persons who provide structural pest control services.
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority. 
Issued in Austin, Texas, on July 3, 1996.
TRD-9609800
Benny M. Mathis, Jr.
Executive Director
Structural Pest Control Board
Effective date: July 30, 1996
Proposal publication date: February 27, 1996
For further information, please call: (512) 835-4066

CHAPTER 593.Licensing
22 TAC sec.593.23
The Structural Pest Control Board adopts an amendment to sec.593.23, with 
changes to the proposed text as published in the April 19, 1996, issue of the 
Texas Register (21 TexReg 3411). 
The justification for the rule will be increased compliance with continuing 
education requirements due to simplification of the rules. 
The rule will function requiring that Certified Applicators list continuing 
education course numbers for the preceding twelve months when they renew their 
licenses. 
Several comments were concerned about the length of time until the requirements 
took effect. 
The Texas Pest Control Association commented in favor of the amendment. The 
Chemical Connection commented that the rule as amended reduces IPM requirements. 
The reason why the agency agrees with the comments is the rule has been amended 
to create earlier effective dates, thus reducing the lag time. Previous 
amendments required IPM content in all courses submitted for renewal, thus 
meeting the agency's objective to require IPM training. 
The amendment is adopted under Texas Civil Statutes, Article 135b-6, which 
provide the Structural Pest Control Board with the authority to license and 
regulate persons providing structural pest control services.

sec.593.23.Continuing Education Requirements for Certified Applicators. 
(a) On or after January 1, 1997, the Board shall require as a condition to the 
renewal of each certified applicator license granted pursuant to the provisions 
of this section, that the holder thereof certify to the Board that he or she has 
completed courses of continuing education approved by the Board that cover the 
applicator's category(ies) of certification for the preceding 12 months. This 
certification must be completed upon each annual renewal of the certified 
applicator's license. Failure to do so will prevent the license from being 
issued. 
(b) Each certified applicator is required to gain a certain number of continuing 
education points per year, and for each annual renewal period thereafter. 
Applicators who are certified and licensed after the effective date of this 
regulation, will not be required to obtain points for the first year in which 
their license is issued. Upon written request, the Board or the Executive 
Director may grant a hardship to a certified applicator due to extenuating 
circumstances. The length of the hardship is at the discretion of the Board or 
the Executive Director. 
(c) No courses may be repeated for credit. 
(d) The number of continuing education points required for each year is two 
points in general training and one point in each category in which the 
applicator is certified. Applicators who become certified in additional 
categories during an annual renewal period will not be required to obtain points 
in those categories for that period. 
(e) The staff shall evaluate continuing education programs, and assign the 
number of category points for each one. No more than one point will be assigned 
for any hour of net actual instruction time. The staff will consider, the 
technical information given, the recency of the information, the relevance of 
the information to structural pest control, the qualifications of the 
instructor, and the amount of actual training time devoted to each program in 
the process of evaluation. The staff will report its recommendation regarding 
the number of category points, if any, to be assigned to each program to the 
Executive Director of the Structural Pest Control Board. The Executive Director 
will then decide whether to accept, reject, or modify the staff recommendation. 
The Executive Director's decision shall be part of his regular report to the 
Board. 
(f) Any person seeking approval of a training program must submit the 
information required at least 30 days prior to the first day presentation. The 
Executive Director may waive this requirement due to special circumstances. The 
staff must evaluate and recommend credits within 30 days from the date 
submitted. Each submission shall include: 
(1) learning objectives 
(2) the course outline; 
(3) the names and qualifications of the instructors; 
(4) the categories and number of points which are requested;
(5) the means of verifying attendance; 
(6) an agreement to maintain attendance records for two years and to submit a 
list of participants to the Board and a certificate of completion to the 
attendee within 14 days after completion of the course;
(7) a facsimile of the certificate of completion that will be given to 
attendees; and 
(8) additional information requested to assist in the evaluation. 
(g) Parts of courses which focus on promotion of products, policies, or 
procedures of a company cannot be included for points. Programs and instructors 
must be evaluated at least every two years or more frequently at the Board's 
discretion. Any changes to programs shall be submitted to the Board 30 days 
prior to the date of presentation. These changes shall include the most recent 
information available concerning Integrated Pest Management in the subject area. 
(h) Each certified applicator shall keep a certificate of completion for each 
course he or she attends for a period of two years, and submit such records to 
the Board on request. These records are subject to inspection by Board personnel 
at any time. The penalty for falsifying continuing education records is a fine 
of $2,500 to $5,000, a six-month license suspension and re-testing by the 
certified applicator. Certified applicators found not in compliance will have 20 
days to produce the required certificates of completion for courses previously 
attended prior to the initiation of enforcement proceedings. Certified 
applicators who do not meet the recertification requirements will have their 
licenses suspended in all deficient categories for one year or until all 
deficiencies are corrected, and they must then re-qualify by taking the 
certification examination. 
(i) Upon written request to the Executive Director from any two members of the 
Board, the staff shall re-evaluate its approval of a course under the provisions 
of subsection (f) of this section. The date submitted shall be considered to be 
the date the second written request is received. 
(j) The general category is defined to include the topics included in the 
Structural Pest Control Act, sec.4A(e). Of the two general category points 
required for re-certification, at least one must be in federal and state laws, 
pesticide safety, environmental protection, or integrated pest management. The 
other may be in any general topic. 
(k) The Structural Pest Control Board may enter into a memorandum of agreement 
with a state or nonprofit professional society or association to recognize the 
state's pesticide applicator re-certification of the society's professional 
applicator re-certification for satisfaction of the requirements of this section 
for commercial and noncommercial applicator recertification only if: 
(1) the standards for recertification meet or exceed the standards for the 
recertification period as set out in this section; 
(2) the licensed commercial or noncommercial applicator also acquires at least 
two points in the general category during each year; and 
(3) the agreement reduces duplication of effort and does not increase the record 
keeping burden of the Board. 
(l) A certified applicator may submit the information required in subsection 
(f)(2), (4) and (7) of this section, the names of instructors and verification 
of attendance for any course attended by the certified applicator which was not 
previously approved within 30 days of attendance of the course. The Executive 
Director will notify the certified applicator of any points awarded.
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority. 
Issued in Austin, Texas, on July 3, 1996.
TRD-9609801
Benny M. Mathis, Jr.
Executive Director
Structural Pest Control Board
Effective date: July 30, 1996
Proposal publication date: April 19, 1996
For further information, please call: (512) 835-4066

