Part II.
Public Utility Commission of Texas
Chapter 23.
Substantive Rules
Subchapter C. Rates
16 TAC §23.23
The Public Utility Commission of Texas adopts the repeal
of §23.23 relating to Rate Design with no changes to the proposed text
as published in the December 25, 1998
Texas Register
(23 TexReg 12978). The repeal is necessary to avoid duplicative rule
sections. The commission has adopted new §§25.234 relating to Rate
Design, 25.235 relating to Fuel Costs-General, 25.236 relating to Recovery
of Fuel Costs, 25.237 relating to Fuel Factors, and 25.238 relating to Purchased
Power Cost Recovery Factors to replace §23.23 for electric service providers.
The commission has adopted §26.205 relating to Rates for Intrastate Access
Services to replace §23.23 for telecommunications service providers.
This repeal is adopted under Project Number 17709.
The commission received no comments on the proposed repeal.
This repeal is adopted under the Public Utility Regulatory Act,
Texas Utilities Code Annotated §14.002 (Vernon 1998) (PURA) which provides
the commission with the authority to make and enforce rules reasonably required
in the exercise of its powers and jurisdiction.
Cross Index to Statutes: Public Utility Regulatory Act §14.002.
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.
Filed with the Office of the Secretary of State on June
15, 1999.
TRD-9903557
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: July 5, 1999
Proposal publication date: December 25, 1998
For further information, please call: (512) 936-7308
Subchapter J. Costs, Rates and Tariffs
16 TAC §§25.234-25.238
The Public Utility Commission of Texas (commission) adopts
new §§25.234 relating to Rate Design; 25.235 relating to Fuel Costs
- General; 25.236 relating to Recovery of Fuel Costs; 25.237 relating to Fuel
Factors; and 25.238 relating to Purchased Power Cost Recovery Factors, with
changes to the proposed text as published in the December 25, 1998,
The Appropriations Act of 1997, HB 1, Article IX, Section 167 (Section
167) requires that each state agency review and consider for readoption each
rule adopted by that agency pursuant to the Government Code, Chapter 2001
(Administrative Procedure Act). The commission finds that the reason for adopting
the rule continues to exist.
The public benefit anticipated as a result of enforcing these sections
will be the adoption of rates that are not unreasonably preferential, prejudicial,
or discriminatory, and allow the utilities to recover reasonable fuel and
purchased power costs in an efficient and timely manner. Also, §25.236
should increase off-system sales and therefore benefit the public from a decrease
in overall unit fuel costs.
The commission received comments and/or reply comments on the proposed
sections from the following parties: Texas Utilities Electric Company ("TU"),
Houston Lighting & Power ("HL&P"), Entergy Gulf States, Inc. ("EGS"),
Central and South West Corporation ("CSW"), El Paso Electric Company ("EPEC"),
Southwestern Public Service Company ("SPS"), Texas Industrial Energy Consumers
("TIEC"), South Texas Electric Cooperative ("STEC"), Texas Electric Cooperatives,
Inc. ("TEC"), and Office of Public Utility Counsel ("OPUC"). The commission
solicited comments on the text of the proposed sections and on specific questions
concerning the rules, which are summarized below.
A public hearing was held on March 9, 1999, at the commission offices under
Texas Government Code §2001.029. TU, HL&P, EGS, CSW, and EPEC attended
the hearing. TU commented that §25.235(b)(2)(A)(v) requires the notice
of fuel proceedings to contain a Control Number to the proceeding before a
Control Number is assigned by the commission. The commission agrees with TU
and has deleted that language from the rule.
The first three questions published in the
Texas
Register
were all related to the sharing of margins from off-system
energy sales.
(1) Should the commission permit utilities to
retain a share of the margins from off- system energy sales? If so, what is
the appropriate share for retention by utility shareholders? (2) In determining
the utilities' incentive to make off-system sales, should the utilities only
be allowed to retain a share of the margins over and above a three-year historical
average? (3) Should the commission place conditions on the eligibility of
a utility to retain a share of the margins from off-system energy sales? If
so, what conditions are appropriate?
OPC and TIEC filed the only comments opposing the sharing of margins from
off-system energy sales. OPC urged the commission to reject the proposal for
sharing of off-system sales margins between ratepayers and electric utility
shareholders. OPC argued that: (1) electric utilities currently have an appropriate
incentive to make off-system sales to increase efficiency and reduce unit
costs; (2) ratepayers bear all risks with making off-system sales; (3) shareholders
bear none of the costs of making off-system sales; (4) the proposed sharing
mechanism increases incentive to "game" the system; (5) the proposed sharing
mechanism does not act as a true incentive; and (6) no proof exists that an
additional incentive is needed or warranted. TIEC opposed rewarding electric
utilities for fulfilling their obligation to serve.
All utilities filing comments supported the sharing of margins from off-system
sales. Generally all favored greater retention of margins by shareholders.
SPS and STEC proposed retention rates that depended on the utility's standing
in the wholesale power market. HL&P, TU, and STEC proposed allocation
schemes that would reduce stranded costs.
CSW noted that the current regulatory framework provides few incentives
for utilities to participate in the off-system sales markets. Increasing the
incentives will increase the possibility for off-system sales and compensate
for uncertainties and risks that were not part of past markets. CSW also argued
that permitting utilities to retain larger shares of margins allows the utilities
to recover some of the costs necessary for the trading and sales organizations
to obtain the additional sales. CSW noted that other jurisdictions share margins
as high as 50%.
EGS and EPEC commented that the proposed 10% share is too small, and that
a 50-50 sharing of margins is more equitable. EPEC further argued that the
potential rewards do not outweigh the potential risks of total immersion in
the wholesale market.
HL&P suggested to expand the proposed rule to include shared margins
on purchases. HL&P argued that such a sharing arrangement would align
the interests of ratepayers and shareholders by encouraging the utility to:
(1) improve its position to make off-system sales; (2) look for increased
opportunities for savings from wholesale sales and purchases; and (3) negotiate
to maximize margins.
HL&P urged the commission to adopt a sharing allocation proposed in
the commission's Staff Report in Docket Number 17555,
Investigation into the Competitiveness of the Wholesale Market.
HL&P
proposed to share margins 25% to ratepayers, 25% to shareholders, and 50%
to reduce stranded costs. TU also supported this sharing allocation.
SPS argued that a minimum of 25% of margins should be retained by shareholders
with higher proportions being retained by utilities with lower costs. SPS
offered four reasons for the commission to implement margin sharing for off-system
sales: (1) competitive wholesale markets require increasingly greater effort
and creativity; (2) the competitive wholesale market will require higher incentives
to compensate for risk than in the past; (3) SPS's wholesale non- firm sales
generated on Texas gas support the Texas economy and should be encouraged;
and (4) sharing margins would more appropriately reflect the equities of the
situation and would provide an increased incentive to achieve even more wholesale
non-firm sales.
STEC argued that the commission should provide a graduated sharing of margins
from off- system sales. STEC suggested that the share of the margins should
increase in proportion to the utility's participation in the short-term energy
market. STEC argued that greater rewards for greater activity would help stimulate
the wholesale market. STEC also suggested that utilities with stranded costs
should be required to use the margins to write-down stranded costs.
The commission declines to require utilities to write-down stranded costs
with their share of margins from off-system sales. However, the utilities
may do so at their discretion.
The commission disagrees with the utilities' position that the sharing
of margins should be 50%. The commission finds that the greater the percentage
share of margins for retention by utility shareholders, the greater the possibility
that the ratepayers' loss of margins will exceed the benefit from stimulating
the wholesale market. The commission notes that a 10% share of the margins
by utilities should stimulate the wholesale market, without risking the ratepayers'
existing benefit from off-system energy sales. The commission is also concerned
that the greater the percentage share of margins, the greater the possibility
that the utilities will inappropriately game the system.
The second question posed by the commission asked whether the commission
should permit sharing of margins for sales over some historical average. While
opposing margin sharing, in the event that margin sharing is allowed, OPC
argued that the proposed criteria are not specific enough to be consistently
applied. Furthermore, OPC argued that any margin sharing should be applied
only to off-system sales above a historic level. Finally, OPC argued that
a transition provision should be included to flow through all margins to ratepayers
and not to permit shareholders to share margins until after a review of the
utility's base rates. OPC noted that the current rule has a similar transition
mechanism.
