August 2008
From the editors of Wolters Kluwer Law & Business, this update describes
important developments from CCH energy publications.
If you have any comments or suggestions concerning the information provided or the format used, we'd like to hear from you. Please send your comments to pamela.maloney@wolterskluwer
Nuclear Power
DOE: Yucca Mountain Project to Cost
$96 Billion
The total system life cycle
cost for the geologic repository at Yucca Mountain, Nevada, will be $96.2
billion, according to a newly revised estimate released by the Department
of Energy (DOE). The 2007 total life cycle estimate includes cost to research,
construct and operate Yucca Mountain over a period of 150 years, from
the beginning of the program in 1983 through closure and decommissioning
in 2133. The $96.2 billion figure represents a 38 percent increase from
the last published estimate (in 2001) of $57.5 billion. The updated estimate
takes into account a substantial increase in the amount of waste to be
shipped and stored at the repository—from a 2000 estimate of 83,800
metric tons heavy metal to a 2007 estimate of 109,300 metric tons heavy
metal—and more than $16 billion for inflation. The Department is
not proposing a change in the fees paid by nuclear utilities for the disposal
of commercial spent nuclear fuel. (CCH Nuclear Regulation Reporter,
No. 1398, August 12, 2008)
Nuclear Plant’s Rates Remain
Unchanged
The Louisiana Public Service
Commission’s (Louisiana Commission) request to alter the depreciation
and decommissioning rates and the return on equity (ROE) under the Unit
Power Sales Agreement (Agreement) between System Energy Resources, Inc.
(System Energy) and four Entergy operating companies to reflect a possible
change in the length of an operating license was denied by the Federal
Energy Regulatory Commission (Commission). Louisiana Commission filed
the complaint against System Energy requesting the rate change in anticipation
of a 20-year extension in the operating license of the Grand Gulf 1 Nuclear
Generating Facility. Also, Louisiana Commission argued the ROE formula
rate should be lowered because it was no longer just and reasonable based
on the decline in interest rates since System Energy’s last proceeding.
The Commission denied Louisiana Commission’s complaint on both grounds.
The Commission noted that in order for the complainant to succeed Louisiana
Commission had to establish that the current rate was unjust and unreasonable;
second, the complainant had to establish that its alternative rate proposal
was just and reasonable. The Commission found that Louisiana Commission
did not meet the first burden because it did not demonstrate that the
depreciation and decommissioning rates under the Agreement were not just
and reasonable, or that System Energy’s ROE should have been reduced
from its level. Louisiana Commission did not meet the second burden by
not providing sufficient evidence to demonstrate that its proposed rates
for the Agreement were just and reasonable. Finally, the Commission found
that Louisiana Commission had not provided sufficient information to establish
that System Energy’s currently-effective ROE under the Agreement
was unjust and unreasonable, or that its proposed ROE would be just and
reasonable.( Louisiana Public Service Commission v. System Energy
Resources, Inc., et al., 124
FERC ¶61,003 (ip
access users))
Natural Gas
Non-jurisdictional Extension Line Costs
Removed from Recourse Rates
The construction costs of non-jurisdictional
natural gas extension lines which would connect a lateral expansion project
(Colorado Lateral) to a local distribution company will be removed by
the Commission from the cost-based recourse rates that the transmission
company constructing the lines will charge for service. In an order on
rehearing of Kinder Morgan Interstate Gas Transmission LLC (122
FERC ¶61,154 (ip
access users)), the Public Service Company of Colorado (PSCo) argued
that the Commission erred in permitting Kinder Morgan to include the costs
of these lines in both the initial incremental negotiated and recourse
rates that it will charge for this service. The distribution company currently
obtains its gas transportation service from PSCo; when the Colorado Lateral
and the non-jurisdictional extension lines are completed, it will be able
to serve its market via Kinder Morgan’s Colorado Lateral, thus effectively
bypassing PSCo. Kinder Morgan intends to convey ownership of the extension
line facilities to the distribution company before service begins. In
this instance, Kinder Morgan is building the Colorado Lateral to service