TITLE 34. PUBLIC FINANCE
PART VI. Texas Municipal Retirement System
CHAPTER 121.Practice and Procedure Regarding Claims
34 TAC sec.121.7
The Texas Municipal Retirement System adopts an amendment to sec.121.7, 
concerning submission of documents reasonably related to establishment of a 
claimed right to benefits, without changes to the proposed text as published in 
the May 14, 1996, issue of the Texas Register (21TexReg 4216). 
The amendment clarifies the required documentation and sets guidelines for the 
timely receipt of these documents in the offices of the retirement system. 
No comments were received regarding adoption of the amendment. 
The amendment is adopted under the Texas Government Code, sec.855.102, which 
provides the board of trustees of the Texas Municipal Retirement System with the 
authority to adopt rules necessary or desirable for effective administration of 
the System. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority. 
Issued in Austin, Texas, on July 9, 1996.
TRD-9609829
Gary W. Anderson
Executive Director
Texas Municipal Retirement System
Effective date: July 30, 1996
Proposal publication date: May 14 1996
For further information, please call: (512) 476-7577

CHAPTER 123.Calculation or Types of Benefits
34 TAC sec.123.5
The Texas Municipal Retirement System adopts an amendment to sec.123.5, 
concerning spousal consent on any form filed with the System making application 
for a retirement annuity, without changes to the proposed text as published in 
the May 14, 1996, issue of the Texas Register (21TexReg 4216). 
The amendment specifies the manner in which spousal consent is obtained on 
applications for certain retirement annuity payments. 
No comments were received regarding adoption of the amendment. 
The amendment is adopted under the Government Code, sec.855.102, which provides 
the board of trustees of the Texas Municipal Retirement System with the 
authority to adopt rules necessary or desirable for effective administration of 
the System. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority. 
Issued in Austin, Texas, on July 9, 1996.
TRD-9609830
Gary W. Anderson
Executive Director
Texas Municipal Retirement System
Effective date: July 30, 1996
Proposal publication date: May 14 1996
For further information, please call: (512) 476-7577