In response to Question Number 2, all the utilities opposed the establishment
of a historical threshold before margin could be shared. Although not stated
in the question, some utilities also voiced opposition to the imposition of
a moving three-year average.
CSW stated that while a three-year historical average may be an appropriate
benchmark in certain cases, it should not be included in the rule for all
utilities. CSW argued against the three- year average being a rolling average.
EGS, EPEC, HL&P, SPS, TU, and STEC argued that the level of shared
margins should not be limited to those margins above some historical amount.
SPS argued that such a baseline would place a time limit on sharing margins.
As sales increase, the utilities' three-year average baseline would increase.
Ultimately, the utility would be unable to make additional sales above the
average, thereby ending the sharing of margins. TU argued that declining market
prices and shrinking reserve capacity to make sales may result in no incremental
sales to exceed the historical average. STEC argued that the imposition of
a three-year baseline would penalize utilities that have been aggressive making
off-system sales and reward those utilities that have participated the least.
The commission agrees with the utilities that it would not be appropriate
to limit the sharing of margins to over and above a historical average.
The commission's third question asked for conditions that might be appropriately
placed on utilities before permitting them to retain a share of off-system
sales margins. Although opposing margin sharing, if the proposal is implemented,
TIEC would agree with the first two conditions contained in the proposed rule.
Additionally, TIEC argued that the third proposed condition for sharing off-system
sales margins should be strengthened. TIEC proposed to change the condition
from no detrimental transactions to all beneficial transactions. TIEC also
argued that the commission should require utilities to remove all non-fuel
costs from their eligible fuel expenses before permitting them to share margins
from off-system sales. Finally, TIEC argued that any entitlement to retain
a share of margins from off-system sales should be sunset at each fuel reconciliation,
at which time the utility may demonstrate that it continues to meet the necessary
conditions to share margins before the commission would permit continued sharing.
CSW did not find the proposed conditions governing a utilities' ability
to retain a share of the margins from off-system sales appropriate. Specifically,
CSW argued that the criterion that no off-system transactions were conducted
"to the detriment of retail customers," is vague thereby leading to unreasonable
multiple interpretations and arguments. CSW offered substitute language that
incorporates an "overall financial benefits test" that recognizes that the
utility should not be held accountable for certain activities, which may be
beyond its control.
EPEC, TU, HL&P, and SPS also argued that the commission should not
condition margin sharing on the vague standard that the utility conducts "no
transactions to the detriment of its retail customers." HL&P argued that
the commission should adopt a standard that concentrates on the aggregate
efforts to engage in off-system transactions. SPS argued that a single transaction
should not prohibit the sharing of margins. TU argued that the eligibility
conditions to share margins are unnecessary, ambiguous, and add uncertainty
to the incentives.
EGS argued that the only condition that should govern whether non-ERCOT
utilities can share margins from off-system sales should be a utility's implementation
of a non-discriminatory, open-access transmission tariff consistent with the
FERC Order 888.
EPEC commented that the commission should not condition non-ERCOT utilities'
opportunity to share margins upon their participation in a transmission region
governed by an independent transmission system operator (ISO). EPEC argued
that the absence of an independent transmission system operator does not justify
excluding a utility from sharing margins from off-system sales.
SPS opposed the imposition of "artificial and over restrictive conditions"
on the eligibility to share margins. SPS argued that such conditions would
not serve the basic purpose of margin sharing, to provide an incentive to
utilities to make off-system sales and thereby making the wholesale market
robust. SPS questioned whether the requirement that a utility be a member
of a transmission ISO in order to be eligible for sharing is evenhanded.
STEC did not oppose the proposed conditions to share in off-system margins.
STEC urged the commission to adopt another condition that would tie the proportion
of margins retained to the utility's level of participation in the short-term
wholesale market.
The commission disagrees with the utilities about including conditions
on the eligibility of a utility to retain a share of the margins. The commission
notes that if the goal of margin sharing is to stimulate the wholesale market,
then conditions which improve that goal should also be appropriate. The commission
agrees to clarify §25.236(a)(8), so that a single transaction will not
prohibit the sharing of margins.
(4) Should the commission delete §25.238(a)(3),
which requires commission approval of purchased power contracts with unregulated
entities, given wholesale market competition and the need for participants
to have greater operational flexibility?
HL&P and CSW argued not to delete the section, but to amend it to allow
commission approval rather than require commission approval. HL&P also
requested clarification of the term "investor-owned electric distribution
utility". EGSI and STEC argued to delete. TIEC argued that §25.238(a)(3)
may no longer be necessary for short-term resources, however, because of the
commission's integrated resource planning rules, the commission will still
be required to approve purchase power contracts for long-term capacity resources.
The commission agrees with TIEC that because of the integrated planning
rules, the commission should not delete §25.238(a)(3).
(5) Should the commission incorporate into these
regulations language to address the proper handling of sulfur dioxide (SO
HL&P and TU argued that SO
2
allowances
are properly recorded as non-fuel revenues and expenses and are base rate
items, because they are related to investment in plant and related pollution
control capital expenditures. TU also argued against SO
2
allowances as fuel because the FERC rejected that idea. CSW argued
against language to specify a particular treatment for SO
2
allowances, because different utilities may require different mixes
of base and eligible fuel treatment of expenses and revenues associated with
SO
2
allowances. EPEC argued against SO
2
allowances as fuel because the allowance transactions are already
scrutinized by FERC, the EPA, and through tax reporting. EPEC also argued
that allowance handling is an accounting item that does not directly impact
fuel rates or fuel factors. EGSI argued that SO
2
allowances are fuel-related and should be treated as eligible fuel expense.
STEC also argued that the commission should incorporate language on SO
The commission agrees with CSW that the commission should not incorporate
such language at this time.
(6) Should the commission incorporate into these
regulations language to address the proper handling of hedging gains and losses?
All parties stated that the commission should incorporate language to address
the proper handling of hedging gains and losses. CSW, HL&P, TU, and EPEC
stated that hedging gains and losses should be treated as eligible fuel. CSW
argued that because of the current regulatory uncertainty with regard to the
treatment of hedging gains and losses, utilities may be foregoing potentially
beneficial hedging transactions. A significant disincentive will exist if
the commission allocates hedging gains to customers and losses to shareholders.
CSW also requested that the fuel rule should be modified to allow utilities
to include the revenues, expenses, and transaction costs from financial derivative
transactions resulting from utility hedging activities, such as exchange-traded
futures, options, and swaps.
HL&P stated that the purpose of hedging activities is to reduce fuel
and energy costs while minimizing risk by locking in margins on off-system
transactions. Similar to margins on off- system transactions, hedging activities
should be reviewed in the aggregate and as part of the actual costs of fuel
and power. Currently, the use of financial instruments for hedging is unduly
risky because the rule does not allow for reconciliation of costs associated
with such financial transactions.
EGS stated that the marketplace for energy products has evolved such that
sophisticated instruments for managing risk are now available. EGS is concerned
that the current rule may result in an asymmetrical treatment of hedging gains
and losses.
TU argued that unequal regulatory treatment, based upon the hindsight of
whether there is a gain or a loss, and the uncertainty of regulatory treatment
serves as a severe disincentive to engage in hedging transactions. In developing
hedging language, the commission should use the accounting rules applicable
to hedging transactions specified by Generally Accepted Accounting Principles
and clearly state the applicable standards under which the reasonableness
and recoverability of hedging costs will be judged.
EPEC stated that the costs associated with fuel-price hedging should be
recovered through the fuel factor because such costs could be a critical part
of a utility's fuel acquisition strategy and could displace other costs that
would otherwise be flowed through the fuel factor. EPEC stated that to the
extent that hedging practices reduce a utility's fuel costs, those saving
should be flowed through to customers through the fuel factors, and shareholders
should receive none of the benefits. To the extent that hedging causes a premium
to be added to fuel costs, customers should likewise bear those increased
costs through the fuel factor, except to the extent that any hedging activities
are ultimately determined to be unreasonable in a fuel-reconciliation proceeding.
Hedging costs determined to be unreasonable should be borne by shareholders.
The commission finds that it should not incorporate language addressing
hedging gains and losses at this time, without further review. The commission
is concerned about the appropriate sharing of the risk, between the ratepayer
and the shareholder, of any hedging transactions. The commission is also concerned
about any speculative financial hedging.