a single shipper and the Commission has approved an initial incremental
recourse rate for service to that shipper. Therefore, the construction
costs associated with the non-jurisdictional facilities would be included
in Kinder Morgan’s incremental recourse rate as soon as service
began on the Colorado Lateral. Since the distribution company has not
subscribed to the full capacity of the Colorado Lateral until the second
five-year period of operation, it is possible that another shipper seeking
to acquire available capacity on this incrementally-priced line would
be required to pay for extension line facilities that are not owned and
operated by Kinder Morgan and that would not benefit such shipper. Therefore
the costs associated with the non-jurisdictional facilities must be removed
from the recourse rates. The Commission will not require Kinder Morgan
to remove these costs from negotiated rates for service on the Colorado
Lateral because these rates were freely negotiated (Kinder Morgan
Interstate Gas Transmission LLC, 124
FERC ¶61,024 (ip
access users))
Unsafe Gas Leakage Stalls LNG Expansion
Project
As part of a Federal Energy
Regulatory Commission (FERC) order approving a project expanding the liquefied
natural gas (LNG) capacity of an LNG terminal, FERC's conclusion that
unblended LNG would not have caused leaks in a local natural gas distribution
company's distribution system if a subset of the system's compression
couplings had not been damaged by hot tar applied to the couplings during
their installation decades earlier was supported by substantial evidence,
the U.S. Court of Appeals for the District of Columbia Circuit held. The
distribution company, Washington Gas Light Company (WGL), argued that
the expansion project would be inconsistent with the public-interest requirements
of the Natural Gas Act (NGA) because the influx of unblended LNG would
cause severe leakage throughout its distribution system. The court found,
however, that the facts were consistent with FERC's finding that WGL's
couplings were so damaged by the hot tar that its distribution system
became susceptible to the confluence of multiple leak-inducing factors,
such as LNG and cold weather. Nonetheless, the court granted WGL's petition
for review, vacated FERC's orders to the extent that they approved the
expansion project, and remanded the case to FERC because FERC failed to
ensure that the project could go forward consistent with the NGA’s
public interest requirement by concluding that WGL could address safety
concerns before the project's November 2008 in-service date without the
support of substantial evidence. (Washington Gas Light Co. v. FERC
(DCCir), CCH Utilities Law Reporter ¶14,703)
Electric Utilities
Entergy Violated Tariff by Canceling
Transmission Service Agreements
The termination of two firm
point-to-point transmission service agreements between ConocoPhillips
Company (ConocoPhillips) and Entergy Services, Inc. (Entergy) was a violation
of Entergy’s Open Access Transmission Tariff (OATT) the Commission
ruled. ConocoPhillips requested and received a total of 103 megawatts
(MW) of short-term firm point-to-point transmission service on Entergy’s
system. A month later, Entergy’s Independent Coordinator of Transmission
(ICT) learned that Entergy had oversold service at the Entergy-Ameren
interface because it miscalculated the Available Flowgate Capability (AFC)
due to a software error. The ICT resolved the oversell by recalling (i.e.,
terminating) transmission in reverse queue order, thereby terminating
ConocoPhillips firm service. ConocoPhillips then filed a complaint with
the Commission. The Commission found that the termination of ConocoPhillips’
transactions was not consistent with Entergy’s OATT. Absent a specific
provision addressing software errors, the provision addressing the curtailment
of firm transmission service was the appropriate OATT provision to which
Entergy and the ICT should have looked for addressing the constraint.
Relieving the system constraints through termination of reservations in
the reverse order that the requests were accepted did not comply with
this provision, and placed the burden of relieving the constraint on ConocoPhillips
and the other last-in-queue firm-service customers. This unduly discriminated
between customers even though they were similarly situated, each having
confirmed service, and as such, action was unsupported by Entergy’s
OATT, the Commission reasoned. NRG Power Marketing, LLC (NRG Companies)
requested that the Commission’s determination also apply to them.