CHAPTER 129.Qualified Domestic Relations Orders
34 TAC sec.sec.129.3, 129.6, 129.7, 129.9, 129.10
The Texas Municipal Retirement System adopts amendments to sec.sec.129.3, 129.6, 
129.7, 129.9, and 129.10, without changes to the proposed text as published in 
the May 14, 1996, issue of the Texas Register (21 TexReg 4217). 
These amendments change certain statutory references as a result of the 
codification, transfer and renumbering of the Texas Civil Statutes, Title 110B 
as well as define and clarify documentation required by the system to comply 
with qualified domestic relations orders. 
No comments were received regarding adoption of the amendments. 
The amendments are adopted under the Government Code, sec.855.102, which 
provides the board of trustees of the Texas Municipal Retirement System with the 
authority to adopt rules necessary or desirable for effective administration of 
the system. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority. 
Issued in Austin, Texas, on July 9, 1996.
TRD-9609831
Gary W. Anderson
Executive Director
Texas Municipal Retirement System
Effective date: July 30, 1996
Proposal publication date: May 14 1996
For further information, please call: (512) 476-7577

34 TAC sec.129.13, sec.129.14 
The Texas Municipal Retirement System adopts new sec.129.13 and sec.129.14, 
concerning requirements for a qualified domestic relations order, without 
changes to the proposed text as published in the May 14, 1996, issue of the 
Texas Register (21 TexReg 4218).
These new sections are being adopted to provide a form that has been pre-
approved by the retirement system as meeting the requirements of this title for 
a qualified order. A qualified domestic relations order in substantially the 
prescribed form incorporates by reference the definitions set forth in these 
sections and the provisions set forth in sec.129.14 of this title (relating to 
Provisions Incorporated by Reference). 
No comments were received regarding adoption of the new sections. 
The new sections are adopted under the Government Code, sec.855.102, which 
provides the board of trustees of the Texas Municipal Retirement System with the 
authority to adopt rules necessary or desirable for effective administration of 
the System. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority. 
Issued in Austin, Texas, on July 9, 1996.
TRD-9609832
Gary W. Anderson
Executive Director
Texas Municipal Retirement System
Effective date: July 30, 1996
Proposal publication date: May 14 1996
For further information, please call: (512) 476-7577

TITLE 37. PUBLIC SAFETY AND CORRECTIONS
PART I. Texas Department of Public Safety
CHAPTER 18.Driver Education
Driver Training School Testing and Issuance of Instruction Permits
37 TAC sec.sec.18.1-18.4
The Texas Department of Public Safety adopts new sec.sec.18.1-18.4, concerning 
Driver Training School Testing and Issuance of Instruction Permits, without 
changes to the proposed text as published in the May 21, 1996, issue of the 
Texas Register (21 TexReg 4398). 
The justification for these sections will be the reduction of crowded conditions 
in Driver License offices as a result of the applicants and their parents not 
being required to go to those offices to acquire an instruction permit. The new 
sections are necessary to implement the provisions of Texas Civil Statutes, 
Article 6687b as amended by Senate Bill 964 of the 74th Legislative Session, and 
establish procedures for said testing and issuance. 
No comments were received regarding adoption of the new sections. 
The new sections are adopted pursuant to Texas Civil Statutes, Article 6687b, 
sec.10(e) and sec.12(c), which provide that a licensed driver education school 
may administer required vision, highway sign, and traffic law portions of a 
driver's license examination and may subsequently issue instruction permits to 
those student applicants who successfully complete those examinations. 
This agency hereby certifies that the adoption has been reviewed by legal 
counsel and found to be a valid exercise of the agency's legal authority. 
Issued in Austin, Texas, on July 2, 1996.
TRD-9609844
James R. Wilson
Director
Texas Department of Public Safety
Effective date: July 30, 1996
Proposal publication date: May 21, 1996
For further information, please call: (512) 424-2890