(7) How should the commission incorporate the
following language into this rule?: "All utilities who must file fuel reconciliations
shall also survey the next-day and within the day electricity markets. The
survey shall be done every business day and include price and quantity. The
within the day survey shall be done more than once as conditions merit. Utilities
shall document this survey in electronic format. Parties may substitute information
from an electronic exchange or bulletin board upon showing that such information
is representative of the market. They shall also document in electronic format
the existence or absence of market opportunities by comparing the survey information
with the appropriate expected incremental or decremental generation cost.
All utilities who conduct a market survey shall file the results monthly in
electronic format and with their fuel reconciliations. Utilities who do not
have contractual or other authority to engage in the purchase and sale of
electricity in the wholesale market would be exempt from this requirement."
SPS and TU argued against incorporation because of the cost of implementation.
TU also argued that no meaningful comparisons can be made from such data.
CSW requested that the language have further clarification through workshops
and public hearings. CSW and HL&P argued that different utilities operate
differently and should be reviewed on a case by case basis. EPEC also argued
for the language to be utility specific. EGSI offered to provide such data
only on a monthly basis. STEC and TIEC argued to include the language, and
TIEC requested access to all parties.
The commission agrees with some of the parties, who have commented on the
difficulty of implementing such language. Therefore the commission adopts
§25.236(c)(6), and limits some of the requirements from the proposed
language.
Sections 25.235(b), 25.235(b)(1) - Notice
CSW proposed that §25.235(b) be moved to the commission's procedural
rules. The movement will place these provisions with other procedural sections.
Also, the placement of notice in the procedural rules will allow notice language
to read in a consistent manner and allow simultaneous modification with other
notice provisions as the need arises.
The commission disagrees with CSW that §25.235(b) should be moved.
Although the provision of notice is procedural, the commission believes that
§25.235(b) is more appropriately placed at the beginning of the fuel
proceeding section.
TIEC proposed to add to §25.235(b)(1) the requirement that a utility
provide direct, individual notice and a copy of the filing to intervenors
who participated in the utility's last fuel proceeding. This addition would
allow the intervenor to evaluate an application for a fuel refund/surcharge
or fuel factor change and have discussions with the utility before the 30-day
period in which to request a hearing.
The commission agrees with TIEC that direct notice should be given to parties
who participated in the electric utility's prior fuel reconciliation proceeding.
The commission, however, does not agree with TIEC that the electric utility
should be obligated to provide a copy of its filing. Upon the receipt of notice,
the party can reach its own conclusions whether or not to request a copy of
the filing from the electric utility.
Sections 25.236(a), 25.236(a)(1), 25.236(a)(2),
25.236(a)(5), 25.236(a)(6), 25.236(a)(7)(B), 25.236(a)(7)(C), 25.236(a)(8)
- Eligible Fuel Expenses
HL&P recommended that language of §25.236(a) explicitly provide
for the classification of all Account 565 expenses as eligible fuel expenses,
except that expense as defined in §25.236(a)(5). Therefore, the amounts
payable to others for the transmission of a utility's electricity over transmission
facilities owned by others would be classified as eligible fuel expenses.
TIEC on the other hand recommended that the proposed rule delete all Account
565 expenses from the definition of eligible fuel, because these expenses
are related to transmission and not generation.
The commission clarified §25.236(a)(5) to reflect the commission's
current position on Account 565 expenses.
In §25.236(a)(1), TU would like to exclude from eligible fuel maintenance
and taxes on rail cars owned or leased by an electric utility unless such
rail cars are used in connection with an internal delivery system in a mine-mouth
operation. In which case, the maintenance expenses and taxes on such rail
cars shall be included as eligible fuel expenses. The commission has recognized
in previous TU rate and fuel reconciliation proceedings that expenses associated
with internal delivery systems at mine-mouth operations are eligible expenses.
The commission concludes that TU's request to modify §25.236(a)(1)
to permit recovery of railcar maintenance and taxes on internal delivery systems
is not necessary, and to the extent that a utility seeks such recovery it
can be addressed as a special circumstances.
CSW proposed §25.236(a)(2) to include brokerage fees in eligible fuel
because it would improve fuel market activity.
The commission rejects CSW's suggestion that brokerage fees be recoverable
as eligible fuel. The commission sets an electric utility's base rates to
recover the salaries of its fuel staff and those rates also include the consulting
fees paid by the utility when contracting for fuel. Permitting recovery of
brokerage fees as eligible fuel would treat some fuel procurement expenses
different than the rest.
EGS suggested that in §25.236(a)(5), which addresses Account 565,
the following phrase should be added to the existing paragraph: "wheeling
expenses paid to others may not be recovered for non-ERCOT utilities." TU
also addressed this paragraph by proposing a change to make the commission's
fuel rule consistent with its transmission rules. TU suggested the following
addition, "For Account 565, the only eligible fuel expenses are the expenses
properly recorded in the Account for the following: (1) payments to third
parties for short-term transmission service; and (2) payments to third parties
for planned transmission service only to the extent that such payments exceed
the revenues received by the utility for planned transmission service provided
for third parties."
The commission agrees with EGS. The commission partially agrees with the
principles proposed by TU with regard to the expenses for short-term transmission
service and has adopted appropriate language in §25.236(a)(5).
CSW supports the symmetry of expenses and revenues that is included in
the proposed §25.236(a)(5) and §25.236(a)(7). If such symmetry was
removed, then CSW would oppose the exclusion of expense without the exclusion
of revenues.
The commission agrees with CSW that §25.236(a)(5) and §25.236(a)(7)
should be symmetrical in their treatment of revenues and expenses. The commission
believes that the language in §25.236(a)(5) and §25.236(a)(7) is
symmetrical.
TIEC commented that the "special circumstances" provision of §25.236(a)(6),
which would allow a utility to recover ineligible fuel expenses in the fuel
factor, should be eliminated. The provision has allowed utilities to include
costs that were only tangentially related to fuel, has undermined the justification
for allowing the utility to earn more than a risk free return to the stockholders,
is no longer appropriate as the State transitions to a fully competitive environment,
and needs to be eliminated to be consistent with current commission policy.
TIEC stated that if the commission did not want to eliminate the provision
then it should explicitly state that the commission would not give advanced
or pre-approval of expenses that occur outside the reconciliation period.
The commission rejects TIEC's argument that the "special circumstances"
provision of §25.236(a)(6) should be deleted. The commission believes
that there are circumstances that warrant deviation from the rules and that
the public interest is served when electric utilities know that such relief
is available.
Comments from EPEC, OPC, and TU were received concerning the revisions
to §25.236(a)(7)(B) dealing with revenues from wheeling transactions.
EPEC believed that the commission is premature to define what expenses should
be allowed for recovery and what revenues might offset these expenses for
wheeling transactions, when there is no independent system operator or regional
transmission provider fully developed in EPEC's service area. Also EPEC's
transmission rates are regulated and approved by the FERC. OPC recommended
that the commission reject the rule change which excepts wheeling revenues
for non-ERCOT utilities from reconcilable fuel because a portion of those
revenues should be directed to Texas ratepayers who financially support the
underlying assets which make the transaction possible irregardless of the
fact that FERC sets the rate for non-ERCOT utilities. TU suggested that §25.236(a)(7)(B)
needs to be narrowed to be consistent with the commission's transmission rules.
Only revenues received from third parties for payments of losses associated
with transmission transactions should serve as an offset to eligible fuel
costs.
The commission adopts §25.236(a)(7)(E) in order to be consistent with
the commission's transmission rules, as suggested by TU.
In order to reflect a consistent treatment for all wheeling revenues, EGS
proposed several minor changes to §25.236(a)(7)(C) as follow: "Production-related
revenues from off-system sales in their entirety, except as permitted in paragraph
(8) of this subsection". CSW suggested the following changes to provide symmetry
to the commission's rules: "...revenues from off- system energy sales in their
entirety..."
The commission finds that these clarifications are unnecessary.
Section 25.236(b) - Reconciliation Period
CSW proposed to allow the reconciliation period to be extended beyond the
36-month period if the parties to the proceeding agree. This extension may
allow for the review of expenses from a particular fuel purchase contract
that extended beyond the 36-month period.