The Commission concluded that it would be inappropriate for them to address
NRG Companies request, because NRG Companies were effectively asking to
be joined in the complaint and that would be improper. (ConocoPhillips
Co. v. Entergy Services, Inc., 124
FERC ¶61,085 (ip
access users))
Blanket Authorizations for Mergers/Acquisitions
Affirmed
FERC’s recent decision
to establish additional blanket authorizations for certain dispositions
of jurisdictional facilities under the Federal Power Act’s (FPA)
merger and acquisition provisions to facilitate investment in the electric
industry [Order No 708, CCH FERC Statutes and Regulations
¶31,265
(ip
access users)], has been largely affirmed by the agency. The new rule
(Order No. 708-A) affirms the earlier decision’s finding that the
transfer of a wholesale power contract which does not provide for the
transfer of control of generation or transmission cannot affect horizontal
or vertical market power because the parties which sought rehearing on
the issue raised no new arguments to the contrary. It also affirms Order
No. 708’s decision to grant blanket authorization for hedging transactions—those
that employ an approach to risk management that uses financial instruments
to manage identified risk. Blanket authorization involving hedging for
holding companies is in the public interest because such authorization
would not give the acquiring entity additional market power or enable
it to undermine competition or place its captive customers at a disadvantage.
Finally, FERC clarifies that blanket authorization applies to transactions
involving the transfer of assets from one non-traditional utility subsidiary
(i.e., a public utility that does not have captive customers and does
not own or control transmission facilities) to another non-traditional
utility subsidiary when only one of the two non-traditional utility subsidiaries
survives the transaction. The Commission found that this type of transaction
is consistent with the public interest and does not entail subsidization
issues. (CCH FERC Statutes and Regulations ¶31,273
(ip
access users))
New Cross-Subsidization Safeguards Clarified
A number of FERC’s cross-subsidization
restrictions on affiliate transactions [Order No 707, CCH FERC
Statutes and Regulations ¶31,264
(ip
access users)], have been clarified on rehearing by the agency. These
restrictions encompass transactions between franchised public utilities
that have captive customers or that own or provide transmission service
over jurisdictional transmission facilities and their market-regulated
power sales affiliates or non-utility affiliates. The rule expanded the
transactions and entities to which these restrictions apply in order to
protect against inappropriate cross-subsidization of market-regulated
and unregulated activities by the captive customers of public utilities.
In Order No. 707-A, the Commission decided to permit affiliates within
a single-state holding company system that does not have a centralized
service company to provide at cost to other affiliates in the system the
kinds of services typically provided by centralized service companies
and the goods to support those services. This permission does not apply
to inputs to utility operations such as fuel supply, construction or real
estate that have a clearly identifiable market price, nor does it apply
to the implementation of major projects that are easily susceptible to
competitive bidding, such as construction projects. With regard to multi-state
holding companies that do not have centralized service companies, the
Commission will consider requests for waiver on a case-by-case basis for
at-cost pricing in the multi-state context under the same circumstances
as for single-state holding companies (i.e., only for general and administrative
services and goods to support those services and only where members of
the holding company do not sell such goods outside the holding company.)
This will allow the Commission to examine each situation to ensure that
adequate regulatory oversight and protections are in place. (FERC
Statutes and Regulations ¶31,272)
Alternative Energy
Alternative Energy Program for OCS
Proposed by MMS
Regulations that would establish
a program to grant leases, easements, and rights-of-way (ROW) for alternative
energy project activities on the Outer Continental Shelf (OCS) have been
proposed by the Minerals Management Service (MMS). The regulations would
also address the alternate use of existing OCS facilities, as well as
establish a method for sharing revenues with the coastal states. MMS expects
that wind, wave, and ocean currents will be the primary focus of OCS projects
in the short term, although it expects solar, hydrogen, and other projects
in the future. MMS is proposing two types of alternative energy leases:
a commercial lease of up to 25 years for full-scale commercial energy
production, and a limited lease of up to 5 years for site assessment,
technology testing, and other activities that do not include commercial
operations. Leases, ROW grants, and Alternative Use Right of Use and Easement
Grants (RUE) are required by the Energy Policy Act of 2005 to be awarded
competitively. A cash bonus bidding system would be used as the basis
for determining the winner. MMS has proposed a rental fee of $3 to $5
per acre, which is lower than that normally used for oil and gas projects.
(CCH Energy Management ¶9320)