The commission sees no need to adopt special language to permit the consideration
of fuel expenses beyond the 36-month reconciliation period. Such an exception
could be requested on a case-by-case basis and, especially if agreed to by
the parties, considered for final reconciliation.
Sections 25.236(c), 25.236(c)(5) - Filing Requirements
SPS and CSW were not opposed to the elimination of the original filing
requirements in §25.236(c), but they believe that filing packages should
be sufficiently specific to prevent any ambiguity. OPC believed that the filing
requirements should not be eliminated from the rule because a prescribed commission
application form could be changed at any time without notice and the utility
could omit information from a filing without obtaining a "good cause" exception.
TUEC requested that §25.236(c)(5) requiring the filing of "tables
and graphs which show generation (MWh), capacity factor, fuel costs (cents
per kWh and cents per MMBtu), variable cost and heat rate by plant and fuel
type, on a monthly basis" be deleted and this information be obtained through
discovery. TUEC believed this information to be highly sensitive and should
be protected under the provisions of a Protective Order rather than a confidentiality
agreement because a party violating a commission Protective Order would be
subject to the penalties specified in the Public Utility Regulatory Act (PURA).
The commission chose to remove filing requirement from the rule where duplicated
by the commission's fuel filing guidelines. While the commission understands
OPC's concern a requirement in a filing guideline is more easily changed that
a requirement in a rule, the commission disagrees that a utility could omit
information required by the filing guidelines without seeking a waiver. The
commission expects electric utilities to comply with filing requirements,
whether contained in rules or filing guidelines. The commission rejects TU's
arguments that the information requesting in §25.236 should be deleted
and obtained through discovery. The commission believes that the requested
information is useful and should be provided as part of an electric utility's
application. Parties should be able to perform discovery on the required information
immediately, rather than waiting until the information is provided as a discovery
response before probing the data.
Section 25.236(d)(1)(A) - Burden of Proof
Six utilities responded to the proposed §25.236(d)(1)(A) with very
similar comments. CSW believed the proposed revision introduces several terms
("feasible" and "lowest") which may establish inappropriate higher standards
of proof than the "reasonableness" standard of PURA. CSW also believed the
terms "feasible" and "lowest" are inappropriately used in the revised rule
language. EGS believed the proposed burden of proof language is confusing
and superfluous and should be deleted. EPEC questioned whether the proposed
change is intended to deviate from precedent. If the proposed change is intended
to alter established precedent, then the commission should explain the need
for such change, its origin and impact, and allow share holders the opportunity
to comment. HL&P stated that the commission should reject the proposed
language in §25.236(d)(1)(A) as an unwarranted departure from the statutory
language and as being vague and ambiguous. The proposed changes move away
from the statutory language of "reasonable and necessary." SPS suggested that
the current rule is well understood by all the parties and that considerable
amount of case law has been developed. Also, the use of the term "feasible"
has raised the standard of review to perfection, which cannot be achieved.
TU believed the additional phrase in §25.236(d)(1)(A) is not clear; will
undoubtedly cause litigation of very contentious issues; and will add unnecessarily
to the complexity of fuel reconciliation proceedings. Also, TU suggested that
the phrase appears to establish a higher burden of proof. If the commission
is determined to add to the statutory burden, then TU recommends two changes
for clarity. The phrase "which acquired the maximum amount of power at" should
be deleted and replaced with the phrase "and produced." A utility, of course,
can only acquire the amount of energy required by its customers at any point
in time, so the concept of "maximum amount" is unnecessary and confusing.
Secondly, the phrase "to retail customers" should be deleted because TU has
wholesale customers receiving service under a tariff subject to the same fuel
factor as its retail customers (differentiated by the voltage level of service).
The commission agrees with the utilities and has removed the proposed burden
of proof language from §25.236(d)(1)(A).
Sections 25.236(e)(5), 25.236(e)(6) - Refunds
and Surcharges
TIEC stated that §25.236(e)(5) of the proposed rule would retain the
requirement that the retail customers receiving service at transmission voltage
level, all wholesale customers, and any group of seasonal agricultural customers
would be assessed a lump-sum surcharge. TIEC would like the term "lump sum",
which could mean "one-time" to be clarified.
The commission has clarified §25.236(e)(5) by removing the word "lump-sum".
CSW requested a clarification concerning §25.236(e)(6) as to whether
or not the filing "windows" for various utilities apply with respect to a
stand-alone surcharge or refund proceeding.
The commission has clarified §25.236(e)(6) by specifying the filing
"windows".
Sections 25.237(b), 25.237(b)(1), 25.237(d)(4)
- Fuel Factor Filings
TIEC suggested that the public interest would be better served to allow
more timely adjustments in §25.237(b) to the fuel factor or implementation
of a surcharge or refund. TIEC claims that frequent surcharges and refunds
of under- or over-collected fuel costs can cause problems for businesses with
regular budget cycles. More timely adjustments to the fuel factor would minimize
the need for more frequent surcharges or refunds. TIEC proposed that a utility
could implement a change in the fuel factor when an over/under collection
reaches the materiality threshold and an adjustment would prevent a further
increase in the over/under collection balance. Such a change in the fuel factor
would be conditioned on the utility reaching a settlement with the major parties.
TIEC also suggested that the definition of an emergency be revised to include
circumstances that would cause a utility to materially over-collect (not just
under-collect) fuel costs absent a timely change in the fuel factor.
The commission notes that without a schedule for filings, the administrative
workload could become unmanageable. The commission finds that changes to §25.237(b)
are unnecessary.
SPS commented that all rules specifying what a utility must file in fuel
proceedings be deferred to the appropriate filing package and be sufficiently
specific to prevent any problem about what is required.
SPS suggested that all of the filing requirements should be removed from
rules and placed in appropriate filing packages or guidelines. While the commission
generally agrees with that rationale, the commission's filing guidelines for
fuel proceedings are not being reviewed. The commission may consider moving
all filing requirements to filing guidelines at a later date.
CSW proposed a revision to §25.237(b)(1) in order to simplify the
types of information required in the fuel factor filing schedules. The proposed
rule requires that specific information be provided for each month of the
period in which the fuel factor has been in effect up to the most recent month
for which information is available. CSW believes that the rule requires unnecessary
data. If the data request extended from the conclusion of the last completed
fuel reconciliation proceeding, then it would be less burdensome on the utility.
The commission notes that the most recent information is essential in determining
the need to revise fuel factors.
Section 25.237(d)(4) - Filing Opportunities for
Changing the Fuel Factor
CSW requested that SWEPCO's "filing window" for a fuel factor proceeding,
presently April and October (pursuant to present §23.23(b)(2)(E)(iv)
and under proposed rule §25.237(d)(4)), be moved to May and November.
CSW has experienced some difficulties with the current SWEPCO filing dates
because WTU has the March and September time slots.
The commission agrees with this change.
Section 23.23(a) - Certification of Contracts
CSW expressed a concern that even though CSW does not foresee their own
use of the certification of long-term fuel contracts, some entities may find
them useful. Therefore, the certification options should not be eliminated.
Also, CSW noted that the certification is optional.
The commission has not processed any cases under the contract certification
provisions of the existing rule. Furthermore, in light of the likely approach
of retail competition and the criterion that the contract must be of at least
five years in duration, the commission concludes that the value of contract
certification is increasingly limited.
Section 23.23(b)(6) - Transition Rule
SPS suggested that §23.23(b)(6) dealt with more than just the transitional
issues arising out of the 1993 changes to the §23.23. SPS recommended
that the concept that fuel revenues and expenses should be reconciled under
the rules that were in effect at the time the expense was incurred should
be carried forward. CSW opposed the elimination of §23.23(b)(6). CSW
proposed that a transition point be established so that all fuel-related revenues
and the definition of eligible fuel be treated differently depending upon
if they occurred before or after the effective date of the proposed changes.
The commission notes that the concept of a transition period is one that
is temporary in nature. This transition has existed since 1993, and since
then the commission has attempted to move all utilities under the current
fuel rule, regardless of inconsistencies with commission orders prior to that
date.
Section 23.23(c) - Cooperative Expedited Rate
Change
CSW opposed the elimination of the cooperative expedited rate change section
found in §23.23(c). CSW believed the section should be streamlined, if
necessary, and moved to the commission's procedural rules. TEC opposed the
deletion of §23.23(c) arguing that although many cooperatives have become
rate deregulated, several have not. TEC pointed out that the rule has been
used recently (1997) and is still useful by saving the cooperative and the
commission expenses associated with a more complicated proceeding. While,
if the commission deletes the rule, cooperatives would rely on the provisions
of the commission's procedural rule 22.243.TEC argued that a very important
difference exists under the two procedures. Under §23.23(c) an expedited
case could be filed for rate changes under 5%. Under the commission's procedural
rule §22.243, a rate change above 2.5% would be treated as a major rate
case that has a substantial filing requirement.
The commission disagrees with CSW's and TEC's suggestions and finds that
§23.23(c) is an unnecessary section. A cooperative will still be able
to request expedited consideration through good cause exceptions to the rule.
The following parties filed additional comments in response to questions
at the public hearing: EPEC, HL&P, EGS, and CSW. EPEC, EGS, and CSW stated
that it may be premature to address whether utilities should use their share
of off-system sales margins to write down stranded costs. EGS and EPEC reasserted
their request for a 50-50 sharing of margins. HL&P referred to decisions
of the Federal Energy Regulatory Commission ("FERC") and of other states to
show that they have allocated a greater share of margins to the utilities'
shareholders. The utilities outlined various risks associated with off-system
sales. EPEC, EGS, and HL&P support sharing margins on all off-system sales,
and CSW supports sharing of margins for incremental off-system sales. EPEC
argues that §25.236(a)(8)(A) discriminates against non-ERCOT utilities,
by requiring utility participation in a transmission region governed by an
independent transmission operator. EGS also opposes §25.236(a)(8)(A).
The commission believes that §25.236(a)(8)(A) is necessary to have
fair competition in the developing wholesale market.
EGS, HL&P, and CSW provided methods for calculating the sharing of
off-system purchase margins. EGS and CSW stated that transmission expenses
in Account 565 should not be included as eligible fuel. CSW argues however,
that ERCOT ISO and other ISO fees based upon transaction volume should be
included. HL&P argued that transmission cost of service revenues and expenses
should be included in eligible fuel.
Although the commission agrees with HL&P that transmission cost of
service may be included in eligible fuel and, therefore, disagrees with CSW
that the transmission expenses should not be included in eligible fuel, it
will defer action on this proposal until a later time. Legislation is pending
that could affect this proposal, and the commission will need to consider
the impact of such legislation on the proposal, if enacted. It was the commission's
intent, when it adopted the transmission rule, to entertain mechanisms for
the timely recovery of new transmission investment. Finally, the commission
agrees with CSW that the ERCOT ISO fees and other short-term, volume-related
fees should be included in eligible fuel.
In adopting the transmission pricing rules, the commission concluded that
it has the legal authority to permit new transmission costs to be recovered
through the fuel factor as eligible fuel expenses. However, the same limitations
that impede the implementation of a retail transmission factor also impede
the recovery of wholesale transmission expenses for planned service through
retail rates as eligible fuel expense. First, most of the large investor owned
utilities (IOUs) have not received a thorough review of their transmission
costs recently. Neither did those reviews include the unbundling of transmission
costs from generation and distribution and the establishment of unbundled
transmission rates. Many of the initial transmission cost of service (TCOS)
cases were based on cost-of-service information from prior retail rate cases,
and this information is now quite old. The transmission revenues collected
from retail customers through bundled retail rates and transmission costs
may have changed significantly since the last retail rate case. The other
impediment is the rate freezes that HL&P, TU Electric and Texas-New Mexico
Power Company (TNMP) have negotiated. Ultimately, the commission concluded
that it is good public policy to permit the timely recovery of new transmission
investment from retail customers. Accordingly, the commission adopted §25.193(a)(4)
of the transmission rule, which permits establishment of mechanisms for the
timely recovery of changes in wholesale transmission charges after a TCOS
proceeding and consistent with any rate freeze.
The commission concludes that it must use the same caution with regard
to the recovery of wholesale transmission expenses through fuel as it used
for the implementation of a retail transmission factor. The commission cannot
justify permitting the recovery of additional wholesale transmission costs
from retail customers outside of a rate case until it determines the level
of revenues that utilities are collecting through bundled retail rates for
transmission service. Furthermore, the commission will not circumvent the
agreements reflected in the rate freezes that HL&P, TU Electric and TNMP
have negotiated by permitting recovery of additional costs through eligible
fuel that were previously determined to be recoverable through base rates
in Docket Number 15840. After the legislative session ends and the commission
has an opportunity to review any changes to PURA that may affect fuel and
transmission cost recovery, the commission may need to revisit these rules
to make appropriate modifications. Those modifications could include the adoption
of specific mechanisms for the timely recovery of new transmission investments,
and those mechanisms may include the recovery of expenses associated with
new transmission investment through eligible fuel.
All comments, including any not specifically referenced herein, were fully
considered by the commission.
These new sections are adopted under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998) (PURA), which
provides the Public Utility Commission with the authority to make and enforce
rules reasonably required in the exercise of its powers and jurisdiction;
and specifically, PURA §§34.171, 34.172, 36.203, 36.204, 36.205.Section
34.171 grants the commission authority to allow additional incentives for
purchased power. Section 34.172 allows the commission to adopt rules regarding
the reconciliation of recovered costs. Section 36.203 directs the commission
to adopt rules which provide for the reconciliation of a utility's fuel costs,
and adjustment of fuel factor. Section 36.204 grants the commission authority
to allow additional incentives for purchased power. Section 36.205 grants
the commission authority over purchased power cost recovery.
Cross-Index to Statutes: Public Utility Regulatory Act §§14.002,
34.171, 34.172, 36.203, 36.204, and 36.205.
§25.234.Rate Design.
(a)
Rates shall not be unreasonably preferential, prejudicial,
or discriminatory, but shall be sufficient, equitable, and consistent in application
to each class of customers, and shall be based on cost.
(b)
Rates will be determined using revenues, billing and usage
data for a historical test year adjusted for known and measurable changes,
and costs of service as defined in §25.231 of this title (relating to
Cost of Service).
§25.235.Fuel Costs - General.
(a)
Purpose. The commission will set an electric utility's
rates at a level that will permit the electric utility a reasonable opportunity
to earn a reasonable return on its invested capital and to recover its reasonable
and necessary expenses, including the cost of fuel and purchased power. The
commission recognizes in this connection that it is in the interests of both
electric utilities and their ratepayers to adjust charges in a timely manner
to account for changes in certain fuel and purchased-power costs. Pursuant
to the Public Utility Regulatory Act (PURA) §36.203 this section establishes
a procedure for setting and revising fuel factors and a procedure for regularly
reviewing the reasonableness of the fuel expenses recovered through fuel factors.
(b)
Notice of fuel proceedings. In addition to the notice required
by the Administrative Procedure Act (APA) to be given by the commission, the
electric utility is required to give notice of a fuel proceeding at the time
the petition is filed.
(1)
Method of notice. Notice of fuel proceedings will be given
by the electric utility as follows:
(A)
Notice in all proceedings involving refunds, surcharges,
or a proposal to change the fuel factor, shall be by one-time publication
in a newspaper having general circulation in each county of the service area
of the electric utility or by individual notice to each customer and by individual
notice to parties that participated in the electric utility's prior fuel reconciliation
proceeding;
(B)
Notice in all reconciliation proceedings shall be by publication
once each week for two consecutive weeks in a newspaper having general circulation
in each county of the service area of the electric utility and by individual
notice to each customer and to parties that participated in the electric utility's
prior fuel reconciliation proceeding.
(2)
Contents of notice.
(A)
All notices required by this section shall provide the
following information:
(i)
the date the petition was filed;
(ii)
a general description of the customers, customer classes,
and territories affected by the petition;
(iii)
the relief requested;
(iv)
the statement, "Persons with questions or who want more
information on this petition may contact (utility name) at (utility address)
or call (utility toll-free telephone number) during normal business hours.
A complete copy of this petition is available for inspection at the address
listed above"; and
(v)
the statement, "Persons who wish to formally participate
in this proceeding , or who wish to express their comments concerning this
petition should contact the Public Utility Commission of Texas, Office of
Customer Protection, P.O. Box 13326, Austin, Texas 78711-3326, or call (512)
936-7120 or toll-free at (888) 782- 8477. Hearing and speech-impaired individuals
with text telephones (TTY) may call (512) 936-7136 or use Relay Texas (toll-free)
1-800-735-2989."
(B)
Notices to revise fuel factors must also state the proposed
fuel factors by type of voltage and the period for which the proposed fuel
factors are expected to be in effect.
(C)
Notices to revise fuel factors, to refund, or to surcharge
must contain the statement that, "these changes will be subject to final review
by the commission in the electric utility's next reconciliation," unless,
in the case of refunds or surcharges, the change is a result of a reconciliation
proceeding.
(D)
Notices to reconcile fuel expenses must also state the
period for which final reconciliation is sought.
(3)
Proof of notice may be demonstrated by appropriate
affidavit. In fuel proceedings initiated by a person other than an electric
utility, the notice required in this subsection must be provided in accordance
with a schedule ordered by the presiding officer.
(c)
Reports; confidentiality of information. Matters related
to submitting reports and confidential information will be handled as follows:
(1)
The commission will monitor each electric utility's actual
and projected fuel-related costs and revenues on a monthly basis. Each electric
utility shall maintain and provide to the commission, in a format specified
by the commission, monthly reports containing all information required to
monitor monthly fuel-related costs and revenues, including generation mix,
fuel consumption, fuel costs, purchased power quantities and costs, and system
and off-system sales revenues.
(2)
Contracts for the purchase of fuel, fuel storage,
fuel transportation, fuel processing, or power are discoverable in fuel proceedings,
subject to appropriate confidentiality agreements or protective orders.
(3)
The electric utility shall prepare a confidentiality
disclosure agreement to be included as part of the fuel reconciliation petition.
The format for the agreement shall be the same as that contained in the commission
approved rate filing package. In addition to the agreement itself, Attachment
1 of the agreement shall present a complete listing of the information required
to be filed which the electric utility alleges is confidential. Upon request
and execution of the confidentiality agreement, the electric utility shall
provide any information which it alleges is confidential. If the electric
utility fails to file a confidentiality agreement, the deadline for a commission
final order in the case is tolled until a protective order is entered or a
confidentiality agreement is filed. Use of the confidentiality disclosure
agreement does not constitute a finding that any information is proprietary
and/or confidential under law, or alter the burden of proof on that issue.
The form of agreement contained in the commission approved rate filing package
does not bind the examiner or the commission to accept the language of the
agreement in the consideration of any subsequent protective order that may
be entered.
(4)
A party that cannot view a confidential document without
receiving advantage as a competitor or bidder may hire outside counsel and
consultants to view the document subject to a protective order.
§25.236.Recovery of Fuel Costs.
(a)
Eligible fuel expenses. Eligible fuel expenses include
expenses properly recorded in the Federal Energy Regulatory Commission Uniform
System of Accounts, numbers 501, 503, 518, 536, 547, 555, and 565, as modified
in this subsection, as of April 1, 1997, and the items specified in paragraph
(7) of this subsection. Any later amendments to the System of Accounts are
not incorporated into this subsection. Subject to the commission finding special
circumstances under paragraph (6) of this subsection, eligible fuel expenses
are limited to:
(1)
For any account, the electric utility may not recover,
as part of eligible fuel expense, costs incurred after fuel is delivered to
the generating plant site, for example, but not limited to, operation and
maintenance expenses at generating plants, costs of maintaining and storing
inventories of fuel at the generating plant site, unloading and fuel handling
costs at the generating plant, and expenses associated with the disposal of
fuel combustion residuals. Further, the electric utility may not recover maintenance
expenses and taxes on rail cars owned or leased by the electric utility, regardless
of whether the expenses and taxes are incurred or charged before or after
the fuel is delivered to the generating plant site. The electric utility may
not recover an equity return or profit for an affiliate of the electric utility,
regardless of whether the affiliate incurs or charges the equity return or
profit before or after the fuel is delivered to the generating plant site.
In addition, all affiliate payments must satisfy the Public Utility Regulatory
Act (PURA) §36.058.
(2)
For Accounts 501 and 547, the only eligible fuel expenses
are the delivered cost of fuel to the generating plant site excluding fuel
brokerage fees. For Account 501, revenues associated with the disposal of
fuel combustion residuals will also be excluded.
(3)
For Accounts 518 and 536, the only eligible fuel expenses
are the expenses properly recorded in the Account excluding brokerage fees.
For Account 503, the only eligible fuel expenses are the expenses properly
recorded in the Account, excluding brokerage fees, return, non-fuel operation
and maintenance expenses, depreciation costs and taxes.
(4)
For Account 555, the electric utility may not recover
demand or capacity costs.
(5)
For Account 565, an electric utility may not recover
transmission expenses paid to affiliated companies for the purpose of equalizing
or balancing the financial responsibility of differing levels of investment
and operating costs associated with transmission assets. A non-ERCOT electric
utility may not recover expenses for wheeling transactions. An ERCOT electric
utility may only recover the expenses properly recorded in Account 565, for
payments to parties related to unplanned transmission service, such as ISO
fees, losses, and re-dispatch fees.
(6)
Upon demonstration that such treatment is justified
by special circumstances, an electric utility may recover as eligible fuel
expenses fuel or fuel related expenses otherwise excluded in paragraphs (1)
- (5) of this subsection. In determining whether special circumstances exist,
the commission shall consider, in addition to other factors developed in the
record of the reconciliation proceeding, whether the fuel expense or transaction
giving rise to the ineligible fuel expense resulted in, or is reasonably expected
to result in, increased reliability of supply or lower fuel expenses than
would otherwise be the case, and that such benefits received or expected to
be received by ratepayers exceed the costs that ratepayers otherwise would
have paid or otherwise would reasonably expect to pay.
(7)
Eligible fuel expenses shall not be offset by revenues
by affiliated companies for the purpose of equalizing or balancing the financial
responsibility of differing levels of investment and operation costs associated
with transmission assets. In addition to the expenses designated in paragraphs
(1) - (6) of this subsection, unless otherwise specified by the commission,
eligible fuel expenses shall be offset by:
(A)
revenues from steam sales included in Accounts 504 and
456 to the extent expenses incurred to produce that steam are included in
Account 503; and
(B)
revenues from wheeling transactions except for non-ERCOT
electric utilities; and
(C)
revenues from off-system sales in their entirety, except
as permitted in paragraph (8) of this subsection.
(D)
For electric utilities in ERCOT, revenues from third parties
for unplanned transmission service, such as ISO fees, losses, and re-dispatch
fees.
(8)
Shared margins from off-system sales. An electric
utility may retain 10% of the margins from an off-system energy sales transaction
if the following criteria are met:
(A)
the electric utility participates in a transmission region
governed by an independent system operator or a functionally equivalent independent
organization;
(B)
a generally-applicable tariff for firm and non-firm transmission
service is offered in the transmission region in which the electric utility
operates; and
(C)
the transaction is not found to be to the detriment of
its retail customers.
(b)
Reconciliation of fuel expenses. Electric utilities shall
file petitions for reconciliation on a periodic basis so that any petition
for reconciliation shall contain a maximum of three years and a minimum of
one year of reconcilable data and will be filed no later than six months after
the end of the period to be reconciled. However, notwithstanding the previous
sentence, a reconciliation shall be requested in any general rate proceeding
under the PURA, Chapter 36, Subchapters C and E and may be performed in any
general rate proceeding under the PURA, Chapter 36, Subchapter D. Upon motion
and showing of good cause, a fuel reconciliation proceeding may be severed
from or consolidated with other proceedings.
(c)
Petitions to reconcile fuel expenses. In addition to the
commission prescribed reconciliation application, a fuel reconciliation petition
filed by an electric utility must be accompanied by a summary and supporting
testimony that includes the following information:
(1)
a summary of significant, atypical events that occurred
during the reconciliation period that affected the economic dispatch of the
electric utility's generating units, including but not limited to transmission
line constraints, fuel use or deliverability constraints, unit operational
constraints, and system reliability constraints;
(2)
a general description of typical constraints that
limit the economic dispatch of the electric utility's generating units, including
but not limited to transmission line constraints, fuel use or deliverability
constraints, unit operational constraints, and system reliability constraints;
(3)
the reasonableness and necessity of the electric utility's
eligible fuel expenses and its mix of fuel used during the reconciliation
period;
(4)
a summary table that lists all the fuel cost elements
which are covered in the electric utility's fuel cost recovery request, the
dollars associated with each item, and where to find the item in the prefiled
testimony;
(5)
tables and graphs which show generation (MWh), capacity
factor, fuel cost (cents per kWh and cents per MMBtu), variable cost and heat
rate by plant and fuel type, on a monthly basis; and
(6)
a summary and narrative of the next-day and intra-day
surveys of the electricity markets and a comparison of those surveys to the
electric utility's marginal generating costs.
(d)
Fuel reconciliation proceedings. Burden of proof and scope
of proceeding are as follows:
(1)
In a proceeding to reconcile fuel factor revenues and expenses,
an electric utility has the burden of showing that:
(A)
its eligible fuel expenses during the reconciliation period
were reasonable and necessary expenses incurred to provide reliable electric
service to retail customers;
(B)
if its eligible fuel expenses for the reconciliation period
included an item or class of items supplied by an affiliate of the electric
utility, the prices charged by the supplying affiliate to the electric utility
were reasonable and necessary and no higher than the prices charged by the
supplying affiliate to its other affiliates or divisions or to unaffiliated
persons or corporations for the same item or class of items; and
(C)
it has properly accounted for the amount of fuel-related
revenues collected pursuant to the fuel factor during the reconciliation period.
(2)
The scope of a fuel reconciliation proceeding
includes any issue related to determining the reasonableness of the electric
utility's fuel expenses during the reconciliation period and whether the electric
utility has over- or under-recovered its reasonable fuel expenses.
(e)
Refunds. All fuel refunds and surcharges shall be made
using the following methods.
(1)
Interest shall be calculated on the cumulative monthly
ending under- or over-recovery balance at the rate established annually by
the commission for overbilling and underbilling in §25.28 (c) and (d)
of this title (relating to Bill Payment and Adjustments). Interest shall be
calculated based on principles set out in subparagraphs (A) - (E) of this
paragraph.
(A)
Interest shall be compounded annually by using an effective
monthly interest factor.
(B)
The effective monthly interest factor shall be determined
by using the algebraic calculation x = (1 + i)
(1/12)
- 1; where i = commission-approved annual interest rate, and x = effective
monthly interest factor.
(C)
Interest shall accrue monthly. The monthly interest amount
shall be calculated by applying the effective monthly interest factor to the
previous month's ending cumulative under/over recovery fuel and interest balance.
(D)
The monthly interest amount shall be added to the cumulative
principal and interest under/over recovery balance.
(E)
Interest shall be calculated through the end of the month
of the refund or surcharge.
(2)
Rate class as used in this subparagraph shall
mean all customers taking service under the same tariffed rate schedule, or
a group of seasonal agricultural customers as identified by the electric utility.
(3)
Interclass allocations of refunds and surcharges,
including associated interest, shall be developed on a month-by-month basis
and shall be based on the historical kilowatt-hour usage of each rate class
for each month during the period in which the cumulative under- or over-recovery
occurred, adjusted for line losses using the same commission-approved loss
factors that were used in the electric utility's applicable fixed or interim
fuel factor.
(4)
Intraclass allocations of refunds and surcharges shall
depend on the voltage level at which the customer receives service from the
electric utility. Retail customers who receive service at transmission voltage
levels, all wholesale customers, and any groups of seasonal agricultural customers
as identified by the electric utility shall be given refunds or assessed surcharges
based on their individual actual historical usage recorded during each month
of the period in which the cumulative under- or over-recovery occurred, adjusted
for line losses if necessary. All other customers shall be given refunds or
assessed surcharges based on the historical kilowatt-hour usage of their rate
class.
(5)
Unless otherwise ordered by the commission, all refunds
shall be made through a one-time bill credit and all surcharges shall be made
on a monthly basis over a period not to exceed 12 months through a bill charge.
However, refunds may be made by check to municipally-owned electric utility
systems if so requested. Retail customers who receive service at transmission
voltage levels, all wholesale customers, and any groups of seasonal agricultural
customers as identified by the electric utility shall be given a one-time
credit or assessed a surcharge made on a monthly basis over a period not to
exceed 12 months through a bill charge. All other customers shall be given
a credit or assessed a surcharge based on a factor which will be applied to
their kilowatt-hour usage over the refund or surcharge period. This factor
will be determined by dividing the amount of refund or surcharge allocated
to each rate class by forecasted kilowatt-hour usage for the class during
the period in which the refund or surcharge will be made.
(6)
A petition to surcharge or refund a fuel under- or
over-recovery balance not associated with a proceeding under subsection (d)
of this section shall be processed in accordance with the filing schedules
in §25.237(d) of this title (relating to Fuel factors) and the deadlines
in §25.237(e) of this title.
(f)
Procedural schedule. Upon the filing of a petition to reconcile
fuel expenses in a separate proceeding, the presiding officer shall set a
procedural schedule that will enable the commission to issue a final order
in the proceeding within one year after a materially complete petition was
filed. However, if the deadlines result in a number of electric utilities
filing cases within 45 days of each other, the presiding officers shall schedule
the cases in a manner to allow the commission to accommodate the workload
of the cases irrespective of whether such procedural schedule enables the
commission to issue a final order in each of the cases within one year after
a materially complete petition is filed.
§25.237.Fuel Factors.
(a)
Use and calculation of fuel factors. An electric utility's
fuel costs will be recovered from the electric utility's customers by the
use of a fuel factor that will be charged for each kilowatt-hour (kWh) consumed
by the customer.
(1)
Fuel factors are determined by dividing the electric utility's
projected net eligible fuel expenses, as defined in §25.236(a) of this
title (relating to Recovery of Fuel Costs), by the corresponding projected
kilowatt-hour sales for the period in which the fuel factors are expected
to be in effect. Fuel factors must account for system losses and for the difference
in line losses corresponding to the type of voltage at which the electric
service is provided. An electric utility may have different fuel factors for
different times of the year to account for seasonal variations. A different
method of calculation may be allowed upon a showing of good cause by the electric
utility.
(2)
An electric utility may initiate a change to its fuel
factor as follows:
(A)
An electric utility may petition to adjust its fuel factor
as often as once every six months according to the schedule set out in subsection
(d) of this section.
(B)
An electric utility may petition to change its fuel factor
at times other than provided in the schedule if an emergency exists as described
in subsection (f) of this section.
(C)
An electric utility's fuel factor may be changed in any
general rate proceeding.
(3)
Fuel factors are temporary rates, and the electric
utility's collection of revenues by fuel factors is subject to the following
adjustments:
(A)
The reasonableness of the fuel costs that an electric utility
has incurred will be periodically reviewed in a reconciliation proceeding,
as described in §25.236 of this title, and any unreasonable costs incurred
will be refunded to the electric utility's customers.
(B)
To the extent that there are variations between the fuel
costs incurred and the revenues collected, it may be necessary or convenient
to refund overcollections or surcharge undercollections. Refunds or surcharges
may be made without changing an electric utility's fuel factor, but requests
by the electric utility to make refunds or surcharges may only be made at
the times allowed by this paragraph. An electric utility may petition to make
refunds or surcharges at the specified times that these rules allow an electric
utility to change its fuel factor irrespective of whether the electric utility
actually petitions to change its fuel factor at that time. An electric utility
shall petition for a surcharge at the next date allowed for setting a fuel
factor by the schedule set out in subsection (d) of this section when it has
materially undercollected its fuel costs and projects that it will continue
to be in a state of material undercollection. An electric utility shall petition
to make a refund at any time that it has materially overcollected its fuel
costs and projects that it will continue to be in a state of material overcollection.
"Materially" or "material," as used in this section, shall mean that the cumulative
amount of over- or under-recovery, including interest, is greater than or
equal to 4.0% of the annual estimated fuel cost figure most recently adopted
by the commission, as shown by the electric utility's fuel filings with the
commission.
(b)
Petitions to revise fuel factors. During the first five
business days of the months specified in subsection (d) of this section, each
electric utility using one or more fuel factors may file a petition requesting
revised fuel factors. A copy of the filing shall also be delivered to the
Office of Regulatory Affairs and the Office of Public Utility Counsel. Each
petition must be accompanied by the commission prescribed fuel factor application
and supporting testimony that includes the following information:
(1)
For each month of the period in which the fuel-factor has
been in effect up to the most recent month for which information is available,
(A)
the revenues collected pursuant to fuel factors by customer
class;
(B)
any other items that to the knowledge of the electric utility
have affected fuel factor revenues and eligible fuel expenses; and
(C)
the difference, by customer class, between the revenues
collected pursuant to fuel factors and the eligible fuel expenses incurred.
(2)
For each month of the period for which the revised
fuel factors are expected to be in effect, provide system energy input and
sales, accompanied by the calculations underlying any differentiation of fuel
factors to account for differences in line losses corresponding to the type
of voltage at which the electric service is provided.
(c)
Fuel factor revision proceeding. Burden of proof and scope
of proceeding are as follows:
(1)
In a proceeding to revise fuel factors, an electric utility
has the burden of proving that:
(A)
the expenses proposed to be recovered through the fuel
factors are reasonable estimates of the electric utility's eligible fuel expenses
during the period that the fuel factors are expected to be in effect;
(B)
the electric utility's estimated monthly kilowatt-hour
system sales and off- system sales are reasonable estimates for the period
that the fuel factors are expected to be in effect; and
(C)
the proposed fuel factors are reasonably differentiated
to account for line losses corresponding to the type of voltage at which the
electric service is provided.
(2)
The scope of a fuel factor revision proceeding
is limited to the issue of whether the petitioning electric utility has appropriately
calculated its estimated eligible fuel expenses and load.
(d)
Schedule for filing petitions to revise fuel factors. A
petition to revise fuel factors may be filed with any general rate proceeding.
Otherwise, except as provided by subsection (f) of this section which addresses
emergencies, petitions by an electric utility to revise fuel factors may only
be filed during the first five business days of the month in accordance with
the following schedule:
(1)
January and July: El Paso Electric Company and Central
Power and Light Company;
(2)
February and August: Texas Utilities Electric Company
and Brazos Electric Power Cooperative, Inc.;
(3)
March and September: West Texas Utilities Company
and Entergy Gulf States, Inc.
(4)
April and October: Houston Lighting & Power Company;
(5)
May and November: Southwestern Electric Power Company,
Southwestern Public Service Company, and Lower Colorado River Authority; and
(6)
June and December: Texas-New Mexico Power Company,
South Texas Electric Cooperative, Inc., San Miguel Electric Cooperative, Inc.,
and any other electric utility not named in this subsection that uses one
or more fuel factors.
(e)
Procedural schedule. Upon the filing of a petition to revise
fuel factors in a separate proceeding, the presiding officer shall set a procedural
schedule that will enable the commission to issue a final order in the proceeding
as follows:
(1)
within 60 days after the petition was filed, if no hearing
is requested within 30 days of the petition; and
(2)
within 90 days after the petition was filed, if a
hearing is requested within 30 days of the petition. If a hearing is requested,
the hearing will be held no earlier than the first business day after the
45th day after the application was filed.
(f)
Emergency revisions to the fuel factor. If fuel curtailments,
equipment failure, strikes, embargoes, sanctions, or other reasonably unforeseeable
circumstances have caused a material under-recovery of eligible fuel costs,
the electric utility may file a petition with the commission requesting an
emergency interim fuel factor. Such emergency requests shall state the nature
of the emergency, the magnitude of change in fuel costs resulting from the
emergency circumstances, and other information required to support the emergency
interim fuel factor. The commission shall issue an interim order within 30
days after such petition is filed to establish an interim emergency fuel factor.
If within 120 days after implementation, the emergency interim factor is found
by the commission to have been excessive, the electric utility shall refund
all excessive collections with interest calculated on the cumulative monthly
ending under- or overrecovery balance in the manner and at the rate established
by the commission for overbilling and underbilling in §25.28(c) and (d)
of this title (relating to Bill Payment and Adjustments Billing). If, after
full investigation, the commission determines that no emergency condition
existed, a penalty of up to 10% of such over-collections may also be imposed
on investor-owned electric utilities.
§25.238.Power Cost Recovery Factors (PCRF).
(a)
Application. The provisions of this subsection apply to
all investor-owned electric distribution utilities, river authorities and
cooperative-owned electric utilities.
(1)
An electric utility which purchases electricity at wholesale
pursuant to rate schedules approved, promulgated, or accepted by a federal
or state authority, or from qualifying facilities may be allowed to include
within its tariff a PCRF clause which authorizes the electric utility to charge
or credit its customer for the cost of power and energy purchased to the extent
that such costs vary from the purchased power cost utilized to fix the base
rates of the electric utility. Purchased electricity cost includes all amounts
chargeable for electricity under the wholesale tariffs pursuant to which the
electricity is purchased and amounts paid to qualifying facilities for the
purchase of capacity and/or energy. The terms and conditions of such PCRF
clause, which may include the method in which any refund or surcharge from
the electric utility's wholesale supplier will be passed on to its customers,
shall be approved by an order of the commission.
(2)
Any difference between the actual costs to be covered
through the PCRF and the actual PCRF revenues recovered shall be credited
or charged to the electric utility's ratepayers in the second succeeding billing
month unless otherwise approved by the commission.
(3)
If the electric utility purchases power from an unregulated
entity, such as a political subdivision of the State of Texas, the electric
utility shall submit the purchased power contract to the commission for approval
of the terms, conditions and price. If the commission issues an order approving
the purchase, a PCRF may be applied to such purchases.
(4)
If PCRF revenue collections exceed PCRF costs by 10%
in any given month and the total PCRF revenues have exceeded total PCRF costs
by 5.0% or more for the most recent 12-month period:
(A)
investor-owned electric distribution utilities shall be
subject to a 10% penalty on excess collection,
(B)
cooperative-owned electric utilities shall report to the
commission the justification for excess collection.
(5)
The electric utility shall maintain and provide
to the commission, monthly reports containing all information required to
monitor the costs recovered through the PCRF clause. This information includes,
but is not limited to, the total estimated PCRF cost for the month, the actual
PCRF cost on a cumulative basis, total revenues resulting from the PCRF and
the calculation of the PCRF.
(b)
Application. The provisions of this subsection apply to
all investor-owned generating electric utilities and river authorities.
(1)
An electric utility which purchases electricity from qualifying
facilities may be allowed to include within its tariff a PCRF clause which
authorizes the electric utility to charge or credit its customers for the
costs of capacity purchased from cogenerators and small power producers. These
costs shall be included in the PCRF only to the extent that such costs vary
from the costs utilized to fix the base rates of the electric utility. The
terms and conditions of such PCRF shall be approved by an order of the commission.
(2)
Purchased power costs that are recovered through the
PCRF shall be excluded in calculating the electric utility's fixed fuel factor
as defined in §25.237 of this title (relating to Fuel Factors).
(3)
Costs recovered through a PCRF shall be allocated
to the various rate classes in the same manner as the embedded costs of the
electric utility's generation facilities allocated in the electric utility's
last rate case, unless otherwise ordered by the commission. Once allocated,
these costs shall be collected from ratepayers through a demand or energy
charge.
(4)
Any difference between the actual costs to be recovered
through the PCRF and the PCRF revenues recovered shall be credited or charged
to the customers in the second succeeding billing month.
(5)
If PCRF revenue collections exceed PCRF costs by 10%
in any given month and the total PCRF revenues have exceeded total PCRF costs
by 5.0% or more for the most recent 12-month period, the electric utility
shall be subject to a 10% penalty on excess collections.
(6)
The electric utility shall maintain and provide to
the commission, monthly reports containing all information required to monitor
costs recovered through the PCRF. This information includes, but is not limited
to, total estimated PCRF cost for the month, the actual PCRF cost, total revenue
resulting from the PCRF and the calculation of the PCRF clause.
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.
Filed with the Office of the Secretary of State on June
15, 1999.
TRD-9903555
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: July 5, 1999
Proposal publication date: December 25, 1998
For further information, please call: (512) 936-7308
Subchapter J. Costs, Rates and Tariffs
Chapter 25.
Substantive Rules Applicable to Electric Service Providers
Chapter 26.
Substantive Rules Applicable to Telecommunications Service Providers